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State of the Art In Gas Treating

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  • pg 1
									State-of-the-Art
       In
 Gas Treating

           Mahin Rameshni, P.E.
          Chief Process Engineer



             WorleyParsons
        125 West Huntington Drive
            Arcadia, CA, USA

           Phone: 626-294-3549
             Fax: 626-294-3311
 E-Mail: mahin.rameshni@worleyparsons.com




           British Sulphur 2000
         San Francisco, CA – USA
             November 2000
                    Table of Contents


                                                                                                                                            Page
                  Abstract .......................................................................................................................iv

Section 1         Introduction                                                                                                               1-1


Section 2         Selection Criteria for Acid Gas Removal
            2.1   Natural Gas Processing............................................................................................2-1
            2.2   Petroleum Refining ...................................................................................................2-2
            2.3   Synthesis Gas Treatment.........................................................................................2-2
            2.4   Data Base Outline.....................................................................................................2-3

Section 3         Raw Gas Preconditioning Process & Final Conditioning Process
            3.1   Elemental Sulfur Removal........................................................................................3-1
                  3.1.1 Inline Separator / Filtration System................................................................3-1
                  3.1.2 Disposal Solvent Injection ..............................................................................3-2
                  3.1.3 Slug Catchers .................................................................................................3-4
                  3.1.4 Gravity-Based Scrubber.................................................................................3-4
            3.2   Heavy Hydrocarbon Removal ..................................................................................3-4
            3.3   BTEX Emissions .......................................................................................................3-5
                  3.3.1 Integration with Membranes...........................................................................3-7
                  3.3.2 Integration with Molecular Sieves ..................................................................3-7
            3.4   COS/CS2 Removal ...................................................................................................3-8
            3.5   Effect of NH3..............................................................................................................3-9
            3.6   Dehydration Process ................................................................................................3-9

Section 4         Amine Unit Configurations
            4.1   Liquid Treating ........................................................................................................... 4-2




                                                       i
                    Table of Contents

Section 5          Solvents
             5.1   Selective H2S Removal..............................................................................................5-1
             5.2   Bulk CO2 Removal .....................................................................................................5-2
             5.3   Physical Solvent Process ..........................................................................................5-3
             5.4   Equilibrium Behavior of Solvents...............................................................................5-5
             5.5   Software........................................................................................................................... 5
             5.6   Typical Product Specifications...................................................................................5-8

Section 6          Dealing with Corrosion and Foaming in Amine Unit
             6.1   Tendency to Foam at High Concentration ................................................................6-1
             6.2   Corrosion in Amine Unit.............................................................................................6-1

Section 7          Impact of Feed Gas Composition on SRU Efficiency
             7.1   Revamp Options ........................................................................................................7-2

Section 8          WorleyParsons Sulfur Recovery & Criteria Selection for Tail Gas Treating
                   System
             8.1   Selection Criteria for Tail Gas Treating Processes...................................................8-2
             8.2   H2S Conversion/Removal Technologies...................................................................8-3
             8.3   BSR/MDEA Technology ............................................................................................8-5
             8.4   Tail Gas Treating with Flexsorb SE Solvents ...........................................................8-5
             8.5   Sub-Dewpoint Claus ..................................................................................................8-6
             8.6   BSR/Selectox & BSR/Hi-Activity Technologies ........................................................8.7


Section 9          WorleyParsons PROClaus Process                                                                                             9-1


Section 10         Conclusion                                                                                                               10-1


Section 11         References                                                                                                               11-1




                                                        ii
        Table of Contents


                                                                                                                         Page
       Figures
  1    Basic Gas Treating & Sulfur Recovery Facilities ......................................................1-1
  2    Typical Acid Gas Removal Diagram .........................................................................4-3
  3    Typical Physical Solvent Configuration .....................................................................5-7
  4    H2S Content VS. SRU Recovery...............................................................................7-2
5A     Comparison of Different Tail Gas Processes ...........................................................8-3
5B     Comparison of PROClaus with Sub-Dew Point Process .........................................8-7
  6    BSR/Selectox Process .......................................................................................8-9
  7    BSR/Hi-Activity Process...................................................................................8-10
  8    PROClaus Process ............................................................................................9-3

       Tables
   I   Acid Gas Sources ......................................................................................................2-1
  II   Data Base Outline ......................................................................................................2-3
 III   Main Available Processes..........................................................................................5-4
 IV    Solvent Capabilities....................................................................................................5-4
  V    Typical Product Specifications...................................................................................5-8
 VI    Comparison of Tail Gas Cleanup Processes............................................................8-4
VII    Tail Gas Cleanup Process.........................................................................................8-4
VIII   WorleyParsons BSR/Tail Gas Processes.................................................................9-2




                                          iii
  Abstract

Gas Treating in gas industries, and in oil and chemical facilities is getting more
complex due to emissions requirements established by environmental regulatory
agencies. In addition, increasing demand of using new wells with complex compo-
nents and new sources of sour gases is encouraging gas specialists to look for-
ward to the new technologies, new solvents, and new ways to find solutions. In re-
sponse to this trend, gas preconditioning upstream, or final step(s) for gas condi-
tioning downstream of the gas-treating unit, are emerging as the best options to
comply with the most stringent regulations. The final steps of gas conditioning are
a combination of different processes to remove impurities such as elemental sul-
fur, solids, heavy hydrocarbons, and mercaptans that current commercial solvents
are not able to handle. In cases where there is no sulfur recovery / tail gas unit in-
stalled downstream of the gas plant to destroy the remaining impurities, meeting
the product specification is very crucial. Solvents could be contaminated with un-
desired elements, causing plugging, foaming, corrosion, or changing the required
product specification. Over the years, many papers have been presented due to
the gas preparation required prior to any gas treating system. There is no indica-
tion, however, of any unique process that is able to handle all of the impurities.

In cases where sulfur recovery and tail gas units are installed downstream of the
gas plant, gas preconditioning may not be required and most of the impurities will
be destroyed in the sulfur recovery unit. However, with the increasing sulfur con-
tent in crude oil and natural gas and the tightening regulations of sulfur content in
fuels, refiners and gas processors are being pushed to obtain additional sulfur re-
covery capacity. At the same time, environmental regulatory agencies in many
countries continue to promulgate more stringent standards for sulfur emissions
from oil, gas, and chemical processing facilities. It is necessary to develop and im-
plement reliable and cost effective technologies to cope with the changing re-
quirements. In response to this trend, several new Claus tail gas technologies are
emerging to comply with the most stringent regulations.

Typical sulfur recovery efficiencies for Claus plants are 90-96% for a two- stage
plant, and 95-98% for a three- stage plant. Most countries require sulfur recovery
efficiency in the range of 98.5% to 99.9% or higher. Therefore, the sulfur constitu-
ents in the Claus tail gas need to be reduced further.

The key parameters affecting the selection of the gas-treating and tail-gas cleanup
process are:

    Selection of gas preconditioning process upstream or final gas conditioning
    downstream of the gas treating unit based on nature of impurities

    Gas pressure and temperature




                         iv
  Abstract

    Feed gas composition, including H2S content, CO2 and hydrocarbons, and
    other contaminants

    Process configuration

    Selection of the dehydration process

    Product specification, such as H2S, CO2, H2O, hydrocarbons, and mercaptans

    Optimization of the existing equipment

    Required recovery efficiency

    Concentration of sulfur species in the stack gas

    Ease of operation

    Remote location

    Sulfur product quality

    Costs (capital and operating)

In response to the above trends, selection of the right tools is very crucial. Those
tools could be a “right” technology, a “right” solvent, a “right” simulator, and a
proper economic design with low- energy consumption to reduce operating and
capital costs.

Generic and specialty solvents are being divided into three different categories to
achieve sales gas specifications: 1) chemical solvents 2) physical solvents 3) and
physical-chemical (hybrid) solvents. In other words, regular gas units could be
identified as amine units for H2S removal, dehydration process, turbo expander for
deep chilling, and caustic treatment for removing sulfur compounds from liquid
product. Or they could be specified as solvents for H2S Selectivity, solvents for
CO2 Removal, and solvents for organic Sulfur Removal.

Final selection is ultimately based on process economics, reliability, versatility, and
environmental constrains. Clearly, the selection procedure is not a trivial matter
and any tool that provides a reliable mechanism for process design is highly desir-
able. Acid gas removal is the removal of H2S and CO2 from gas streams by using
absorption technology and chemical solvents.

This paper emphasizes on the selection criteria for gas preconditioning and the fi-
nal steps of gas conditioning processes for industry needs.




                          v
  Abstract

The various gas-treating process technologies with commercialized chemical,
physical, and hybrid solvents to meet the various environmental regulations are
presented. This paper also demonstrates how these processes are chosen based
on the selection criteria mentioned above.

The various Claus tail gas-treating technologies developed and commercialized to
meet the various environmental regulations are presented. Depending on the proc-
ess route selected, an overall sulfur recovery efficiency of 98.5% to 99.9% or
higher is achievable. The latter recovery corresponds to less than 250 parts per
million by volume (ppmv) of SO2 in the offgas going to the thermal oxidizer prior to
its’ venting to the atmosphere.




                         vi
Section 1                    Introduction

                          As the results of the new revolutions in challenging the various solvents and differ-
                          ent process configurations, gas processing in gas industries and refineries has be-
                          come more complex. In response to this trend and to comply with the product
                          specifications, more equipment and more process upstream or downstream of gas
                          processing should be implemented.

                          The selection criteria for gas processing is not limited to the selection of gas treat-
                          ing configurations by itself; it is expanded to the selection criteria of more side
                          process / down streams configurations, to complete the gas processing in order to
                          meet the product specification and to satisfy environmental regulatory agency re-
                          quirements.

                          For instance, if the H2S concentration of gas to the sulfur recovery unit is low, the
                          acid gas enrichment unit is recommended. Acid gas from the gas-treating unit
                          flows through the acid gas enrichment unit where the H2S has substantially sepa-
                          rated from the CO2 and N2. The stream that is enriched in H2S is fed to the sulfur
                          recovery unit while the desulfurized CO2 and N2 stream is sent to the thermal in-
                          cinerator.

                          Figure 1 represents the basic gas treating and sulfur recovery facilities. Acid gas
                          and liquid sweetening will be followed by the other process that is shown in figure
                          1. Liquid sweetening will be discussed in the following sections.




            Acid Gas and Liquid             Enrichment                   Sulfur                    Tail Gas
                Sweetening                   Facilities                 Recovery                   Treating




                           Sour Water                              Sulfur Degassing,
                                                                                                  Incinerator
                            Stripping                            Solidification & Storage




                                        Figure 1- Basic Gas Treating & Sulfur Recovery Facilities




                                                     1-1
Section 2      Selection Criteria for Acid Gas Removal

            Acid gas removal is the removal of H2S and CO2 from gas streams by using ab-
            sorption technology and chemical solvents. Sour gas contains H2S, CO2, H2O, hy-
            drocarbons, COS/CS2, solids, mercaptans, NH3, BTEX, and all other unusual im-
            purities that require additional steps for their removal.

            There are many treating processes available. However, no single process is ideal
            for all applications. The initial selection of a particular process may be based on
            feed parameters such as composition, pressure, temperature, and the nature of
            the impurities, as well as product specifications. The second selection of a particu-
            lar process may be based on acid/sour gas percent in the feed, whether all CO2,
            all H2S, or mixed and in what proportion, if CO2 is significant, whether selective
            process is preferred for the SRU/TGU feed, and reduction of amine unit regenera-
            tion duty. The final selection could be based on content of C3+ in the feed gas and
            the size of the unit (small unit reduces advantage of special solvent and may favor
            conventional amine).

            Final selection is ultimately based on process economics, reliability, versatility, and
            environmental constraints. Clearly, the selection procedure is not a trivial matter
            and any tool that provides a reliable mechanism for process design is highly desir-
            able.

            The variety of the acid gas sources that have different gas compositions, pressure,
            temperature, and nature of impurities and might require different means of gas
            processing to meet the product specification, are presented in table I.

                                             Table I- Acid Gas Sources

                     Natural Gas Processing                         LNG Facilities

             Petroleum Refining                          Synthesis Gas Treating

             Chemicals and Petrochemicals                Coal & Heavy Oil Gasification

             LPG Systems                                 Pipeline Dew Point Control

             Landfill Gas Facilities                     Feed to Tail Gas Treating

             Ammonia & Hydrogen Plants


            Selection of the right tools is very crucial. Establishing and conducting all the ele-
            ments together at the same time, would generate such a beautiful art in gas treat-
            ing.




                                       2-1
Section 2              Selection Criteria for Acid Gas Removal


2.1   Natural Gas Processing

                     Natural gas is one of the common sources of gas treating, with a wide range in
                     CO2/H2S ratios and high pressure treating. If natural gas is not an LNG application,
                     it could be treated with selective H2S removal if significant CO2 is present. If C3+ is
                     present, the desirability of using physical or mixed solvents is reduced. If organic
                     sulfur is present, the desirability of using physical or mixed solvents is increased.

                     It is favored to use proprietary solvents if natural gas has significant CO2 and /or
                     H2S for large units/ and to use conventional solvents for small units particularly
                     with modest acid /sour gas levels.


2.2   Petroleum Refining

                     Petroleum refining is another source of gas treating with low CO2 content, unless
                     the refinery has catalyst cracking unit, in which case the gas may contain COS,
                     organic sulfur, cyanides, ammonia, and organic acids. The acid gas from hy-
                     drotreating and hydrocracking essentially contains H2S and ammonia. The gas
                     treating pressures and H2S specifications vary for individual applications, and
                     MEA/DEA/MDEA or formulated amines are the typical solvents. The refinery typi-
                     cally has multiple absorbers and a common regenerator as listed below:

                           Fuel gas treating

                           Hydrotreater product/fuel gas

                           Hydrotreater recycle gas

                           Hydrocracker product/fuel gas

                           Hydrocracker recycle gas

                           LPG liq-liq contactor

                           Thermal/catalyst cracker gases

                           Services independent or combined as practical




                                               2-2
Section 2                 Selection Criteria for Acid Gas Removal


2.3   Synthesis Gas Treatment

                     Synthesis gas treatment is characterized by high CO2 and low (or no) H2S. If the
                     amount of CO2 is limited, it is preferred to use selective H2S treating via formu-
                     lated/hindered amine, mixed solvent, or physical solvent. If H2S is not present and
                     there is modest or essentially complete CO2 removal, it is preferred to use acti-
                     vated MDEA, hot potassium, mixed amine, and physical solvent.


2.4   Data Base Outline

                     In order to select the optimized process, gas-treating units are divided into several
                     categories and each one requires different solvents, simulator, or available tech-
                     nology. However, each project is required to be evaluated with more than one
                     technology in order to meet the project specification, circulation rate, and duties,
                     which is truly dependent on the gas composition (such as H2S, CO2 and NH3). In
                     addition, the selected process must be evaluated to make sure it is economic.

                     Table II represents the most common process being used in gas plant industries.

                                                   Table II- Data Base Outline

                            HP Gas Treating System, Bulk CO2 Removal from Natural Gas, and
                                                     Selective H2S Removal
                      Physical Solvent Process (SELEXOL, Murphreesorb, IFPEXOL)
                      Other Solvent Process (DEA, MDEA, DGA, aMDEA, Sulfinol M/D, Flexsorb,
                      Gas/SPEC *SS, Membrane + amine, UCARSOL, Chevron-IPN, Benfield, K2CO3)
                          Tail Gas Treating (H2S Recycle & Selective Cat. Oxidation Process
                      Typical Solvent (MDEA, HS-101/103, Gas/Spec *SS, Sulfinol, Flexsorb)
                      BSR /Amine Process          Shell SCOT/ ARCO                  WorleyParsons
                                                                                    BOC Recycle
                      Resulf                      Dual-Solve                        BSR / Wet Oxi-
                                                                                    dation
                      MCRC                        CBA                               Sulfreen
                      BSR /Selectox               BSR/Hi-Activity/PROClaus          Super Claus
                                                  Incinerator Tail Gas

                      Wellman-Lord                    Clintox                            Elsorb
                      Claus Master                    Cansolv                            Bio-Claus
                      Clausorb




                                             2-3
Section 2    Selection Criteria for Acid Gas Removal

                                          Acid Gas Enrichment
            Typical Solvent (MDEA, Sulfinol M/D, FLEXSORB, UCARSOL, Gas/SPEC
            *SS)
                                            Ammonia Plants

            Physical Solvents, aMDEA, Hot Potassium, Dow 800 series, etc.
                                          Cryogenic Systems
            Chemical Solvents
                                   Enhanced Oil Recovery (EOR)

            Chemical & physical Solvents
                                     EOR CO2 Recovery Plants

            Similar to Bulk CO2 Removal
                                            Ethylene Plants

            Similar to Bulk CO2 Removal
                                 Flash Regeneration CO2 Removal

            Similar to Bulk CO2 Removal
                                            Hydrogen Plants
            Chemicals Solvents
                                             LPG Treating
            Chemical Solvents
                                          Oil Refinery Systems
            Chemical & Physical Solvents
                                       Dehydration systems

            EG, DEG, TEG, Solvents, Methanol, Molecular Sieve Process, etc.




                                 2-4
Section 3              Raw Gas Preconditioning Process & Final Conditioning Process

                     Unusual impurities are on the increase by demand of exploring new sources of the
                     sour gas.

                     Following are some the unusual impurities that may require additional removal
                     steps in gas -treating. Feed gas compositions should be evaluated for needs of
                     gas preparation prior entering to any gas plant. Contaminated gas will damage the
                     solvent and cause plugging, pipeline cleaning of liquids and solids, corrosion,
                     foaming, and changing product specifications. This paper addresses different Raw
                     Gas Preconditioning and Final Conditioning processes.

                         Elemental Sulfur

                         Heavy Hydrocarbons (CnHm) & BTEX, such as Benzene & C8+

                         COS, CS2, RSH, Mercaptans, Hg

                         Solids, Carbon


3.1   Elemental Sulfur Removal

                     Several studies have being performed regarding the elemental sulfur removal in
                     gas plant industries.

                     Elemental sulfur causes the “series” problem within the gas plant such as plugging
                     of exchangers, crystal forming and contaminating the solvent, and changing the
                     product specifications.

                     GPSA Engineering Data Book and the Perry and Chilton Chemical Engineering
                     Handbook, show that the gravity-based scrubbers are not effective for particles
                     smaller than approximately 1 micron, whereas filtration is effective for particles as
                     small as 0.01 micron.

                     Sulfur is one of the elements that have a tendency to bond extensively to itself and
                     chains in a similar fashion to carbon, and produces S8. Chains can break and re-
                     act with other molecules such as H2S or produce solid sulfur that is suspended in
                     the water.

                     Sulfur has the potential to act as a fairly strong oxidizing agent and causes corro-
                     sion in stainless steel equipment.

                     3.1.1 Inline Separator / Filtration System

                     All gas-sweetening units should have a well-designed inlet separator. Inline sepa-
                     rator has been used as a filtration system to remove the particles and to remove


                                              3-1
Section 3      Raw Gas Preconditioning Process & Final Conditioning Process

            any entrained solids. The inline separator should be designed not only on the ba-
            sis of inlet fluid volumes but also on surge capacity to handle slugs of liquid hydro-
            carbons, H2O, and well-treated chemicals. In cases where solids or liquids are
            known or anticipated to be a problem, a high-efficiency separator such as a coa-
            lescing filter separator should be used.

            The second stage of filtration should be performed by using the carbon filter for
            removing particles down to 5 microns. The activated carbon filter should always be
            located downstream because the deposition of solids would plug the carbon filter
            and prevent its regeneration.

            If the gas is contaminated with the large amount of the elemental sulfur, even more
            steps should be taken before entering the gas into the inline separator. Otherwise,
            inline separator will plug.

            The latest filtration system is the implementation of designing the special media for
            the elemental sulfur removal. This filter can facilitate the separation of the sulfur in
            conjunction with simultaneous liquid aerosol removal. The liquid quantity would be
            available for assisting the separator, i.e. whether or not additional water injection
            ahead of the filter would be necessary. This could be done by simply adding a wa-
            ter injection upstream of the inlet nozzle. Due to the hazardous (lethal) nature of
            the gas, it would be advisable to have the ability to steam or nitrogen-purge a unit
            that would need to be serviced. Basically, the installation of this filter provides the
            ability to simultaneously water-wash the gas while providing for sub-micron ele-
            mental sulfur removal. The filter media allows small liquid droplets to coalesce by
            impingement. As larger droplets grow, they become sufficiently heavy to drain
            through the glass fibers. To prevent plugging of the glass fibers, a pleated paper of
            prefilter could be used.

            3.1.2 Disposal Solvent Injection

            DAD’s and DMDS are well known as the disposal solvents that could be injected to
            the well to absorb the elemental sulfur. The rich fluid, which contains elemental
            sulfur, is disposed and the solvent will not be regenerated.

            Sulfur Scrubbing by Using Chemical Solvent

            The elemental sulfur removal is achievable by using absorption oil as a sulfur sol-
            vent in sour gas wells to control sulfur deposition. This solvent is based on a mix-
            ture of alkylnaphthalenes diluted in a mineral oil; both can physically combine with
            the precipitated sulfur. The solvent will be regenerated and its behavior in corro-
            sion inhibitors is outlined. This solvent, with an oil-soluble inhibitor having proper
            phase behavior, can effectively control corrosion in sour gas wells with high reser-
            voir water production.



                                      3-2
Section 3     Raw Gas Preconditioning Process & Final Conditioning Process

            Application of a solvent in sour gas wells should satisfy the following important
            characteristics:

                No corrosion with the well fluid

                Sufficient sulfur solubility

                No irreversible reactions with precipitated sulfur

                Stability under conditions

                Low vapor pressure

                Corrosion prevention

                Ability to separate from water

                Suitable uniform quality

                Suitable viscosity

                Ability to be regenerated and recirculated

                Simple recovery of the absorbent sulfur

            The liquid is injected at the wellheads and travels by gravity through the annulus.
            The solvent mixes with the upcoming gas and formation water and is reproduced
            by the well fluid. The annulus cross-section narrows around the couplings of the
            tubing connectors. At high injection rates, the annulus becomes partially filled up,
            forming a liquid column and creating slugs that travel through the tubing.

            The produced liquid phases are separated at the surface by 3 three-stage systems
            consisting of a free-water knockout drum, a separator, and the scrubber of the gly-
            col dehydrator. The formation-water/solvent mixture is collected in tanks at each
            well site.

            The temperature decrease shifts the sulfur solubility of the gas to lower values.
            Depending on the particular super-saturation of the gas, sulfur precipitation could
            take place in the cooler. To prevent plugging of the cooler tubes, a small volume of
            solvent is injected downstream of the free-water knockout drum, the sulfur loading
            capacity is about 30 g/L.




                                       3-3
Section 3             Raw Gas Preconditioning Process & Final Conditioning Process

                    3.1.3 Slug Catchers

                    If the elemental sulfur content in the feed gas is very high, slug catchers are highly
                    recommended to remove the elemental sulfur. Slug catchers should be designed
                    with enough capacity to remove all the particles.

                    3.1.4 Gravity-Based Scrubber

                    The elemental sulfur could be removed by using the gravity-based scrubber with a
                    separation flash drum or settling storage tank that should be sized with sufficient
                    residence time.


3.2   Heavy Hydrocarbon Removal

                    During phasing-in of new wells, feed gas is enriched with heavy hydrocarbons and
                    oil. Hydrocarbon liquids are known to cause foaming in amine systems. It has
                    been found that hydrocarbon liquid may reside in the piping; however, the liquid
                    flow regime must be evaluated.

                    Then, the first option is to drain these hydrocarbons from pipelines. This liquid
                    could be drained from a pipe by installing dip legs at different locations such as at
                    the end of header, and between the final two branches.

                    The purpose of carbon filtration removal of hydrocarbon molecules and chemical
                    contaminants, which promote amine foaming, is to remove hydrocarbons prior to
                    the amine unit.

                    Selective solvents have a capability of removing trace sulfur compounds, but hy-
                    drocarbon losses with the acid gas are high.

                    Hydrocarbons have a higher solubility in physical solvent than in water; therefore,
                    a higher physical solvent concentration should result in an increase in hydrocarbon
                    content in the acid gas. There are other options could be used for hydrocarbon
                    removal, such as:

                        Using physical solvent for gas treating if applicable.

                        Draining the heavy hydrocarbons from pipelines prior to gas plant.

                        Providing a Water Wash Scrubber (with a separation flash drum with sufficient
                        residence time, the dissolved hydrocarbon can gravity-separate from the bulk
                        solution) and using baffles & weirs.




                                             3-4
Section 3                Raw Gas Preconditioning Process & Final Conditioning Process

                            Providing a gas carbon filter upstream of multi-cyclone separator and coalesc-
                           ing filter.

                           Providing skimming facilities such as skimming pots for flash drums with suffi-
                           cient residence time.

                           Using mole-sieve bed downstream of the gas treating (mole-sieves could be
                           designed with multi-beds for the dehydration, aromatic removal, and Hg re-
                           moval, etc. in one package).

                           Adding one or two fractionation columns within gas treating for the removal of
                           the remaining hydrocarbons, and to recover the C2-C4 and blend it back to the
                           treated gas to maintain the required heating value.

                           If the amine-based solvent is applicable, some hydrocarbon removal could be
                           achieved by minimizing the lean amine, running stripper with lower pressure,
                           and using low circulation rate.

                           If the sulfur recovery unit is located downstream of the gas plant, the heavy
                           hydrocarbons and BTEX could be destroyed by designing a suitable burner to
                           achieve 2,200 °F minimum. If the acid gas feeding to the sulfur recovery unit
                           has the low percent of H2S (Lean Gas), oxygen enrichment is recommended.

                       If the gas has retrograde properties close to its hydrocarbon dew points, it is of
                       particular importance to minimize pressure losses. Drums could be equipped with
                       proper hydrocarbon condensate withdrawal, such as skimming pots.


3.3   BTEX Emissions

                       An amine unit operates by contacting an amine solution with the sour gas or liquid
                       feed counter-currently in an absorber column. H2S and CO2 in the feed are ab-
                       sorbed by the amine in the solution, and the sweetened gas exits the top of the
                       column. Rich amine exits the bottom of the column and is sent through the regen-
                       eration system to remove the acid gases and dissolved hydrocarbons, including
                       BTEX. The lean solution is then circulated to the top of the absorber to continue
                       the cycle. The sweetened gas exiting the absorber is saturated by water from its
                       contact with the amine. The overheads, including BTEX from the amine regenera-
                       tor column, are sent to a sulfur recovery unit.

                       The aromatic compounds including benzene, Toluene, Ethylbenzene, and Xylene
                       (collectively known as BTEX), are included as hazardous factors in air pollutants.

                       If the raw gas contains appreciable amounts of H2S, a sulfur plant is used to treat
                       the overheads from the rich amine stripper. This treating normally destroys any


                                                3-5
Section 3     Raw Gas Preconditioning Process & Final Conditioning Process

            BTEX or other hydrocarbons. Several operating parameters directly affect the
            amount of BTEX absorbed in an amine unit, such as inlet BTEX composition, con-
            tactor operating pressure, amine circulation rate, solvent type, and lean solvent
            temperature.

            MDEA absorbs the lowest amount of BTEX compared to DEA and MEA; therefore,
            it is recommended to use MDEA where BTEX is observed in the sour gas, (if it is
            applicable).

            Several operating parameters directly affect the amount of BTEX absorbed in an
            amine unit. These factors include the inlet BTEX composition, contactor operating
            pressure, amine circulation rate, solvent type, and lean solvent temperature. Fol-
            lowing is a list of strategies that should be followed to limit the BTEX emissions
            from gas plant:

                Minimize the lean amine temperature. The amount of BTEX emissions in
                amine systems decreases with an increase in lean solvent temperature.

                Use the best solvent for treating requirements. (i.e. MDEA absorbs the lowest
                amount of BTEX).

                Minimize the lean circulation rate. BTEX pick up increases almost linearly with
                an increase in circulation rate.

                If the stripper pressure is higher, the overall BTEX emissions are lower.


            Sulfur has the potential to act as a fairly strong oxidizing agent and cause corro-
            sion in stainless steel equipment.

            H2S is very soluble in molten sulfur; so then H2S would be expected from typical
            solubility’s of gases into liquids. Sulfur reacts with hydrocarbons to form mercap-
            tans, which are present in sour gas. The high solubility of sulfur in CS2 has been
            recognized. Other solvents are oily disulfides, amines, alkanolamines, and aro-
            matic hydrocarbons. Amines and alkanolamines compounds are extensively used
            in German sour-production schemes and depend on the following reaction for tak-
            ing up sulfur.

                    RNH2 +     H2S         RNH3 +      HS9

            Technology has been patented for loop systems using this approach.

            Sulfur should be managed and it is reasonable to predict that a suitable chemical
            base might prevent sulfur deposition. Acid-base reactions are rapid compared to




                                     3-6
Section 3                Raw Gas Preconditioning Process & Final Conditioning Process

                    decomposition reactions and could act to capture the sulfanes as ionic polysulfides
                    before decomposition occurs.

                    If water is contaminated with bicarbonate, that water becomes corrosive. This is a
                    suggestion here that indicates aqueous sodium bicarbonate should be injected
                    into the bottom of the wellbore to control sulfur deposition until production matures
                    and the formation water takes over.

                    If the gas containing high levels of sulfur, say more than 10 tons per day is to be
                    removed, then a regenerable H2S adsorption / desorption process, such as a
                    Claus process for the conversion of the removed H2S into elemental sulfur, is nor-
                    mally favored.

                    If less than a few hundred pounds/day of sulfur needs to be removed, fixed beds of
                    chemical absorbents will remove H2S to any level required. The used catalysts and
                    absorbents can be sold to the metal recovery industry, and there are no disposal
                    problems.

                    3.3.1 Integration with Membranes

                    Membranes are now being used widely for the purification of natural gas contain-
                    ing high levels of CO2. For instance, it has developed a membrane-based process
                    to separate and recover hydrocarbons, including propylene and ethylene, from ni-
                    trogen and light gases. Unfortunately, the membranes available presently lack se-
                    lectivity, and it is not possible to precisely control the rate of diffusion of the various
                    components present across the membrane. Therefore, it is rare for the stripped
                    gas to meet the sales gas specification.

                    3.3.2 Integration with Molecular Sieves

                    Molecular sieves are used extensively to dry natural gas. In this role, they will also
                    remove H2S but because water is significantly more powerfully bonded than H2S,
                    they are not very effective for the combined H2S/H2O removal duty.

                    The new technology is using the molecular sieves as a multi-bed combination,
                    each for a specific duty. This combination could be a dehydration bed, in addition
                    to a removal bed for heavy hydrocarbon(s), Hg, or any other impurities that could
                    be effectively selected for removal technology. These beds should be cost effec-
                    tively designed.


3.4   COS /CS2 Removal

                    Some of the chemical and physical solvents are capable of removing COS / CS2 at
                    some level; however, the solvent may not be able to meet the product specifica-


                                               3-7
Section 3     Raw Gas Preconditioning Process & Final Conditioning Process

            tion. In that case, using another conditioning process is feasible. The molecular
            sieves process could be used for COS / CS2. The amine reclaimer system is an al-
            ternative for COS / CS2. Reclaimer operation is a semi-continuos batch operation
            for removal of degradation product from the solution and removal of suspended
            solids and impurities. Reclaimer operates on a side stream of 1-3 percent of total
            solvent circulation rate. If a physical solvent is being used for the acid gas removal,
            COS / CS2 could be improved by increasing the fresh solvent circulation rate since
            the semi-solvent is already saturated and providing an additional chiller system
            would increase the absorption process.

            Any gas treating, including natural gas and refinery offgas, are contaminated with
            mercaptan and COS.

            Any gas-treating unit operates by contacting a solvent solution with the sour gas or
            liquid feed counter-currently in an absorber column. H2S and CO2 in the feed are
            absorbed by the solvent in the solution, and the sweetened gas exits the top of the
            column. Rich solvent exits the bottom of the column and is sent through the re-
            generation system to remove the acid gases, dissolved hydrocarbons, and COS.
            Several operating parameters directly affect the amount of COS absorbed in a gas
            treating unit, such as inlet COS composition, contactor operating pressure, solvent
            circulation rate, solvent type, and lean solvent temperature. The chosen solvent
            should be capable of absorbing COS in the absorption process and release the
            COS to the acid gas in the regenerator. The acid gas from the regenerator is sent
            to the sulfur recovery unit to decompose any sulfur compounds, including COS.

            Pure physical solvent is particularly effective in a high-pressure system, high-acid
            gas treatment for removing H2S, CO2, COS, organic sulfur species, and a wide
            range of other gas stream contaminates. Usually, two absorbers are designed with
            physical solvents, one absorber for H2S removal with semi-lean physical solvent
            and another absorber for CO2 and COS removal with lean, pure solvents. If more
            absorption of COS is required, additional free-COS, free-lean solvent should be
            fed to the H2S absorber, or semi-lean physical solvent has to be cooled prior feed-
            ing the H2S absorber.

            The purpose of the amine reclaiming units is to distill the water and amine from the
            fouled solution leaving behind the entrained solids, dissolved salts, and degrada-
            tion products that cause foaming and corrosion problems.




            The reclaimer is an integral part of a successful amine sweetening process. It
            normally operates on a side stream of the lean amine solution leaving the bottom
            of the stripper column. The temperature of the reclaimer is to be controlled
            through the cycle. The presence of COS, CS2, FeSO2, free oxygen, and other con-



                                      3-8
Section 3               Raw Gas Preconditioning Process & Final Conditioning Process

                      taminants can poison the amine. In such cases, a reclaimer is often used to re-
                      generate the degraded amine. Amine degradation depends on different factors. All
                      of the feed to the reclaimer is assumed to go overhead except the degraded
                      amine. A flash calculation would be essentially impossible since the composition
                      and properties of the degraded amine vary widely and are never accurately deter-
                      mined. The reclaimer has only one inlet stream that comes from the reboiler, and
                      two outlet streams (the reclaimer OVHD and the reclaimer dump). The reclaimer
                      operating temperature is in a range of 300-350 ° F and, usually, 1-5 percent of the
                      lean amine would be fed to the reclaimer.


3.5   Effect of NH3

                      When small amounts of ammonia are present in the sour gas, nearly all of the
                      ammonia should be scrubbed from the sour gas by the amine solution. Due to the
                      high solubility of ammonia in water, the ammonia may build up in the circulating
                      rich-amine solution and present several problems in the absorber and stripper.
                      Some of the operational problems with ammonia are meeting the project specifica-
                      tion, flood in the stripper, inability to hold the pressure control set points on the
                      condenser or reboiler.

                      These problems all have the same root cause. Ammonia is absorbed at the pres-
                      sure and temperature in the absorber, rich amine is loaded with ammonia fed to
                      the stripper, and the K value for ammonia in the condenser is considerably less
                      than one. Therefore, most of the ammonia is vaporized in the stripper, and is re-
                      turned in the reflux. This process continues to build up until steady-state ammonia
                      either overcomes the low K value in the condenser or forces its way to the reboiler
                      against high K value in the tower.


3.6   Dehydration Process

                      Gas hydrates are crystalline compounds composed of water and natural gas in the
                      pipelines. The conditions that tend to promote hydrate formation include the follow-
                      ing: low temperature, high pressure, and a gas at, or below, its water dew point
                      with free water present. The formation of hydrates can be prevented by using any
                      of the following methods:

                          Adjusting the temperature and pressure until hydrate formation is not favored.

                          Dehydrating a gas stream to prevent a free water phase.

                          Inhibiting hydrate formation in the free water phase.




                                               3-9
Section 3     Raw Gas Preconditioning Process & Final Conditioning Process

            EG, DEG, and TEG are the most widely used solvents for bulk removal of water
            from natural gas. Methods of calculations are the K-chart method and Hammer
            Schmidt’s Equation, which are both presented in GPSA, 1994, and computer simu-
            lation.

            Use of amines in aqueous solutions saturates the sweet gas with water vapor, re-
            gardless of whether the entering sour gas is wet or dry.

            For some amine processes, this means that a dehydration step necessarily follows
            sweetening. One process, which overcomes this shortcoming, is the use of MDEA
            or DEA in combination with ethylene or diethylene-glycol.

            The combination of amine and glycol will usually do an excellent job in removing
            acid gas constituents, but generally does not dehydrate as well as a conventional
            glycol installation.

            Using other technologies, capable of water removal, could be EG injection, metha-
            nol-protected cold processes, hydrate- formation temperature predications, and
            Cold Finger Drizo. Finally, the molecular sieve process is an alternative for the de-
            hydration process in addition to removal of other impurities.




                                     3-10
Section 4     Amine Unit Configurations

            The most common amine design configuration includes one single absorber, one
            single regenerator, and all related equipment such as pumps, filters, and heat ex-
            changers. Sometimes other configurations required to be considered to be able to
            design the gas treating units, in addition to being able to meet the project require-
            ment. Other considerations are listed below as a reference:

                One single absorber, and one single regenerator
                One single absorber, and several flash stages
                Absorber A in series with absorber B, and single regenerator
                Absorber A/B in parallel with a common regenerator
                Split –flow configuration using absorber A, B, or A/B
                Absorber A/B with two lean amine feeds
                Absorber A/ B and regenerator with side heaters / coolers
                Single –Stage Co-current static mixing element
                Absorber A/B with amine pump-around
                One single absorber, one single regenerator, with amine and Semi-amine split
                flow
                H2S & CO2 Absorbers, one single Regenerator, with amine and Semi-amine
                split flow
                Molecular sieve process
                Membrane process

            Figure 2 represents the typical amine unit configuration. Some of the above con-
            figurations are not common processes; therefore, a brief description follows:

            Absorber with pump-around may be used when a gas stream containing, for ex-
            ample nine mole percent of CO2. In order to reduce the total circulation of the sol-
            vent, an internal recycle or pump-around circuit is used with a heat exchanger to
            cool the stream. The process enables recovery of 89% of CO2 in the feed gas.

            Split- flow may be used to provide a significant reduction in the amount of stripping
            steam needed. Lean and semi-lean solvent enters the absorber to sweeten the
            gas. The partially stripped semi-lean solvent stream is drawn off the third tray of
            the regenerator.

            Molecular sieve process may be used for selectivity of H2S removal in the pres-
            ence of CO2.

            In this process, the gas passes through one of two to four fixed beds of molecular
            sieves, where the H2S along with H2O and organic sulfur compounds are removed
            from the gas by a process similar to adsorption. When the bed becomes saturated
            with H2S, the main gas flow is switched to another bed, which is freshly regener-
            ated. Twenty percent of the sweet gas is heated to 600 -700 °F, and passed
            through the fouled bed to regenerate it. The hot regeneration gas is then cooled


                                     4-1
Section 4                 Amine Unit Configurations

                        and processed by an amine unit to remove H2S from the regeneration gas. The
                        regeneration gas is sweetened; it rejoins the main gas stream downstream of the
                        sieve beds.


4.1   Liquid Treating

                        Liquid treating is another amine unit for sweetening hydrocarbon liquids by using
                        DEA, MDEA, or MEA solvent.

                        The acid condensate-sweetening unit removes H2S and CO2 from the acid con-
                        densate feed by liquid-liquid contacting the sour condensate with lean solvent such
                        as DEA.

                        The sour condensate flows through the acid condensate coalesce filter where par-
                        ticulate matter is removed and entrained water is coalesced and separated. The
                        acid condensate then flows to the acid condensate contactors where CO2 and H2S
                        are absorbed by the lean DEA solution.

                        The contactors are liquid-liquid contactors containing 2 or 3 packed sections. The
                        treated condensate from the acid condensate contactor is washed using a recircu-
                        lating water wash. The treated condensate and the wash water are mixed in the
                        water-wash static mixer. The mixer is then coalesced into two liquid phases and
                        separated in the water-wash separator.

                        Makeup water is continuously added to the circulating water-wash circuit to control
                        the buildup of DEA in the wash water and to help maintain the water content of the
                        DEA system. Water is also continuously withdrawn from the water-wash circuit
                        and mixed with the rich DEA solution.

                        In this process, liquid hydrocarbon enters the bottom of a packed absorber and
                        lean amine enters the top of the absorber. Sweet liquid leaves the absorber from
                        the top and rich amine leaves the absorber from the bottom. The most common
                        liquid–liquid absorbers are packed contactors, jet educator-mixers, and static mix-
                        ers. However, other processes such as Merox, Molecular Sieve, KOH, and Iron
                        Sponge could do the liquid treating process.




                                                 4-2
                                                                            Section 4
                                                                TO ACID
                                                              GAS FLARE

                                                               ACID GAS
                                                                TO SRU

                                                                PURGE
                                                                WATER



                              CW
      SWEET
      PRODUCT GAS



      SOUR
      GAS
                                                       MAKE-UP
                                                       CONDENSATE


      SOUR OIL /




4-3
      WATER                                M
                                   AMINE
                                   DRAIN
                                                               STM
                                                                          Amine Unit Configurations




                MAKE-UP
             CONDENSATE

                                                       COND




                          Figure 2, Typical Acid Gas
                              Removal Diagram
Section 5            Solvents

                   Generic and specialty solvents are divided to three different categories to achieve
                   sales gas specification; however, these solvents may be called chemical solvents,
                   physical solvents, and physical-chemical (hybrid) solvents. On the other hand,
                   regular amine units are divided into an amine unit for H2S removal, molecular sieve
                   dehydration, turbo expander for deep chilling, and caustic treating for removing
                   sulfur compounds from liquid product, or finally, are divided to:

                       Solvents for H2S selectivity

                       Solvents for CO2 removal

                       Solvents for organic sulfur removal

                   The primary differences in process by using generic amines are in solution con-
                   centrations. MEA is ordinarily used in a 10 to 20 percent by weight in the aqueous
                   solution. DEA is also used in the 10 to 30 percent by weight in the aqueous solu-
                   tion. DIPA, DGA, and MDEA are used in higher concentrations. Typical concentra-
                   tion ranges for DIPA and MDEA are 30 to 50 percent by weight in the aqueous so-
                   lution. DGA concentrations range from approximately 40 to 70 percent by weight.


5.1 Selective H2S Removal

                   The absorption of H2S and the selectivity of H2S over CO2 are enhanced at a lower
                   operating temperature; consequently, it is desirable to minimize the lean amine
                   temperature.

                   To achieve low H2S slippage in the absorber operating at high pressure, it is nec-
                   essary to strip the amine to a very-low H2S loading (typical loading is < 0.01 mole-
                   acid gas/mole amine). Steam stripping occurs in the regenerator at high tempera-
                   ture and reverses the reactions given above. The steam reduces the partial pres-
                   sure of H2S and CO2 over the amine, thus reducing the equilibrium concentration
                   (or loading) of these components in the amine.

                   For highly selective H2S removal, solvents by The DOW Chemical Co. (Gas Spec),
                   Union Carbide (Ucarsol), BASF (aMDEA), EXXON (Flexsorb), and others have
                   been developed that exhibit greater selectivity and H2S removal to lower treated
                   gas specifications. However, these solvents are MDEA-based solvents. These sol-
                   vents have other applications; such as H2S removal from CO2 enhanced oil recov-
                   ery (ROR) enrichment processes.

                   Solvents for H2S selectivity are used for refinery systems with high CO2 slip, tail
                   gas treating, natural gas treating, H2S removal from liquid hydrocarbon streams,
                   natural gas scrubbing, and refinery systems with LPG streams containing olefins.



                                            5-1
Section 5                Solvents

5.2   Bulk CO2 Removal

                     Solvents for CO2 removal are used for natural gas treaters, landfill gas facilities
                     with high CO2 feed, ammonia and hydrogen plants, and natural gas or LNG facili-
                     ties with downstream cryogenic facilities. MDEA solvent and mixtures of amines
                     can be used for bulk CO2 removal. However, this performance is very sensitive to
                     one or more of the operating parameters, such as liquid residence time on the
                     trays, circulation rate, and lean amine temperature.

                     MDEA has a number of properties, which make it desirable for applications such
                     as:

                         High solution concentration up to 50 to 55 wt %
                         High-acid gas loading
                         Low corrosion
                         Slow degradation
                         Lower heats of reaction
                         Low- vapor pressure and solution losses

                     Amine solvents and physical solvents are used over a wide variety of process con-
                     ditions, ranging from atmosphere pressure for refinery off-gas and Claus tail gas
                     treating, to high pressure for natural gas sweetening.

                     Amine solution in water is very effective at absorbing and holding H2S and CO2
                     from weak acids, when dissolved in water. The weak acids react with the amine
                     base to help hold them in the solution. Therefore, a chemical solvent (such as
                     amine) is used for these components.

                     The Hot Potassium Carbonate Process has been utilized successfully for bulk CO2
                     removal from a number of gas mixtures. It has been used for sweetening natural
                     gases containing both CO2 and H2S. If gas mixture containing little or no CO2, po-
                     tassium bisulfide is very difficult to regenerate, and it is not suitable.


5.3   Physical Solvent Process

                     Physical solvents for organic sulfur removal are used to remove sulfur compounds
                     such as carbonyl sulfide, carbon disulfide, dimethyl disulfide, methyl mercaptan,
                     ethyl mercaptan, and C3- mercaptan. The feed to the gas treating units are from
                     natural gas and refinery offgas, landfill gas recovery, ammonia production, coal
                     and heavy- oil gasification, syngas treating, and pipeline dew point control. The
                     physical solvent has low volatility, low to moderate viscosity, high boiling points,
                     and excellent chemical and thermal stability.



                                              5-2
Section 5     Solvents

            Acid gas (such as H2S, CO2, CH3SH, CS2, and SO2) is more soluble in these sol-
            vents than CH4, C2H6, Co, H2, N2, and O2. Heavier hydrocarbons and water are
            also soluble in these solvents. The selectivity of physical solvents to the acid
            gases over the hydrocarbons is best achieved by control of solvent polyglyme dis-
            tribution, water content, and operating conditions. Physical solubility of compo-
            nents in physical solvent is related to the ratio of the number of solute molecules
            and the number of solvent weight, which decreases the number of molecules per
            unit mass. Consequently, capacity for the solute is reduced. Another interesting in-
            teraction is the SO2 polyglyme relationship. SO2 is highly soluble in these solvents
            by an order of magnitude greater than H2S. The interaction is reversible with a
            heat solution of approximately 35 KJ/mol, or roughly twice that of H2S.

            Sometimes, gas contaminants (like mercaptans and trace sulfur compounds) do
            not form acids in water and are relatively unaffected by amine solutions.

            To remove these contaminants, we resort to simple absorption in a fluid using a
            physical solvent. Water has a small amount of absorption or solubility for mercap-
            tans, but not enough to be effective in meeting the light specifications. Therefore,
            solvents that are classified as a “hybrid” solvent are designed to merge the effects
            of chemical and physical solvent technologies. This solvent is usually about 20-
            30%wt water, 40-60% amine, and 10-40% physical solvent.

            Figure 3 represents the typical physical solvent configuration. The configuration
            should be optimized based on the acid gas composition. Table III represents the
            main processes available in gas industries.




                                     5-3
Section 5     Solvents

                                    Table III- Main Available Processes

              Physio-Chemical              Physical      MIXED SOLVENTS          Miscellaneous

             Conventional             Selexol            LE-701                 Solids Beds
             Amines

             Proprietary Amines       Methanol           Sulfinol M/D           Chemical
                                                                                Adsorption

             Activated                Murphree           Exxon Range            Physical
                                      sorb                                      Adsorption

             Formulated               K2CO3

             Hindered Amines                                                    Chemical

             Hot Carbonate                                                      Redox

                                             800                                Slurries


            Table IV represents the solvent capabilities4.


                                      Table IV- Solvent Capabilities

                Solvent           Meets             Removes         Selective         Solution
                                  ppmv,             Mercap.           H2S           Degraded by
                                   H2S             COS, Sulfur      Removal

             MEA              Yes             Partial             No               Yes
                                                                                   (COS,CO2,
                                                                                   CS2)

             DEA              Yes             Partial             No               Some (COS,
                                                                                   CO2,
                                                                                   CS2)

             DGA              Yes             Partial             No               Yes
                                                                                   (COS,CO2,
                                                                                   CS2)

             MDEA             Yes             Partial             Yes (1)          No

             Sulfinol         Yes             Yes                 Yes (1)          Some
                                                                                   (CO2,CS2)

             Selexol          Yes             Yes                 Yes (1)          No



                                     5-4
Section 5               Solvents

                          Solvent          Meets           Removes            Selective         Solution
                                           ppmv,           Mercap.              H2S           Degraded by
                                            H2S           COS, Sulfur         Removal

                       Hot              Yes (2)        No (3)               No               No
                       Potassium
                       Benfield

                       Iron Sponge      Yes            Partial              Yes

                       Mol Sieve        Yes            Yes                  Yes (1)

                       Strefford        Yes            No                   Yes              Yes (CO2 at
                                                                                             high
                                                                                             Conc.)

                       Lo-cat           Yes            No                   Yes              Yes (CO2 at
                                                                                             high
                                                                                             Conc.)
                      (1) These processes exhibit some selectivity.
                      (2) Hi-Pure version.
                      (3) Hydrolysis COS only.

5.4   Equilibrium Behavior of Solvents

                      The design of chemi-sorption processes requires a clear understanding of the
                      equilibrium between the solvent and the dissolved gas. In general, the solvent
                      consists of an active component, such as an alkanolamine, together with diluents,
                      physical sorption promoters, and corrosion inhibitors. Because of the presence of
                      these additional components, the solubility of the dissolved gas is usually given in
                      moles-of-solute per mole-of-active sorbent known as solvent loading.

                      At constant solute partial pressure, the solubility of the dissolved gas varies with
                      the liquid concentration of the active component. Flash calculation for H2S and
                      MDEA shows that the more concentrated MDEA solution exerts a higher partial
                      pressure at the same solvent loading.

                      To achieve a specified outlet concentration of the absorbed component in the ab-
                      sorber, it is necessary that the stripped solvent leaving the regenerator must con-
                      tain a concentration of solute less than that which would be in equilibrium with the
                      gas leaving the absorber at the conditions at the top of the absorber column.

                      It is known, H2S reacts with aqueous solutions of certain amines at a faster rate
                      than CO2.



                                                5-5
Section 5      Solvents

            In order to account for this selectivity, it is necessary to incorporate tray efficiency
            into equilibrium state models for these units. The stage efficiency is a function of
            the kinetic rate constants for the reactions between each acid gas and the amine,
            the physio-chemical properties of the amine solution, the pressure, temperature
            and the mechanical tray design variables, such as tray diameter, weir height, and
            weir length. The Murphree Efficiency Equation is known as the most common ap-
            proach to design the amine units as well as the equilibrium solubility and phase
            enthalpy.

            Vapor-phase enthalpy is calculated by the Pen-Robinson Equation of State, which
            integrates ideal gas-heat capacity data from a reference temperature liquid-phase
            enthalpy, and also includes the effect of latent heat of vaporization and heat of re-
            action.

            The absorption or adsorption of H2S and CO2 in amine solutions involves a heat
            effect due to the chemical reaction. This heat effect is a function of amine type and
            concentration and the mole loading of acid gases. The heat of solution of acid
            gases is usually obtained by differentiating the experimental solubility data using a
            form of the Gibbs-Helmholtz Equation. The heat effect results from evaporation
            and condensation of amine and water in both the absorber and regenerator of liq-
            uid enthalpy. Water content of the sour water gas feed can have a dramatic effect
            on the predicted temperature profile in the absorber and should be considered es-
            pecially at low pressures.




                                      5-6
                                                            SALES
                                                             GAS
                                                                                                                       Section 5
                                                       CO2 ABS.




                                                                                     TO VENT


                                                                                               CHILLER /
                    H2S ABS.                                                                   REFRIGER
                                                                                                 ATOR
                                                                                                                       Solvents




                                                          NO. 1 CO2
                                                          RECYCLE                                          AG TO SRU
                                                           FLASH
                                                           DRUM
                                                                      NO. 2 CO2
                                                                      RECYCLE
                                                                       FLASH
      FEED                                 CHILLER /                   DRUM
      GAS




5-7
                                           REFRIGER
                                             ATOR
                                                                                  VENT
                                                                                   GAS
               FILTER                                                             FLASH
             SEPARATOR                                                            DRUM


                                   H2S RECyl
                                    DRUM




                                                                                                                LPS

                                                    L/R
                                                 EXCHANGER

                                                                                                                LPC




                               Figure 3, Typical Physical Solvent Configuration
Section 5               Solvents

5.5   Software


                      The commercial simulation software provided by Hysim/ Hysis, D.B. Robinson,
                      and Tsweet, is widely used in the gas processing industry. All three programs use
                      thermodynamic models that Kent and Eisenberg develop it. However, each one
                      has been fitted using proprietary data as well. Therefore, the result of each simula-
                      tor might be different for the same case. All listed commercial programs claims that
                      are able to handle any type of generic amine design, but sometimes will not have
                      the same results or even it is not possible to use them as a suitable tool to solve
                      the entire problem. Therefore, it is wise to use engineering judgment and to design
                      a gas plant, to meet all gas treating design aspects.


5.6   Typical Product Specifications

                      Table V represents the typical product specifications for refining, gas processing,
                      and tail gas-treating plants.

                                           Table V- Typical Product Specifications

                      Refining                      Gas Processing           Tail Gas Treating

                      Fuel gas treating : 50 to     CO2 LNG Plant: 50        H2S USA: 10 ppmv
                      100 ppmv                      ppmv

                      LPG: copper strip             CO2 General: 2% vol      H2S General: 150 to 200
                                                                             ppmv
                                                    H2S : 1 to 4 ppmv




                                                  5-8
Section 6               Dealing with Corrosion and Foaming in Amine Unit


6.1   Tendency to Foam at High Concentration

                     If foaming occurs, it is often caused by some alien compound being introduced into
                     the system, such as a corrosion inhibitor being injected at the wellhead. Other root
                     causes could be pipeline liquids and solids entering the amine system through an
                     ineffective, raw-gas preconditioning system, contaminants in the circulation amine,
                     or dissolved amine degradation products and additives in the system.

                     Operational problems with amines, including excessive losses, foaming, corrosion,
                     hydrogen cracking and blistering, are symptoms of poor performance, which can
                     be traced to the accumulation of amine heat-stable salts. The ion exchange-based
                     process removes both the heat stable salts anions and any metalcations from any
                     amine system.

                     Foaming in an amine sweetening process can result in a number of different prob-
                     lems, (e.g. reduced plant gas, decreased efficiency, specifications cannot be met,
                     and amine losses).

                     Foaming could be caused from suspended solids, condensed hydrocarbons,
                     amine degradation products, and overheating of amine or any foreign material
                     such as makeup water, corrosion inhibitor, etc.

                     Silicon-based, and a few other types of antifoam agents, have been found to work
                     reasonably well in many cases. Antifoams are surface-active molecules that
                     change the surface tension of liquid to reduce foaming. In addition, the solution
                     should be kept clean by using adequate mechanical and carbon filtration, carbon
                     should be changed when it is spent, heat stable salts should be prevented from
                     building up, and proper metallurgy should be selected.


6.2   Corrosion in Amine Unit

                     Corrosion in amine units (especially in DEA units) needs very special attention for
                     the repair of existing equipment as well as inspection of the entire unit with the fol-
                     lowing procedures:


                         Initial inspection of repaired equipment
                         Re-inspection of undamaged equipment
                         Equipment and piping requiring examination
                         Examination and procedures and methods
                         Wet-fluorescent magnetic-particle testing
                         Dry magnetic-particle testing


                                              6-1
Section 6     Dealing with Corrosion and Foaming in Amine Unit

                Shear-wave ultrasonic testing
                Visual testing
                Visual testing
                Surface preparation

            For amine units, PWHT is recommended for all carbon steel equipment, including
            piping, exposed to amine at service temperature of 180 ° F and higher. Not only
            the maximum operating temperature but also effect of heat tracing and steam-out
            on the metal temperature of components in contact with the amine should be con-
            sidered.

            Industry experience has shown that many reported instances of ASCC in DEA
            units have occurred in non-PWHT carbon steel equipment exposed to tempera-
            tures higher than 180 0F. However, some cracking problems have been reported in
            DEA units at temperatures below this value.

            In some cases, equipment including piping has been known to crack during steam-
            out, owing to the presence of amine. Each user company should evaluate the
            need for PWHT at temperatures below 180 ° F in equipment such as absorbers
            and contactors.

            MEA degrades to form acidic and basic products.

            Acidic degradation forms multi-acids and eventually reacts with bases to form
            heat-stable salts, which are removed by carbon filtration; however, acids cause
            corrosion. To reduce or prevent corrosion, remember to consider the following
            items:

                Keep contaminants out of unit
                Use filtration, wash feed
                Select adequate metallurgy
                Avoid buildup to heat-stable salts
                Design to limit reboiler tube temperatures
                Limit flow velocities
                Avoid air ingress




                                    6-2
Section 7     Impact of Feed Gas Composition on SRU Efficiency

            The acid gas composition leaving the acid gas removal has an impact on sulfur re-
            covery efficiency.

            If the H2S concentration of gas to the sulfur recovery unit is low, the acid gas en-
            richment unit is recommended. H2S, hydrocarbons, and ammonia content would
            establish the criteria for sulfur recovery designs and efficiency and to overcome
            the remaining impurities that heritage from acid gas processing. The conventional
            sulfur plant could be converted to the oxygen enrichment to process more sour
            gas and to destroy the impurities require the higher temperature for destruction at
            the same time. If the solvent in the existing gas plant has been changed in order to
            process more acid gas, the downstream units such as the SRU/TGU need some
            equipment modifications for capacity expansion. In general commercially available
            technologies offer three levels of oxygen enrichment: low-level (up to 28%), me-
            dium-level (up to 45%), and high-level (up to 100%) providing additional capacity
            of about 25%, 75%, and 150% respectively. All of the existing major equipment
            can be reused for low-level oxygen enrichment. For medium-level oxygen enrich-
            ment a specially designed burner such as WorleyParsons/BOC's SURE direct
            oxygen injection burner is needed. High-level oxygen enrichment requires the im-
            plementation of technology such as WorleyParsons/BOC's Double Combustion
            SURE process. The process involves the addition of a new reaction furnace
            burner, reaction furnace, and waste heat boiler upstream of the existing equip-
            ment. The solvent in the tail gas unit could also be converted to a more selective
            solvent, in order to be capable of processing more acid gas. The process involves
            the addition of a new quench circulation pump; quench water cooler, and an amine
            cooler, to increase the cooling duty. Otherwise, all of the existing major equipment
            can be reused.

            Using oxygen enrichment with the proper burner design for ammonia and BTEX
            destruction would allow the burner to operate with the higher temperature and
            would destroy the undesired elements. It might be required to convert the catalyst
            to TiO2 to destroy the impurities such as COS/CS2.

            The design criteria for sulfur recovery units could be the following:

                Higher air/oxygen demand
                Dilution effect on Claus equilibrium
                Dilution effect on vapor loss
                COS/CS2 loss (TiO2 & BSR)

            The emission level is pending on the selection criteria of the sulfur recovery de-
            signs and the tail gas treating in terms of the oxygen enrichment level and the se-
            lection of the special solvent, respectively, to achieve SO2, CO, NOX, and H2S (10
            ppmv max) to the acceptable level.




                                     7-1
Section 7                Impact of Feed Gas Composition on SRU Efficiency

                       The operating cost and sulfur product quality is ultimately based on the following
                       items:

                              Chemical consumption amine vs. liquid Redox
                              Catalyst requirement (TiO2 & others)
                              Byproducts (water & steam)
                              Contaminants (liquid Redox, bio processes)
                              Access to means of disposal (agricultural use & blend-away in a large pool)

                       Figure 4 represents the sulfur recovery efficiency based on dry H2S content.

                       The dry H2S content could be calculated prior to design of the sulfur recovery
                       units.


                                        98


                                        96
                          Recovery, %




                                        94


                                        92


                                        90
                                             0   10     20      30     40   50    60      70   80   90   100
                                                                     H2S Content, % dry


                                                      Figure 4 – H2S Content VS. SRU Recovery


7.1   Revamp Options

                       The acid gas processes, sulfur recovery units, and the tail gas units could be
                       evaluated in terms of reconfigurations, and economic impact to meet the new re-
                       quirements and increase the capacity as follows:

                              Transition from generic to proprietary solvents in acid gas removal
                              Transition from air to oxygen in sulfur recovery units, to increase the capacity
                              and destroy NH3, BTEX, and heavy hydrocarbons
                              Reconfigure catalyst in the reactors
                              Transition from generic to proprietary solvents in tail gas units
                              Increase the amine concentration to process more feed gas
                              Evaluation of the existing equipment


                                                          7-2
Section 7   Impact of Feed Gas Composition on SRU Efficiency

            Evaluation of the existing plot plan for any addition of the new equipment
            Converting from Strefford Process to amine process




                                7-3
Section 8      Sulfur Recovery & Criteria Selection for Tail Gas Treating System


            Various aspects and considerations when choosing the most optimum process
            configuration for tail gas treating are discussed. There are several key features af-
            fecting the selection of the tail gas cleanup process; that three steps should be
            taken. When the required recovery efficiency and concentration of sulfur species in
            the stack gas is known, selection of the tail gas process is one step closer. The
            first step is one of the most important criteria for the selection of the tail gas treat-
            ing processes. When the required sulfur recovery is established, the selection of
            the tail gas process will be limited. Tables 6&7 represent the various tail gas
            cleanup processes with the recovery that will be achieved. When concentration of
            impurities in the acid gas, such as COS and CS2, H2S content, feed gas composi-
            tion, and treated gas specifications are established, the type of amine used for a
            particular application could be selected in step two. Finally, the third step is the
            evaluation between the identical process chosen for ease of operation, capital and
            operating cost, and remote location. For revamp units, minimum equipment modi-
            fications and process configurations should be considered as main key factors.

             The hydrogenation/hydrolysis step employs WorleyParsons’ patented technology
            known as the Beavon sulfur removal (BSR) process. This process will be used
            when 99.9% or higher sulfur recovery is required. WorleyParsons acquired the ex-
            clusive rights to a series of innovative catalysts developed for two tail gas-treating
            processes.

            The LBNL catalyst has demonstrated high efficiency and selectivity in converting
            SO2 contained in the typical 1st Claus catalyst converter as well as the 2nd Claus
            catalyst converter tail gas to elemental sulfur. These catalysts are to be used in
            WorleyParsons newly offered technology, PROClaus process and are capable of
            enhancing the sulfur recovery of a conventional Claus SRU to 99.5%. The LBN
            catalyst also converts a substantial fraction of the H2S in the tail gas to sulfur.

            The second catalysts are to be used in WorleyParsons-offered technology, Hi-
            Activity Process, and are capable of enhancing the sulfur recovery of a conven-
            tional Claus SRU to 99.0%. In this process, the conventional Claus catalyst in the
            third sulfur converter is replaced with WorleyParsons' Hi-Activity catalyst. Different
            from the conventional Claus catalyst, WorleyParsons' Hi-Activity catalyst selec-
            tively promotes the reaction of H2S with oxygen to form elemental sulfur directly.
            With an enhanced, sulfur recovery efficiency of 98.5 to 99.0%, this may be suffi-
            cient in satisfying sulfur emissions regulations in certain areas and no further tail
            gas treating would be required.

            WorleyParsons' BSR/Selectox tail gas treating system has repeatedly demon-
            strated (commercially) its capability of achieving up to 99.0% overall sulfur recov-
            ery. This system represents a process of much simpler configuration than that of
            the BSR/MDEA system. In the event that 99.0% overall sulfur recovery efficiency is
            sufficient to satisfy the local sulfur emissions regulations, this system does offer


                                     8-1
Section 8                Sulfur Recovery & Criteria Selection for Tail Gas Treating System


                      significant capital cost and operating cost savings compared to the BSR/MDEA
                      system.

                      Figure 5 shows a block flow diagram of typical sulfur recovery systems employing
                      various WorleyParsons proprietary technologies. These systems consist of a
                      Claus SRU and a BSR followed by the options of Selectox, Hi-Activity, and MDEA
                      tail gas treating units to attain overall sulfur recovery efficiencies of up to 99%,
                      99.5% and 99.9+% respectively. The tail gas treating unit is followed by thermal
                      oxidation to convert all residual H2S and other oxidizable sulfur compounds to sul-
                      fur dioxide prior to venting to atmosphere via a stack. For the MDEA tail gas-
                      treating route, it is possible in some cases to reduce the H2S concentration to a
                      sufficiently low level to permit venting the offgas without thermal oxidation.


8.1   Selection Criteria for Tail Gas Treating Processes

                      Tail gas treating follows the sulfur recovery unit for converting most of the remain-
                      ing sulfur compounds in the Claus tail gas to H2S. The most commonly used tail
                      gas cleanup processes can be divided into three categories:

                          Tail gas hydrogenation, followed by either selective amine coupled with acid
                          gas recycle such as BSR/MDEA, BSR/Flexsorb, SCOT, and HCR, or selective
                          catalyst oxidation such as PROClaus, BSR/Selectox, and BSR/Hi-Activity.

                          Sub-dew point Claus, such as, WorleyParsons ER Claus, CBA, MCRC, and
                          Sulfreen

                          Direct Oxidation of H2S to Elemental Sulfur, such as SuperClaus

                      Other Claus tail gas treating options, such as incinerator tail gas processes (i.e.
                      ClausMaster, Cansolv) are marketed recently.

                      This section presents the selection criteria for tail-gas process configuration sali-
                      ent-design features; including safety design features, sulfur recovery efficiency,
                      and comparison of capital and operating costs of these technologies.




                                               8-2
 Section 8                               Sulfur Recovery & Criteria Selection for Tail Gas Treating System



8.2     H2S Conversion/Removal Technologies

                                       The second major step of the Claus tail gas-treating unit involves the following
                                       candidate technologies. Tables VI&VII present the comparison of tail gas cleanup
                                       processes.

                                       Figure 5A below represents the different tail gas cleanup configurations.


                                                                                                                   H2S/SO2
                                                                                                             AC
Modified Claus                                     95 %               97 %
  Thermal
                       Converter # 1                  Converter # 2                   Converter # 3
   Stage
                          Claus                          Claus                           Claus




                                                                H2S/SO2
                                                             AC
Hydrogenation
                                                                                                                        99.9 %
  Thermal          Converter # 1          Converter # 2               Converter # 3                Water                  Amine
   Stage              Claus                  Claus                       Claus                    Removal



                                                                                                           Air
                                                                                                                             99.0%
                                                                                                                            Converter # 4
                                                                                                                              Selectox

                                                                               Air

                                                                                                                               99.5 %
                                                                                                                           Converter # 4 Hi-
                                                                                                                              Activity




                                                                               H2S
Direct Oxidation                                                A98.8 %                               AC
                                                                                                             99.3 %
  Thermal          Converter #1           Converter # 2                       Converter # 3
   Stage              Claus                  Claus                           Selective Oxi-                       Converter #4 Selective
                                                                             dation or Claus                           Oxidation




                                                             Air                                 Air

                                   Figure 5A, Comparison of Different Tail Gas Processes


                                                                      8-3
Section 8    Sulfur Recovery & Criteria Selection for Tail Gas Treating System


                       Table VI- Comparison of Tail Gas Cleanup Processes

                  Process         No. of Converters         Sulfur Recovery,   Relative
                                                                    %           Cost

            Modified Claus                  3                    97.0           1.00

            PROClaus                        4                    99.5           1.20

            Sub-Dewpoint                    3                    99.0           1.20

            Sub-Dewpoint                    4                    99.5           1.40

            Direct Oxidation                3                    98.8           1.15

            Direct Oxidation                4                    99.3           1.30

            BSR/Selectox                    4                  98.5-99.0        1.45

            BSR/Hi-Activity                 4                    99.5           1.35

            BSR/Amine or                 3 + amine               99.9           1.70
            SCOT


                        Table VII- Tail Gas Cleanup Process

            Process            Capital          Operating       Efficiency,
                                Cost              Cost               %

            BSR/Flexsorb         5                   5            99.99

            BSR/MDEA             6                   5            99.99

            HCR                  6                   5            99.99

            Thiopaq              4                   4            99.99

            Clauspol             3                   4           99.5/99.9

            PROClaus             2                   2            99.50

            BSR/Hi-Activity      3                   3             99.3

            BSR/Selectox         4                   3             99.0

            ER Claus             1                   1             99.0




                                 8-4
Section 8               Sulfur Recovery & Criteria Selection for Tail Gas Treating System



8.3   BSR/MDEA Technology

                      The BSR/amine tail-gas treating technology offered by WorleyParsons is capable
                      of using various types of amine solvents available in the market to date. The most
                      common ones are generic MDEA, UCARSOL HS-101, and UCARSOL HS-103 of-
                      fered by Union Carbide, DIPA offered by Shell, Flexsorb SE offered by Exxon, and
                      TG10 offered by DOW. With the use of these solvents, an overall sulfur recovery
                      of 99.9% and 99.99+% can be achieved respectively. As a result, the treated tail
                      gas has a much lower H2S level, 150 ppmv for HS-101 and 10 ppmv for HS-103.
                      Due to the lower affinity for CO2 of the MDEA-based solvents, CO2 slippage is
                      much higher than comparing to that from the DIPA solvent. This will result in a
                      smaller recycle gas stream to the front-end Claus unit and will account for lower
                      pressure drop or higher sulfur-processing capacity. The fact that the MDEA-based
                      solvents can be operated at high concentrations (50-wt% versus 26-50 wt% used
                      for DIPA) without running the risk of increased corrosion to the absorber, the re-
                      generator, and their associated equipment. Smaller towers could be used and thus
                      reduce the equipment size and capital costs substantially.


8.4   Tail Gas Treating with Flexsorb SE Solvents

                      With the trend towards the processing of more sour crude and natural gas, cou-
                      pled with tighter restrictions on sulfur emissions, the growth in the use of selective
                      amines is set to continue. Flexsorb SE and Flexsorb SE Plus are aqueous amine
                      solvents based on novel hindered amines that were patented by Exxon with
                      WorleyParsons’ partnership. Flexsorb SE solvents formulations are optimized for
                      specific applications such as:

                          Selective H2S removal both grassroots and retrofits

                          High H2S cleanup

                          COS and mercaptan removal

                      Flexsorb solvents use conventional equipment similar to the other generic amine
                      processes; their high capacity for H2S absorption leads to:

                          Smaller grassroots units; about 30-50 percent lower circulation rate

                          Investment savings

                          Debottleneck of existing units for higher capacity, especially increasing SRU
                          capacity by using oxygen enrichment



                                               8-5
Section 8                                            Sulfur Recovery & Criteria Selection for Tail Gas Treating System


                                                       Reduce H2S to 5-10 ppmv in treated product

                                                 Flexsorb solvents offer other advantages compared to other amine solvents. For
                                                 instance, most of the applications require no reclaiming, have good operating ex-
                                                 perience, low corrosion, and low foaming due to low hydrocarbon absorption, and
                                                 by providing water wash of treated gas at low pressure system, amine losses are
                                                 minimum. Flexsorb solvents employ selective H2S removal applications for tail gas
                                                 treating, natural gas treating, LNG sweetening, and acid gas enrichment units.


8.5         Sub-Dewpoint Claus

                                                 Another method employs sub-dewpoint Claus operation. As opposed to the con-
                                                 ventional Claus catalytic converters where the produced sulfur remains in the va-
                                                 por phase, the sub-dewpoint Claus operates the Claus converters at below sulfur
                                                 dewpoint temperatures. As it is well understood that the Claus equilibrium conver-
                                                 sion of H2S conversion to sulfur increases with decreasing temperatures in the
                                                 catalytic operation region. In this operation, produced sulfur is condensed and ad-
                                                 sorbed on the catalyst, and subsequently routine bed switching and regeneration
                                                 is required. A 3-stage sub-dewpoint scheme can achieve about 99% recovery;
                                                 and a 4-bed system can achieve up to mid-99% recovery. Commercial processes
                                                 include MCRC, CBA, and Sulfreen. Figure 5B represents the comparison of Sub-



  S u b -D e w p o in t




                                                                                                                                     H 2S / S O 2                                          H 2S / S O 2
                                                                                                                                                                             9 9 .5 %
                                                                                                                      9 9 .0 %         AC                                                  AC
                                                                                                          C o n v e rte r # 3                                     C o n v e rte r # 4
 T h erm al                C o n v e rte r # 1                 C o n v e rte r # 2                                                                                S u b - D e w P o in t
                                  C la u s                     S u b - D e w P o in t                     S u b - D e w P o in t
 S ta g e




  P R O C la u s                                                                H 2S / S O 2
                                                                                                                                                      9 9 .5 %
                                                                               AC

                    T h erm al                    C o n v e rte r # 1                          C o n v e rte r # 2                          C o n v e rte r # 3
                    S ta g e                             C la u s                                  S e le c tiv e                               S e le c tiv e
                                                                                                  R e d u c tio n                              O x id a tio n



                                                                                                                              A ir



                                                 Dew point with PROClaus.




                                   Figure 5B, Comparison of PROClaus with Sub-Dew Point Process


                                                                                               8-6
Section 8               Sulfur Recovery & Criteria Selection for Tail Gas Treating System


8.6   BSR/Selectox & BSR/HI-Activity Technologies

                     WorleyParsons acquired the exclusive rights to a series of innovative catalysts de-
                     veloped in Russia. These catalysts are to be used in WorleyParsons newly offered
                     technology, Hi-Activity Process, and are capable of enhancing the sulfur recovery
                     of a conventional Claus SRU to 99.0%. In this process, the conventional Claus
                     catalyst in the third sulfur converter is replaced with WorleyParsons' Hi-Activity
                     catalyst. Different from the conventional Claus catalyst, WorleyParsons' Hi-Activity
                     catalyst selectively promotes the reaction of H2S with oxygen to form elemental
                     sulfur directly. With an enhanced sulfur recovery efficiency of 98.5 to 99.0%, this
                     may be sufficient to satisfy sulfur emissions regulations in certain areas, and no
                     further tail gas treating would be required.

                     In the event that an overall sulfur recovery of 98.5 to 99.5% is sufficient to satisfy
                     the local sulfur emissions regulations, WorleyParsons' BSR/Selectox, BSR/Hi-
                     Activity, or PROClaus process can be used.

                     These catalysts are manufactured without a carrier and are capable of converting
                     H2S (85 to 95%) directly to elemental sulfur in the presence of oxygen according to
                     the following equation:

                             H2S + 1/2 O2 = S + H2O

                     They also have high selectivity’s (93 to 97%) for H2S conversion to elemental sul-
                     fur instead of sulfur dioxide or other sulfur compound by-products. Professor Alk-
                     hazov's data indicates that these catalysts are capable of achieving 85 to 95+% of
                     H2S conversion to elemental sulfur. The performance of one of these catalysts,
                     KS-1, had been proven in a commercial-scale Claus sulfur recovery unit of the
                     Minnibayevsky Gas Plant in Almetyevsk, Russia for 2 years. The catalyst, KS-1,
                     was capable of achieving more than 90% conversion of H2S in the feed gas to
                     elemental sulfur. Unlike the conventional Claus catalyst, conversion to sulfur in
                     these Hi-Activity catalysts is relatively insensitive to water. This distinct character-
                     istic of the catalysts is used advantageously for Claus tail gas treating. The water
                     condensing and removal step could therefore be eliminated from the BSR design
                     without sacrificing the overall sulfur recovery significantly. In addition, CO, CO2,
                     and saturated hydrocarbons do not have a deleterious effect on these catalysts.

                     The BSR/Hi-Activity Process is capable of achieving an overall sulfur recovery effi-
                     ciency of 99.5%, while using an even simpler process configuration than that of the
                     BSR/Selectox Process.

                     Figures 6&7 show the simple process configuration of the BSR/Selectox
                     Process and BSR/Hi-Activity Process respectively, where the direct contact



                                              8-7
Section 8     Sulfur Recovery & Criteria Selection for Tail Gas Treating System


            condenser, its associated equipment, and the gas reheater are eliminated
            from the BSR/Selectox Process configuration.




                                  8-8
Section 8   Sulfur Recovery & Criteria Selection for Tail Gas Treating System




                               8-9
Section 8   Sulfur Recovery & Criteria Selection for Tail Gas Treating System




                              8-10
Section 9     WorleyParsons PROClaus Process

            WorleyParsons’ latest developed Claus tail gas scheme, PROClaus (WorleyPar-
            sons RedOx Claus) Process, makes an evolutionary improvement to the current
            tail gas schemes by eliminating the requirements of additional processing units, or
            changing the conventional continuous Claus operation to either shifted or cyclic
            operation. The PROClaus Process is a continuous catalytic process that com-
            bines Claus reaction, selective reduction of SO2 to sulfur, and selective oxidation
            of H2S to sulfur into one, integrated processing scheme.

            PROClaus Process Processing Steps

            WorleyParsons proprietary (patent pending) PROClaus (WorleyParsons RedOx
            Claus) Process, as suggested by its name, consists of three processing steps:

            Step 1 - a conventional Claus thermal stage and at least one Claus catalytic stage

            Step 2 - a selective reduction stage that converts SO2 to elemental sulfur

            Step 3 - a selective oxidation stage that converts H2S to elemental sulfur

            The keys to this new process invention are:

                Combining three distinct processing steps, two being commercially proven,
                into one fully integrated process.

                Taking the advantage of the H2 and CO produced in the Claus reaction fur-
                nace as reducing gas for processing Step 2 (selective reduction of SO2 to
                elemental sulfur). No external supply of reducing gas is required.

                Develop a highly selective SO2 reduction catalyst for Claus-type process gas
                (diluted SO2 stream and lower operating temperatures as compared to previ-
                ous research efforts focused on FGD applications).

                The PROClaus Process is capable of achieving an overall sulfur recovery effi-
                ciency of 99.5%

                Figure 8 is a simplified process flow diagram of a 3-stage PROClaus Process.

            Table VIII presents the comparison of tail gas cleanup processes.




                                    9-1
Section 9                         WorleyParsons PROClaus Process

                                      Table VIII- WorleyParsons BSR/Tail Gas Processes

Section                                   BSR/ MDEA         BSR/Selectox   BSR/Hi-Activity   PROClaus

BSR Section:
        Reducing Gas Generator                1                  1               1              -
 Hydrogenation/Hydrolysis                     1                  1               1              -
Reactor
        Reactor Effluent Cooler               1                  1               1              -
        Direct-Contact Condenser              1                  1                -             -

H2S Removal Section:
        MDEA                                  1                  -                -             -

H2S Conversion Section:
        Reheater                               -                 1                -             1
        Converter                              -                 1               1              1
        Sulfur Condenser                       -                 1               1              1

Attainable Overall Sulfur Recovery,          99.9               99.0            99.3           99.3
%

Relative Cost Factor                         100                64               50             45




                                                      9-2
Section 9                               WorleyParsons PROClaus Process

                                                  Figure 8, PROClaus Process



                                                                                              Air




                                                                Claus                  Selective
                             HP Steam                                                  Reduction                 Selective
                                                               Converter
                                                                                       Converter                 Oxidation
                                                                                                                 Converter
                               Waste
                  Reaction                                                                                                                  O2
                               Heat
                  Furnace                           Reheater               Reheater                      Reheater
                               Boiler                                                                                                  AC
                                                    No. 1                  No. 2                         No. 3
                                         LP Steam               LP Steam           H2S/SO2                                 LP Steam
                                                                                              LP Steam
 Acid Gas                                                                             AC
              K.O             BFW
              Drum
                                                                                                                                        Tail
                                          Condenser              Condenser                    Condenser                    Condenser
                                                                                                No. 3                        No. 4      Gas
                                            No. 1                  No. 2

    Water
            Air                                                                                    BFW                       BFW
                                            BFW                 BFW

                                                                                                                       M

                                                                                                                                   Liquid
                  Air Blower
                                                                                   Sulfur Pit                                      Sulfur
                                                                                                                    Sulfur Pump




                                                               9-3
Section 10     Conclusions

             The key features affecting the selection of the acid gas processes are discussed.
             This paper also demonstrates the application of the most common technologies
             that are well known in the industry. In order to select the proper acid gas removal,
             the entire key parameters step- by- step should be considered. The selection crite-
             ria of gas preconditioning and the final steps of gas conditioning processes to meet
             the environmental regulations have been emphasized. Various contaminants and
             the removal process are discussed. Depending on the process route selected, all
             the criteria would be satisfied.

             The key features affecting the selection of the tail gas treating processes are dis-
             cussed. The application of the most-common well-known technologies is demon-
             strated. In order to select the proper tail gas cleanup, all the key parameters step-
             by -step should be considered.

             WorleyParsons' BSR/MDEA, BSR/Selectox, PROClaus, and BSR/Hi-Activity tail
             gas treating systems improve sulfur recovery efficiencies.

             WorleyParsons’ developed BSR/Hi-Activity, tail gas treating system is expected to
             be superior to the BSR/Selectox system. The BSR/Hi-Activity Process is projected
             to be capable of achieving up to 99.5% overall sulfur recovery efficiency with a
             projected 25% capital cost savings compared to that of the BSR/Selectox system.

             WorleyParsons’ newly developed PROClaus, tail gas treating system is expected
             to be superior to other commercial tail gas processes. This new process is pro-
             jected to be capable of achieving up to 99.5% overall sulfur recovery efficiency and
             will certainly revolutionize how an efficient and cost-effective SRU/TGU should be
             designed.




                                     10-1
Section 11        References

             1.     Process Screening and Selection for Refinery Acid Gas Removal Process-
                    ing, Gupta, and S.R., et. al., Energy Progress, 6:4, pp. 239-47, December,
                    1986

             2.     Tertiary Ethanolamines More Economical for Removal of H2S and CO2,
                    Riesenfeld, F.D., et. al., Oil & Gas Journal, pp. 61-65, September 29, 1986

             3.     Modeling acid gas treating by using AGR physical solvents, Don D. Zhang
                    Presented at Laurence Reid Conference 1999.

             4.     Gas Processors Suppliers Association, 10th edition, Volume 2, Section 21




                                     11-1

								
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