COPYRIGHT 6/9/2017. Introduction

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1 6/9/2017 Introduction The field of gas sweetening and sulfur recovery is a broad specialization in gas engineering and technology The amine, physical solvent and sulfur recovery technologies described in this Skill Module are widely used in production facilities, gas processing and oil refineries 1 1

2 6/9/2017 Learning Objectives Contaminant Removal Acid Gas and Mercury Removal Core Mercury and Acid Gas Removal By By the the end end of of this this lesson, lesson, you you will will be be able able to: to: Explain why mercury is removed from a natural gas stream, and list two common mercury absorbents List the process options for acid gas removal from a natural gas stream 2 1

3 6/9/2017 Why Mercury is Removed? Mercury is frequently present in produced fluids Generally more of an issue in gas systems (either associated or non-associated) because of its toxicity and interaction with aluminum Protection of aluminum components 1. Amalgam corrosion 2. Liquid metal embrittlement Mercury is toxic Sales or transportation quality specifications Mercury Removal Technologies Concentration Location Range µg/nm 3 North America South America North Europe North Africa Middle East 1 10 East Asia Mercury effect on turboexpander wheel Mafi-Trench Company - used with permission The mercury removal options available to the gas processor are based on three categories that can be applied to both gas streams and liquid products: Sulfur impregnated activated carbon Metal oxides/sulfides dispersed onto a solid carrier Molecular sieve technology (regenerable) Removal Location? Upstream of Acid Gas Removal Unit (AGRU) Downstream of Dehydration Integrated into Dehydration 3 2

4 7/20/2017 What are Acid Gases? Produced gases are often contaminated with CO 2 as well as H 2 S and other sulfur species H 2 S Highly toxic Flammable and forms SO 2 upon combustion Metal loss corrosion Due to dissociation in water to form a weak acid Corrosion product is iron sulfide FeS which normally tightly adheres to steel surface Stress cracking Sulfide stress cracking Hydrogen induced cracking What are Acid Gases? CO 2 Corrosive to carbon steel In the presence of water forms carbonic acid (H 2 CO 3 ) ph is a function of the partial pressure of CO 2 in the vapor phase Corrosion product is iron carbonate FeCO 3 which does not adhere tightly to steel surface 4 1

5 7/20/2017 Removal of CO 2, H 2 S and Other Sulfur Compounds Removal of CO 2 as well as H 2 S and other sulfur compounds may be required to meet gas quality specifications in sales and transportation agreements Removal of these compounds from NGL liquid products may also be required CO 2 from ethane or C 2 + NGL mixtures H 2 S and sulfur compounds from NGL products Removal of CO 2 is often required to meet processing requirements Deep NGL extraction plants: typically less than 0.5 to 1.0 mol% depending on the process used LNG liquefaction plants: less than 50 ppmv Is There a Difference Between Sour Gas and Acid Gas? As discussed previously, acid gas components refer to H 2 S and CO 2 Sour generally refers to mixtures that contain sulfur compounds in excess of: A quality specification in a gas sales or transportation contract/tariff Can also apply to liquid products, such as NGLs, condensate and crude oil A design specification for materials selection and fabrication procedures such as NACE MR0175 or ISO The concentration of CO 2 has no effect on whether the gas is considered sour 5 2

6 7/20/2017 Is There a Difference Between Sour Gas and Acid Gas? The process used to remove acid gas and/or sour components from a gas or liquid stream is often called: Acid Gas Removal Unit (AGRU) Gas or Liquid Treating Gas or Liquid Sweetening These are often used interchangeably even though technically they have different meanings Example Gas Compositions Composition, mol % Northern Oman North Africa Component Wyoming Onshore N.W. Alberta Offshore USA Onshore He N C CO C H 2 S C C C C

7 7/20/2017 Gas Processing Facility Block Flow Diagram Tail Gas Hydrogen Sulfide (H 2 S) & Other S Compounds SRU/TGU Sulfur Product Carbon Dioxide (CO 2 ) to Vent or Reinjection Produced Gas Stream Hg Conditioning Water (H 2 O) Disposal NGL Extraction Acid Gas Removal Processes Chemical Absorption Amine Most popular process (by far) Acid-Base reaction Primarily for H 2 S & CO 2 removal Fuel Stabilization/ Fractionation Product Treating Physical Absorption No chemical reaction Several licensed solvents Used for removal of H 2 S, CO 2, mercaptans and other trace sulfur compounds NGL Sales or Condensate 7 4

8 7/20/2017 Acid Gas Removal Processes Hybrid Solvents A customized blend of amine, physical solvent and water Can be formulated to meet process objectives Fixed Bed/Scavenger Molecular sieve, zinc oxide, Sulfatreat Used for removal of relatively small amounts of H 2 S and other sulfur compounds Acid Gas Removal Processes Direct Conversion/Redox/Biological Processes Directly convert the H 2 S and trace sulfur components to elemental sulfur or non-hazardous compounds Redox processes (Stretford, LO-CAT, Sulferox, et al.) Liquid-based reduction-oxidation reaction Paques (THIOPAQ O&G ) Bacteria converts H 2 S to elemental sulfur Membranes (mainly CO 2 ) Extractive Distillation (mainly CO 2 ) 8 5

9 7/27/2017 Learning Objectives You are now able to: Explain why mercury is removed from a natural gas stream, and list two common mercury adsorbents List the process options for acid gas removal from a natural gas stream 9 1

10 Learning Objectives Contaminant Removal Acid Gas and Mercury Removal Core Acid Gas Removal by Amines By By the the end end of of this this lesson, lesson, you you will will be be able able to: to: Describe a basic amine process flow diagram Estimate the amine circulation rate, regenerator reboiler duty and circulation pump power for an AGRU State the conditions where a physical solvent may be advantageous over an amine solvent for acid gas removal List examples where it may be advantageous to selectively remove H 2 S from a gas stream but leave some or all of the CO 2 in the gas 10

11 Contaminant Removal Acid Gas and Mercury Removal Core Amines Most popular process for removal of H2S and CO2 Primary Amines Advantages Can achieve very low acid gas concentrations Monoethanol amine (MEA) Water-based solvent (amine circulated at low molar concentrations) Diglycol amine (DGA) Secondary Amines Low hydrocarbon solubility Often sold as a tailored blend today to better meet process objectives T Disadvantages Diethanol amine (DEA) Diisopropanol amine (DIPA) Corrosive Tertiary Amine High heat of regeneration R IG Can form heat stable salts (primary amines) Methyl Diethanol amine (MDEA) O PY Several amine choices Piperazine C4H10N2 H Generally not effective in removing mercaptans, COS, etc. Process Flow Diagram for a Basic Amine Acid Gas Recovery Unit Regenerator Reflux Condenser Sweet Process Gas Outlet Scrubber Acid Gas Out C Lean Amine Filtration Make up Water Lean Amine Cooler Amine Surge Tank Trays or Packing To Amine Sump HC Skim Trays or Packing Amine Contactor Amine Regenerator Reflux Pump H.P. Lean Amine Pump Sour Process Gas Optional Inlet Separator Flashed Vapor To Fuel or Flare Rich Amine Flash Drum Reclaimer Lean Amine To HC Drain Rich Amine Solids Filter HC Skim Optional Lean/Rich Booster Pump Amine Heat Exchanger Reboiler 11

12 Physical Solvents Advantages Good for bulk removal (high acid gas partial pressure) Selective Lower energy requirements Less corrosive Can remove mercaptans and other trace sulfur species DEPG (Dimethyl Ethers of Polyethylene Glycol) Licensed under several trade names such as Selexol, Coastal AGR, Genosorb Can remove CO 2, H 2 S, mercaptans and water Methanol Disadvantages You may want to PAUSE pause Licensed under trade names Rectisol a moment to review the (Lurgi) and IFPexol (Prosernat) Expensive equations and terms. Requires refrigeration, low temperature Proprietary, license required operation More difficult to meet tight effluent specs Can remove CO 2, H 2 S, and COS (CO 2, H 2 S) NMP (N-Methyl-2-Pyrrolidone) Co-absorption of heavy hydrocarbons Licensed under trade name Purisol (Lurgi) Process Flow Scheme Primarily used in synthesis gas applications Similar to amine: high pressure High selectivity, H 2 S/ CO 2 absorption/low pressure regeneration Propylene Carbonate Regeneration is simpler Most of the acid gas flashes out of solvent at Licensed under trade name Fluor Solvent low pressure Good for bulk CO 2 removal on streams with Heat/stripping may be required to remove residual H 2 S and organic sulfur compounds little or no H 2 S Effect of Acid Gas Partial Pressure on Solvent Choice 12

13 Hybrid Solvents A blend of amine, water and a physical solvent Process flow scheme is essentially identical to an amine unit Advantages Can be formulated to achieve a wide range of process objectives Effective at removing mercaptans and other trace sulfur compounds Higher acid gas loadings Reduced energy consumption Less corrosion than amine system Can achieve lower acid gas concentrations than physical solvents Disadvantages Higher solvent cost Co-absorption of heavy hydrocarbons, especially aromatics Sulfinol D, Sulfinol M, Sulfinol X (Shell) Sulfolane C 4 H 8 O 2 S UCARSOL 701, 702 and 703 (Dow Chemical) HYSWEET (Total) Approximate Economic Ranges for Processes to Treat Sour Gas Acid Gas Content, Vol% CO 2 + H 2 S Mol Sieve Iron Sponge Zinc Oxide Sulfatreat Triazine MEA DGA DEA MDEA Sulfinol Selexol Purisol Etc. Acid Gas Content, Vol% CO 2 + H 2 S 13

14 Summary of Process Capabilities for Gas Treating Normally Capable of Meeting 4 ppmv H 2 S GPSA Engineering Data Book Summary Removes Mercaptans and COS Selective H 2 S Removal Solution Degraded (By COS & CO 2 ) Treating Process Secondary Amine Yes Partial No Some Tertiary Amine Yes Partial Yes* No Hybrid/Mixed Yes Yes Yes* Some Physical Solvent Yes Yes Yes* No Solid Bed Yes Yes Yes* N/A Liquid Redox Yes No Yes CO 2 at high conc. Sacrificial Yes Partial Yes N/A * Some selectivity exhibited Courtesy of the GPSA Data Book 14

15 6/9/2017 Approximate Guidelines for Amine Processes Variable MEA DEA DGA MDEA Maximum solution concentration, wt% Acid gas pickup std m 3 /m 38 C [scf/u. S. 100 F] [ ] [ ] [ ] [3 7.5] Acid gas pickup mols/mol amine Lean solution residual acid gas, mol/mol amine 0.12± 0.01± 0.06± Rich solution acid gas loading, mol/mol amine Approximate reboiler heat duty, MJ/m [1000 [840 [1100 [Btu/gal] lean solution [ ] 1200] 1000] 1300] Adapted from the GPSA Engineering Data Book 3 std m acid gases scf acid gases Acid Gas Loading = moles acid gas or 3 mol amine std m lean solution US gal lean solution May be referred tolean or rich aminesolution 15 1

16 Example Acid Gas Removal Unit (AGRU) 5 million std m 3 Sweet Gas /d [177 H MMscfd] of natural gas is to be processed in an amine 2 S = 4 ppmv system for removal of CO H 2 S = and 50 ppmv CO 2. The feed gas contains 5.9 mol% CO 2 and 4.7 mol% H 2 S. All of the H 2 S and CO 2 is to be removed. The amine is a 50 wt% activated MDEA solution with a rich amine acid gas loading of 0.41 mols/mol and a lean amine acid gas loading of 0.01 mols/mol. The density of the amine solution is 1017 kg/m 3 [8.49 lbm/us gal]. The MW of MDEA is Estimate the acid gas 50 wt% MDEA solution composition and sulfur Lean loading = 0.01 production mol acid gas/ mol MDEA 2. Estimate the acid gas pick up in sm 3 /m 3 of amine sol. Sour Gas Rate = [scf/us gal of amine sol.] 5 x Estimate 6 sm the 3 /day [177 MMSCFD] CO amine circulation 2 = 5.9 mol% rate H in m 3 /h [US gpm] 2 S = 4.7 mol% 4. Estimate the regenerator reboiler duty in MW [MMBtu/hr] Rich loading = Estimate the amine mol acid gas/ mol circulation pump power in MDEA kw [HP]. Assume pump efficiency is 80%. Example Acid Gas Removal Unit (AGRU) 5 million std m 3 /d [177 MMscfd] of natural gas is to be processed in an amine system for removal of H 2 S and CO 2. The feed gas contains 5.9 mol% CO 2 and 4.7 mol% H 2 S. All of the H 2 S and CO 2 is to be removed. The amine is a 50 wt% activated MDEA solution with a rich amine acid gas loading of 0.41 mols/mol and a lean amine acid gas loading of 0.01 mols/mol. The density of the amine solution is 1017 kg/m 3 [8.49 lbm/us gal]. The MW of MDEA is Estimate the acid gas Sweet Gas H 2 S = 4 ppmv composition and sulfur CO 2 = 50 ppmv production 2. Estimate the acid gas pick up in sm 3 /m 3 of amine sol. [scf/us gal of amine sol.] 3. Estimate the amine circulation rate in m 3 /h [US gpm] 4. Estimate the regenerator reboiler duty in MW [MMBtu/hr] 5. Estimate the amine circulation pump power in kw [HP]. Assume pump efficiency is 80%. Sour Gas Rate = 5 x 10 6 sm 3 /day [177 MMSCFD] CO 2 = 5.9 mol% H 2 S = 4.7 mol% 50 wt% MDEA solution Lean loading = 0.01 mol acid gas/ mol MDEA Rich loading = 0.41 mol acid gas/ mol MDEA 16

17 Example-Acid Gas Composition and Sulfur Production The acid gas composition leaving the regenerator is an important factor in selection of a sulfur recovery process. Critical to the design of an acid gas injection system if a sulfur recovery unit (SRU) is not installed. Since all of the acid gas is removed from the feed gas, the acid gas composition is simply the ratio of the volumes of H 2 S and CO 2 to the total acid gas volume. Example-Acid Gas Composition and Sulfur Production Estimate the acid gas composition (ignore water). Assume all the H 2 S and CO 2 is removed. H 2 S Volume CO 2 Volume H 2 S Composition % % CO 2 Composition % % Sulfur Production (Eq. 19.1)

18 Example Acid Gas Pickup Estimate the acid gas loading in sm 3 /m 3 amine solution [scf/us gal amine solution]. acid gas amine std m acid gas acid gas amine % amine 100 solution m mol acid gas mol amine scf acid gas mol acid gas Acid gas loading calculations mol amine Example-Amine Circulation Rate % amine Estimate the amine circulation rate in m 3 /h [US gpm]. Acid gas volume: solution.. gas.. gal Amine circulation rate: See Contaminant Removal Gas Dehydration Core for more information. 18

19 Example-Regenerator Reboiler Duty & Circulation Pump Power Estimate the reboiler duty. From table 19.5 we will use 235 MJ/m 3 [850 Btu/US gal] Reboiler Duty: Estimate the amine circulation pump power. Assume that the contactor pressure is 70 bar [1015 psia] and that the regenerator pressure is 1.75 bar [26 psia]. Pump Power (Eq. 13.3)

20 7/27/2017 Selective Treating-CO 2 Slippage Acid gas composition in non-selective treating example: H 2 S composition: 44.3 mol % CO 2 composition: 55.7 mol% This is the feed to the sulfur recovery unit (SRU) We can design sulfur recovery units to handle this feed composition but we prefer a feed stream with a higher concentration of H 2 S This reduces equipment sizes in the SRU and improves overall sulfur recovery Selective Treating-CO 2 Slippage Acid gas composition in non-selective treating example: H 2 S composition: 44.3 mol % CO 2 composition: 55.7 mol% A common method of changing the acid gas composition is to use a selective amine which absorbs all of the H 2 S but absorbs only a portion of the CO 2 This is referred to as CO 2 slippage 20 1

21 6/28/2017 Where Selective Removal of H 2 S Can Be Used Vendors have many choices of proprietary amine blends to choose from Meeting pipeline acid gas specifications Reducing H 2 S concentration to 4 ppmv Allowing CO 2 concentration up to about 3 mol% Acid gas enrichment Enriching H 2 S for sulfur recovery Enriching CO 2 Dense phase transportation Enhanced oil recovery (EOR) 21 1

22 Exercise Selective Treating (CO2 Slippage) In the previous example, all of the H 2 S and CO 2 was removed from the gas stream. In this exercise we will evaluate a selective treating process where only 55% of the CO 2 will be absorbed in the amine. In other words 45% of the CO 2 will leave the contactor with the sweet gas. All other parameters will remain the same. The density of the amine solution is 1017 kg/m 3 [8.49 lbm/us gal]. The MW of MDEA is 119. CO 2 Volume 1. Estimate the acid gas composition and calculate the concentration of CO 2 in the sweet gas Sweet Gas H 2 S = 4 ppmv CO 2 =? 2. Estimate the amine circulation rate in m 3 /h [US gpm] 3. Estimate the regenerator Sour Gas Rate = reboiler duty in MW 5 x 10 6 sm 3 /day [177 MMSCFD] CO [MMBtu/hr] 2 = 5.9 mol% H 2 S = 4.7 mol% 4. Estimate the amine circulation pump power in kw [HP]. Assume pump efficiency is 80%. Exercise-Acid Gas Composition and CO 2 Concentration in Sweet Gas H 2 S Composition 50 wt% MDEA solution Lean loading = 0.01 mol acid gas/ mol MDEA Rich loading = 0.41 mol acid gas/ mol MDEA Estimate the acid gas composition (ignore water). Assume all the H 2 S and 55% of the CO 2 is removed. H 2 S Volume % % CO 2 Composition % % CO 2 Concentration in sweet gas % % 22

23 Exercise-Amine Circulation Rate w/ Selective Treating Estimate the amine circulation rate in m 3 /h [US gpm]. Use the acid gas pick-up values for the non-selective treating case. Acid gas volume: H 2 S CO H 2 S CO 2 Amine circulation rate: Example-Regenerator Reboiler Duty & Circulation Pump Power Estimate the reboiler duty. From table 19.5 we will use 235 MJ/m 3 [850 Btu/US gal] Reboiler Duty: Estimate the amine circulation pump power. Assume that the contactor pressure is 70 bar [1015 psia] and that the regenerator pressure is 1.75 bar [26 psia]. Pump Power (Eq. 13.3)

24 6/28/2017 Learning Objectives You are now able to: Describe a basic amine process flow diagram Estimate the amine circulation rate, regenerator reboiler duty and circulation pump power for an AGRU State the conditions where a physical solvent may be advantageous over an amine solvent for acid gas removal List examples where it may be advantageous to selectively remove H 2 S from a gas stream but leave some or all of the CO 2 in the gas 24 1

25 Learning Objectives Contaminant Removal Acid Gas and Mercury Removal Core Sulphur Recovery and Tail Gas Treating By By the the end end of of this this lesson, lesson, you you will will be be able able to: to: Describe the process flow diagram for a standard Claus sulfur recovery unit (SRU) Explain why a tail-gas-clean-up unit (TGCU) may be required, and list processes that may be applied 25

26 Gas Sweetening and Sulfur Recovery Integration Gas Sweetening Physical Absorption Chemical Absorption Sulfur Recovery Unit 90 98% Overall Sulfur Recovery Claus LO-CAT /Sulferox SUPERCLAUS Etc. Straight-Through Claus Sulfur Recovery Unit Acid-gas typically enters at kpa [22 29 psia] About 60% of the H 2 S is converted to sulfur in reaction furnace Tail Gas Treating Unit SCOT MCRC CBA SULFREEN SELECTOX Etc. Total conversion typically ranges from 90 to 98% The reaction furnace operates at ~ 980 to 1370 C [1800 to 2500 F] Converters: in C [ F]; out C [ F] Condensers: outlets C [ F] H 2 S + 3/2 O 2 H 2 O + SO 2 (19.1) 2H 2 S + SO 2 3S + 2H 2 O (19.2) 26

27 Claus Plant Configurations Feed H 2 S Concentration, Claus Variation Suggested Mol% Straight-through Straight-through or straight-through with acid gas and/or air preheat Split-flow or straight-through with feed and/or air preheat Split-flow with acid gas and/or air preheat 5 10 Split-flow with fuel added or with acid gas and air preheat, or direct oxidation or sulfur recycle < 5 Sulfur recycle or variations of direct oxidation or other sulfur recovery processes. Courtesy of the GPSA Data Book Claus Sulfur Recovery Operational Aspects Combustion process at kpag [3 14 psig] To oxidize one-third of the H 2 S to SO 2 To burn hydrocarbons and mercaptans, and For many refinery Claus units, to oxidize ammonia and cyanides 27

28 Claus Sulfur Recovery Operational Aspects Combustion side reaction products H 2, CO, COS, and CS 2 H 2 conc. is proportional to the conc. of H 2 S in the feed gas Formation of CO, COS, and CS 2 is related to the amounts of CO 2 and/or hydrocarbons in the feed gas Heavy hydrocarbons may burn partially and form carbon which can cause deactivation of the Claus catalyst and the production of offcolor sulfur Ammonia and cyanides can burn to form NO which catalyzes the oxidation of SO 2 to SO 3 SO 3 causes sulfation of the catalyst and can also cause severe corrosion in cooler parts of the unit Unburned ammonia may form ammonium salts which can plug the catalytic converters, sulfur condensers, liquid sulfur drain legs Claus Sulfur Recovery Operational Aspects Flame stability can be a problem with low H 2 S content feeds The split flow, sulfur recycle, or direct oxidation process variations often are utilized to handle these H 2 S-lean feeds This can result in the cracking of heavy hydrocarbons to form carbon or carbonaceous deposits and the formation of ammonium salts Significant amounts of BTEX in the feed requires operation of the thermal reactor in excess of 1200 C [2,190 F] Acid gas enrichment, an extra cycle of absorption/regeneration can also be used to increase the acid gas H 2 S concentration Catalyst dust plugging the liquid sulfur drain lines that remove liquid sulfur Operating too close to the sulfur dew-point at the entry to the converter beds and condensing liquid sulfur onto the catalyst 28

29 6/28/2017 Why Tail-Gas Clean-Up (TGCU) is Needed? To meet regulations for emissions Sulfur recovery efficiency in the Claus SRU <100% Long term efficiency is in the range of 95-97% Operational upset can reduce the efficiency over short periods Examples of TGCU Technologies Some technologies used in Tail Gas Clean-Up (TGCU) include: Cold Bed Adsorption e.g., CBA and others Direct oxidation of H 2 S to sulfur e.g., SUPERCLAUS, EUROCLAUS H 2 S recycle e.g., SCOT Sulfur oxidation e.g., Cansolv, Clintox, et. al 29 1

30 6/28/2017 Example SCOT Process SCOT Reactor Notes: RGG - Reducing Gas Generator LPS - Low Pressure Steam CW - Cooling Water Combined Claus-plus-SCOT TGCU typically achieves better than 99.9% efficiency 30 2

31 6/12/2017 Learning Objectives You are now able to: Describe the process flow diagram for a standard Claus sulfur recovery unit (SRU) Explain why a tail-gas-clean-up unit (TGCU) may be required, and list processes that may be applied 31 1

32 6/28/2017 Learning Objectives Contaminant Removal Acid Gas and Mercury Removal Core Acid Gas Injection and NGL Product Treating By By the the end end of of this this lesson, lesson, you you will will be be able able to: to: List the advantages of acid gas injection over installation of an SRU and TGCU Describe why liquid product treating may be required, and provide examples of common processes used 32 1

33 6/28/2017 Why Acid Gas Injection? Advantages: Saves cost of SRU and TGCU No need for sulfur storage No need for run-off water treating with bulk sulfur storage Acid Gas Injection Schematic Disadvantages: High compression costs A source of steam for amine reboiler replacing the steam which generated in a clause process waste heat boiler Require a nearby suitable disposal Geological consideration 33 2

34 7/27/2017 Distribution of Contaminant in NGL Products You may want to PAUSE pause a moment to review the animation. NGL Product Treating The process operation of Liquid Product Treating is usually abbreviated to Product Treating in the gas industry Why is this required? Meet liquid product specifications Corrosion, Freezing, Emissions, and Safety / Handling Issues Purpose: Removal of CO 2 and trace of sulfur compounds from NGL products CO 2 must be removed from C 2 and Y-grade products H 2 S and other sulfur compounds (mercaptans, COS, DMS, etc.) must be removed from all NGL products 34 1

35 7/27/2017 NGL Product Treating Liquid Products that may need treating: Ethane, propane, i-butane, n-butane Ethane-Propane (E-P) mixes and Butane-Propane (B-P) mixes Butane (mixture of i-butane and n-butane) LPG: a mixture propane and butane NGLs: from ethane down through LPG and often down further into condensate components Some Liquid Product Treating Processes 35 2

36 6/28/2017 Contaminant Removal Acid Gas and Mercury Removal Core Learning Objectives You are now able to: List the advantages of acid gas injection over installation of an SRU and TGCU Describe why liquid product treating may be required, and provide examples of common processes used PetroAcademy TM Gas Conditioning and Processing Core Hydrocarbon Components and Physical Properties Core Introduction to Production and Gas Processing Facilities Core Qualitative Phase Behavior and Vapor Liquid Equilibrium Core Water / Hydrocarbon Phase Behavior Core Thermodynamics and Application of Energy Balances Core Fluid Flow Core Relief and Flare Systems Core Separation Core Heat Transfer Equipment Overview Core Pumps and Compressors Overview Core Refrigeration, NGL Extraction and Fractionation Core Contaminant Removal Gas Dehydration Core Contaminant Removal Acid Gas and Mercury Removal Core 36 1