The Sour Gas, Sulfur and Acid Gas Book

Technology and Application in Sour Gas Production, Treating and Sulfur Recovery

(SI Units)

Edward Wichert

(www.grayjay.ventures)

Preface The objective of The Sour Gas, Sulfur and Acid Gas Book is to describe the historical development and current applications of the procedures and processes used in the sour natural gas industry to safely produce, gather and treat sour gas, recover sulfur and dispose of waste products in an environmentally friendly manner. The production of sour natural gas in large volumes started in the 1950’s at Jumping Pound, Alberta, and at Lacq, France, and grew rapidly in the following years in Canada and the United States. This required the development of new technologies to handle the production and processing of the sour gas so that it could be used for industrial and domestic purposes. The evolution of improvements in metallurgy for sour gas, well completion techniques, sour gas treating methods and the increases in sulfur recovery efficiency can be traced by reviewing the papers published in the technical literature or presented at various gatherings of industry experts, such as the Laurance Reid Gas Conditioning Conference (LRGCC) held annually near the end of February in Norman, Oklahoma. Up to about the mid-1950’s the topics at such technical conferences dealt mainly with research on natural gas properties and natural gas dehydration. Since that time, the papers dealing with various improvements in sour gas treating and enhancements in sulfur recovery outnumber all other topics at the LRGCC. Currently (2018) the main sour gas developments are taking place in the Middle East, where a major technical conference on Sour Oil and Gas Advanced Technology (SOGAT) takes place annually. Along with the evolution of the sour gas technology there has been the development and evolution of the internet and the personal computer together with powerful software to simulate and refine any operation in sour gas and any other aspect in the hydrocarbon industry. It is now possible for a design engineer to enter any technical term or phrase into a search engine on the internet and extract detailed information on the topic. So why does one need a book? The intention of this book is to provide a historical perspective and a basic description of the various processes and procedures to get the sour gas safely out of the formation to surface, send it through a network of gathering lines to the central treating plant, separate the acid gas components and then describe the processes for handling the acid gas. With the use of computer simulation software it is possible to elaborate on any aspects of the path of the sour gas from reservoir to the ultimate disposal of the various components in the sour gas. Reference is frequently made to key articles published over the years in trade journals and technical publications, as well as papers presented at various conferences, which provide details on the many topics covered in this book. There are several sources of information dealing with the above topics that are available for downloading for free. An attempt will be made to reference such sources throughout the book. Additionally, there are simulation programs available for a fee from providers such as AspenTech, Virtual Materials Group (VMGsim), Bryan Research in Texas, Ops Group, FlowPhase and Optimized Gas Treating, Inc. The book uses SI units (metre-kilogram-second). In a few instances, equivalent Imperial (British) units (foot-pound-second) are also given. A comprehensive explanation of the SI units is available from the Canadian Association of Petroleum Producers (CAPP). The brochure can be downloaded by going to a search engine and entering “Supplementary Metric Practice Guide”, then clicking on the appropriate topic, and “Download”. The conversion constants between Imperial units and SI units are listed in Table 4-2 on pages 26 to 29 of the CAPP document.

OVERVIEW OF CONTENTS

THE SOUR GAS, SULFUR AND ACID GAS BOOK

CHAPTER 1 - PROPERTIES OF HYDROGEN SULFIDE (H2S) AND SOUR NATURAL GAS

CHAPTER 2 - SOUR GAS PRODUCTION AND GATHERING

PART 1 - DRILLING AND COMPLETION OF SOUR GAS WELLS PART 2 - FLOW CONTROL AND FLUID CONDITIONING FOR TRANSPORT TO PLANT PART 3 - DESIGN AND OPERATING CONSIDERATIONS FOR SOUR GAS GATHERING LINES PART 4 - RECEIVING GAS AND LIQUIDS AT THE PLANT

CHAPTER 3 - SOUR GAS SWEETENING

PART 1 - SWEETENING WITH REGENERATIVE SOLVENTS PART 2 - PROCESS EQUIPMENT DESIGN CONSIDERATIONS PART 3 - OPERATING PROBLEMS IN SOUR GAS TREATING PLANTS PART 4 - NON-REGENERATIVE CHEMICAL (SCAVENGER) PROCESSES

CHAPTER 4 – SULFUR RECOVERY AND HANDLING

PART 1 - SULFUR RECOVERY BY THE MODIFIED CLAUS PROCESS PART 2 - SULFUR PLANT ENHANCEMENTS PART 3 - TAIL GAS CLEAN-UP PART 4 - RECOVERY PROCESSES FOR LOW SULFUR RATES PART 5 - SULFUR PROPERTIES, HANDLING AND FORMING

CHAPTER 5 – ACID GAS COMPRESSION AND INJECTION

PART 1 - BASIC PROPERTIES OF ACID GAS PART 2 - MITIGATION OF CORROSION AND HYDRATE FORMATION PART 3 - DESIGN CONSIDERATIONS FOR ACID GAS COMPRESSION AND INJECTION FACILITIES PART 4 - OPERATION OF INJECTION FACILITIES

CHAPTER 6 - SAFETY SYSTEMS AND METHODS FOR SOUR GAS OPERATIONS Contents

CHAPTER 1 - PROPERTIES OF HYDROGEN SULFIDE (H2S) AND SOUR NATURAL GAS

1.1 What is Sour Natural Gas? 1.2 Properties of Hydrogen Sulfide 1.3 Conversion Calculations for Small H2S Concentrations in Natural Gas 1.4 Origin of H2S in Sour Gas 1.5 Other Sulfur Compounds 1.5.1 Mercaptan 1.5.2 Carbon Disulfide (CS2) and Carbonyl Sulfide (COS) 1.6 Geographic Occurrences of Sour Gas 1.7 Increase in H2S Concentration in Produced Sour Gas with Time 1.8 Characteristics of Sour Gas 1.9 Sour Gas Sampling and Analysis 1.10 Determination of Sour Gas Properties 1.10.1 Compressibility Factor, Z 1.10.2 Wichert-Aziz Modification of the Redlich-Kwong Equation of State 1.10.3 Wichert- Aziz Modification of the Standing-Katz (S-K) Chart Method 1.10.4 AGA #8 (1992) Method 1.10.5 Equilibrium Water Vapor Content of Sour Gas 1.10.6 Hydrate Formation and Hydrate Temperature Estimation 1.10.7 Dew Point, Bubble Point and Flash Calculations 1.10.8 Enthalpy Change Predictions 1.11 Sulfur Content of H2S in Sour Gas 1.12 Elemental Sulfur in Sour Gas 1.13 Effects of H2S and Sour Gas on Steel 1.13.1 General Metal Loss Corrosion 1.13.2 Corrosion Pitting 1.13.3 Hydrogen Induced Cracking (HIC) and Blistering 1.13.4 Hydrogen Embrittlement and Sulfide Stress Cracking 1.14 Effect of H2S on Stainless and High Alloy Steel 1.15 Effect of H2S on Elastomeric Materials 1.16 Design Considerations and Mitigating Techniques for H2S Effects on Carbon and Low Alloy Steel 1.16.1 Materials Selection 1.16.2 Dehydration 1.16.3 Use of Corrosion Inhibitors 1.17 Summary re Sour Gas Corrosion, Carbon Steel and Low Alloy Steel REFERENCES

ATTACHMENT 1 Compressibility Factor Calculation for Sour Natural Gases ATTACHMENT 2 Estimation of Water Content of Sour Natural Gas ATTACHMENT 3 Hydrate Temperature Estimation for Sour Natural Gases

CHAPTER 2 - SOUR GAS PRODUCTION AND GATHERING

PART 1 DRILLING AND COMPLETION OF SOUR GAS WELLS 2.1 Introduction 2.2 Properties of Casing 2.3 Casing for Sour Service 2.4 Well Completion - General 2.5 Tubing String Selection 2.6 Special Design Considerations for Tubing Strings 2.6.1 Subsurface Safety Valve 2.6.2 Bottom-hole Equipment 2.6.3 Corrosion Abatement in Sour Well Tubing 2.6.4 Hydrate Prevention in Tubing Strings 2.6.5 Clearing Sulfur Plugs 2.7 Well Cleanup and Testing

PART 2 FLOW CONTROL AND FLUID CONDITIONING FOR TRANSPORT TO PLANT 2.8 Wellsite Production Equipment for Sour Gas Wells 2.8.1 Fluid Temperature, Pressure and Flow Rate Control 2.8.2 Wellsite Heater 2.8.3 Production Measurement 2.8.4 Emergency Shutdown (ESD) 2.9 Conditioning Fluids for Transport to the Central Plant 2.10 Pressure Taps

PART 3 DESIGN AND OPERATING CONSIDERATIONS FOR SOUR GAS GATHERING LINES 2.11 Overview of Pipeline Design and Materials Standards and Regulations 2.12 Pipe Grade, Category and Estimation of Wall Thickness 2.13 Optimum Pipe Diameter 2.14 Estimating Pressure Drop in Gas Gathering Lines 2.15 Prevention of Gas Hydrates in Pipeline Gathering Systems 2.15.1 Gas Heating with Line Heaters 2.15.2 Gas Heating by Warm Water Tracing 2.15.3 Hydrate Prevention by Chemical Addition 2.15.4 Hydrate Prevention by Gas Dehydration 2.16 Pigging Facilities 2.17 Initiating Sour Gas Production 2.18 Internal Corrosion Inhibition and Monitoring 2.19 External Corrosion Prevention 2.20 Safety Considerations in Sour Gas Gathering Operations

PART 4 RECEIVING GAS AND LIQUIDS AT THE PLANT 2.21 Types of Fluids Entering Plant 2.22 Plant Inlet Separator 2.22.1 Separator Design Considerations 2.22.2 Estimating the Size of the Liquid Slug 2.23 Comments on Operating Procedure to Minimize Liquid Slugs REFERENCES

CHAPTER 3 - SOUR GAS SWEETENING

PART 1 SWEETENING WITH REGENERATIVE SOLVENTS 3.1 Overview 3.2 Typical Process Equipment for Sweetening Sour Gas 3.3 Sweetening Solvents 3.4 Regenerative Chemical Solvents 3.4.1 Primary Amines 3.4.2 Secondary Amines 3.4.3 Tertiary Amines 3.4.4 Hot Potassium Carbonate (K2CO3) (Hot Pot) 3.5 Comparison of Chemical Sweetening Solvents 3.6 Computer Simulation of Sweetening Processes 3.7 Physical Solvents 3.7.1 Selexol Process 3.7.2 Fluor Solvent Process 3.7.3 Purisol 3.7 4 Rectisol 3.7.5 Morphysorb 3.8 Proprietary and Mixed Amine Solvent Formulations 3.9 Selective H2S Removal 3.10 Sweetening of Liquefied Petroleum Gas (LPG) 3.11 Summary Comments on Sweetening Solvent Selection

PART 2 PROCESS EQUIPMENT DESIGN CONSIDERATIONS 3.12 Overview 3.13 Inlet Separator 3.14 Inlet Compression 3.15 Absorber or Contactor 3.16 Treated Gas Water Wash 3.17 Rich Solution Flash Drum 3.18 Rich/Lean Solution Heat Exchanger 3.19 Solution Still (Regenerator, Stripper) 3.20 Solution Reboiler 3.21 Still Overhead Condenser 3.22 Reflux Drum 3.23 Amine Surge Tank 3.24 Solution Pumps 3.25 Solution Filters 3.26 Solution Coolers 3.27 Amine Solution Reclamation 3.28 Process Optimization

PART 3 OPERATING PROBLEMS IN SOUR GAS TREATING PLANTS 3.29 Types of Operating Problems 3.29.1 Failure to Meet H2S Sales Gas Specifications 3.29.2 Solution Foaming 3.29.3 Corrosion 3.29.4 Solvent Loss 3.30 Metering of Acid Gas 3.31 Determining Water Content of Undersaturated Acid Gas Mixtures

PART 4 NON-REGENERATIVE CHEMICAL (SCAVENGER) PROCESSES 3.32 Overview 3.33 Dry Scavenger Chemical Sweetening Processes 3.33.1 Iron Sponge (Iron Oxide) 3.33.2 SulfaTreat (Iron Oxide) 3.33.3 Puraspec Process 3.34 Application of Liquid Scavenger Chemicals 3.34.1 Chemsweet (Zinc Oxide Slurry) 3.34.2 Slurrisweet (Iron Oxide Slurry) 3.34.3 Sulfa-Check (Salt Oxidizers, e.g. NaNO2) 3.34.4 Sulfa-Scrub 3.35 Summary Comments on Scavenger Chemicals 3.36 Summary Tabulations of Capabilities of Sweetening Processes REFERENCES

CHAPTER 4 - SULFUR RECOVERY AND HANDLING

PART 1 SULFUR RECOVERY BY THE MODIFIED CLAUS PROCESS 4.1 Introduction 4.2 Chemical Reactions of Modified Claus Process 4.3 Description of Modified Claus Process 4.3.1 The “Straight-Through” Modified Claus Process 4.3.2 The “Split-Flow” Modified Claus Process 4.4 Factors Affecting Sulfur Recovery by the Modified Claus Process 4.4.1 Air to H2S Ratio, or H2S to SO2 Ratio 4.4.2 Acid Gas Purity 4.4.3 High Intensity Burner 4.4.4 Retention Time, Mixing and Temperature in Reaction Furnace 4.4.5 Number of Catalytic Conversion Stages 4.4.6 Activity of Catalyst 4.5 Sulfur Condensers 4.6 Reheat Methods 4.6.1 Hot Gas Bypass 4.6.2 Acid Gas In-line Burners 4.6.3 Fuel Gas In-line Burner 4.6.4 Heat Exchange 4.6.5 External Heat Source 4.7 Coalescers 4.8 Sulfur Plant Operation and Control 4.9 Sulfur Plant Simulation by Computer

PART 2 SULFUR PLANT ENHANCEMENTS AND VARIATIONS 4.10 Introduction 4.11 Gas Preheating 4.12 Oxygen Enrichment 4.12.1 Linde Claus Oxygen Enrichment 4.12.2 Air Products and Chemicals Inc. COPE® Process 4.12.3 The SURE™ Double Combustion Process 4.13 Acid Gas Enrichment 4.14 SUPERCLAUS® Process 4.15 Summary Comments about Modified Claus Process 4.16 Selectox™ and Recycle Selectox™ Process

PART 3 TAIL GAS CLEAN-UP 4.17 Introduction 4.18 Tail Gas Clean-up by Extending the Claus Reaction in the Sub-dewpoint Temperature.. Region 4.18.1 The Mineral & Chemical Resources Company (MCRC) Process 4.18.2 The Amoco Cold Bed Adsorption (CBA) Process 4.18.3 The SNPA and Lurgi SULFREEN Process 4.18.4 Prosernat SmartSulf™ Process (formerly The Linde Clinsulf™ Process) 4.18.5 The Prosernat Clauspol (formerly IFP) Process 4.19 Tail Gas Clean-up by Reduction of Sulfur Compounds to H2S 4.19.1 EUROCLAUS® Process 4.19.2 The Shell Claus Off-gas Treating (SCOT) Process 4.20 Relative Cost of Various Sulfur Recovery Processes and Recovery Efficiency 4.21 Other TGCU Processes similar to the SCOT Process 4.21.1 The Beavon Sulfur Removal Process (BSRP) 4.21.2 The Beavon/MDEA Process 4.21.3 The Beavon Sulfur Removal (BSR)/Selectox Process 4.21.4 The PROSERNAT Sultimate [pProcess 4.21.5 The Resulf and Resulf 10 Processes 4.21.6 The High Claus Ratio (HCR) Siirtek Nigi Process 4.21.7 The Mobil Direct-Oxidation Process (MODOP) 4.22 Tail Gas Clean-up by Oxidation of Sulfur Compounds to SO2 4.22.1 The LUCAS Process 4.22.2 The Wellman-Lord Tail Gas Clean-up Process 4.22.3 DynaWave® Scrubber Technology 4.23 Determination of Sulfur Recovery Efficiency 4.24 Incinerator and Emission Stack

PART 4 RECOVERY PROCESSES FOR LOW SULFUR RATES 4.25 Processes for Low Rate Sulfur Rcovery 4.25.1 LO-CAT II® Process 4.25.2 SulFerox Process 4.25.3 SULFINT HP Process 4.25.4 CrystaSulf Process 4.25.5 Bio-SR Process 4.25.5 Shell-Paques/THIOPAQ Gas Desulfurization Process 4.26 Other TGCU Processes

PART 5 SULFUR PROPERTIES, HANDLING AND FORMINGERROR! BOOKMARK NOT DEFINED. 4.27 Properties of Solid, Liquid and Vapor Sulfur 4.27.1 Vapor Pressure 4.27.2 Density of Liquid Sulfur vs. Temperature 4.27.3 Viscosity of Liquid Sulfur 4.27.4 Melting Point, Boiling Point and Critical Conditions 4.28 Liquid Sulfur Production and Handling1 4.29 Liquid Sulfur Degassing 4.29.1 WorleyParsons (formerly Exxon) Process 4.29.2 Aquisulf (also SNEA) Process 4.29.3 Shell Process 4.29.4 Enersul (formerly Procor) HySPEC Process 4.29.5 Goar Allison & Associates D'GAASS® Degassing Process 4.29.6 Amoco (BP) Degassing Process 4.30 Sulfur Block Storage 4.31 Sulfur Purity and Premium Product Specifications 4.32 Sulfur Forms and Transportation 4.32.1 Sulfur Slates3 4.32.2 Polish Air Prills 4.32.3 Sandvik Rotoform Process 4.32.4 Granulation Process 4.32.5 Wet Prilling Process 4.33 Sulfur Production History for Alberta 4.34 World Sulfur Production REFERENCES

CHAPTER 5 - ACID GAS COMPRESSION AND INJECTION

PART 1 BASIC PROPERTIES OF ACID GAS 5.1 Introduction 5.2 Description of Acid Gas 5.3 Properties of Pure H2S and CO2 5.3.1 Vapor/Liquid Phases 5.3.2 Water Content 5.3.3 Hydrate Formation 5.3.4 Density and Heat Capacity 5.4 Properties of Acid Gas Mixtures 5.4.1 Vapor/Liquid Equilibria 5.4.2 Water Content of Acid Gas Mixtures 5.4.3 Hydrate Formation 5.4.4 Density and Heat Capacity 5.5 Effect of Hydrocarbons on Properties of Acid Gas Mixtures 5.6 Minimization of Hydrocarbon Content in Acid Gas Mixtures

PART 2 MITIGATION OF CORROSION AND HYDRATE FORMATION 5.7 Main Problems in Acid Gas Systems 5.7.1 Problem of Corrosion 5.7.2 Problem of Hydrates 5.8 Water Control Methods 5.8.1 Water Removal by Chilling 5.8.2 Water Removal by Dehydration with a Glycol Dehydrator 5.8.3 Water Removal by Dehydration with Dry Desiccant 5.8.4 Control of Water Content by Interstage Cooling 5.9 Analysis of Suitability of Water Control by Interstage Cooling

PART 3 DESIGN CONSIDERATIONS FOR ACID GAS COMPRESSION AND INJECTION FACILITIES 5.10 Number of Compression Stages and Effect on Water Content 5.11 Materials Selection for Compressor Package 5.12 Piping Layout for Disposal of Condensed Water and Gas Recycling 5.13 Acid Gas Recycle 5.14 Special Considerations in Cooler Design for Final Stage Aftercooler 5.15 Pipeline to Injection Well 5.15.1 Material Selection 5.15.2 Pipeline Sizing 5.15.3 Pipeline Insulation 5.15.4 Design Provision for Depressurizing the Pipeline 5.16 Wellsite Facilities 5.17 The Injection Well 5.18 Acid Gas Injection into Disposal Water

PART 4 OPERATION OF INJECTION FACILITIES 5.19 Acid Gas Compression 5.20 Acid Gas Injection Line 5.21 Acid Gas Injection Well 5.22 Potential for Sulfur Deposition 5.23 Backflow from Formation 5.24 Acid Gas Measurement 5.25 Summary Comments about Acid Gas Disposal by Compression and Injection REFERENCES

CHAPTER 6 - SAFETY IN SOUR GAS OPERATIONS

6.1 Introduction 6.2 General Health Effects of H2S on Humans 6.3 Industry Safety Practices 6.3.1 Materials and Construction 6.3.2 Safety Practices for Workers 6.3.3 Safety Practices Concerning the Public9 6.3.4 Safety in Design of Facilities 6.3.5 H2S Detection in Ambient Air 6.4 Emergency Response Plan 6.5 Safety in Facilities Operations REFERENCES

List of Figures

Figure 1.1 Chart Showing Sulfur Solubility at Saturation in Natural Gas Containing 35% H2S vs.Pressure and Different Compositions Figure 1.2 Chart Showing Sulfur Solubility at Saturation in Natural Gas Containing 1% H2S vs. Pressure and different Temperatures

Figure 2.1 Schematic Drawing of Typical Casing Strings Installed in a Well Figure 2.2 Schematic Drawing of a Well Completion with Hot Fluid Circulating String Figure 2.3 Schematic Drawing of Subsurface and Surface Facilities for Sour Gas Production Figure 2.4 Schematic Drawings of Typical Lease Facilities for a High Pressure Sour Gas Well, without and with a Wellsite Separator Figure 2.5 Schematic Drawing of Test Connections for Liquid/Gas Ratio Testing

Figure 2.6 Friction Factor vs. Reynolds Number and Relative Roughness Figure 2.7 Schematic Drawing of a Warm Water Tracer System Figure 2.8 Chart Showing Hydrate Temperature Depression vs. Methanol Concentration Figure 2.9 Ratio of Methanol Vapor Concentration to Methanol Liquid Concentration vs. P Figure 2.10 Liquid-Liquid Methanol Distribution Ratios

Figure 2.11 Schematic Drawing of Typical Glycol Dehydration Equipment Figure 2.12 Schematic Drawing of Typical Equipment for a Dry Desiccant Dehydration Unit Figure 2-13 Schematic Sketch of Cathodic Protection System for a Buried Pipeline Figure 2.14 Schematic Drawing of Sour Gas Line Block Valve and Instruments Figure 2.15 Schematic Drawing of a Typical Horizontal Plant Inlet Separator Figure 2.16 Liquid Holdup in Pipe vs. Root of Pressure Drop Ratio

Figure 3.1 Schematic Drawing Showing Overview of Sweetening and Sulfur Recovery Processes Figure 3.2 Schematic Drawing of Typical Sweetening Process Equipment Figure 3.3 Sketches of Molecular Structures of Amines Figure 3.4 Chart Showing Relative Density of Aqueous Solutions of Amine Solvents Figure 3.5 Schematic Drawing of Typical Physical Solvent Process Equipment

Figure 3.6 Graph Showing Vapor Pressure of Water vs. Temperature Figure 3.7 Schematic Drawing of SigmaPure System for Foamate Removal Figure 3.8 Schematic Drawing showing Options for Acid Gas Meter Installations Figure 3.9 Sketch Showing Relative Application of Sweetening Processes vs. H2S Concentration Figure 3.10 Schematic Drawing of Three Different Methods for H2S Scavenger Application

Figure 3.11 Schematic Drawing of Typical Iron Sponge Process Equipment Figure 3.12 Schematic Drawing of Typical Two-Tower Lead-Lag SulfaTreat Process Equipment Figure 3.13 Schematic Drawing of Typical SulfaTreat Vessel Configuration Figure 3.14 Schematic Drawing of Typical Liquid Scavenger Process Tower Figure 3.15 Schematic Drawing Showing Typical SulfaScrub Process Equipment

Figure 4.1 Chart Showing the Theoretical Equilibrium Conversion of H2S to Sulfur vs. Temperature Figure 4.2 Schematic Drawing of Typical Three-Stage “Straight-Through” Modified Claus Sulfur Recovery Process Equipment Figure 4.3 Schematic Drawing of Typical Three-Stage “Split-Flow” Modified Claus Sulfur Recovery Process Equipment Figure 4.4 Graph Showing Sulfur Recovery Efficiency vs. Excess Air Figure 4.5 Schematic Drawing of Typical Burner, Reaction Furnace and Waste Heat Boiler

Figure 4.6 Sketch Showing Qualitative Effect of CO2 Content in Acid Gas and Retention Time on Flame Conversion of H2S to Sulfur in Reaction Furnace Figure 4.7 Chart Showing Estimated Sulfur Recovery vs. H2S Content in Acid Gas and Number of Conversion Stages in a Modified Claus Plant without Enhancements Figure 4.8 Schematic Drawing Showing Typical Reheat Method with Hot Gas Bypass Figure 4.9 Schematic Drawing Showing Typical Reheat Method with Acid Gas Inline Burners Figure 4.10 Schematic Drawing Showing Typical Reheat Method with Hot Gas Bypass and Heat Exchange Figure 4.11 Graph Showing Sulfur in Saturated Vapor in Tail Gas as Percent of Sulfur in Feed to the Claus Plant Figure 4.12 Schematic Drawing Showing Equipment for Sulfur Plant Operational Control Figure 4.13 Schematic Drawing of a Typical Acid Gas Enrichment Process Figure 4.14 Schematic Drawing Showing Equipment for SUPERCLAUS Process Figure 4.15 Schematic Drawing Showing Process Equipment for Recycle Selectox™ Sulfur Recovery Facilities

Figure 4.16 Schematic Drawing of Three-Converter Claus Process with MCRC TGCU Equipment Figure 4.17 Schematic Drawing Showing Process Cycle for Four-Converter Claus MCRC TGCU Equipment Figure 4.18 Schematic Drawing Showing Four-Converter Claus CBA TGCU Process Equipment for Regeneration and Cooling of CBA Converter 1 Figure 4.19 Schematic Drawing Showing Four-Converter Claus CBA TGCU Process Equipment for Regeneration and Cooling CBA Converter 2 Figure 4.20 Schematic Drawing Showing Complete Cycle for One Converter of Sulfreen TGCU Process Equipment

Figure 4.21 Schematic Drawing Showing Typical SmartSulf™ Process Equipment Figure 4.22 Schematic Drawing of Prosernat Clauspol Process Equipment Figure 4.23 Schematic Drawing of EUROCLAUS Process Equipment Figure 4.24 Schematic Drawing of Shell Claus Off-Gas (SCOT) Treating Process Equipment Figure 4.25 Chart of Relative Costs of Some Sulfur Recovery Processes vs. Recovery .Efficiency and Acid Gas Quality

Figure 4.26 Schematic Drawing of LO-CAT II® Autocirculation Process Equipment Figure 4.27 Schematic Drawing of SULFEROX Process Equipment Figure 4.28 Schematic Drawing of SULFINT HP Process Equipment Figure 4.29 Schematic Drawing of CrystaSulf Process Equipment Figure 4.30 Schematic Drawing of BIO-SR Process Equipment

Figure 4.31 Schematic Drawing of Shell-Paques/THIOPAQ Gas Desulfurization Process Equipment Figure 4.32 Sketch of the H2S Path Options from Sour Gas to Sulfur Figure 4.33 Density of Pure Liquid Sulfur vs. Temperature Figure 4.34 Schematic Drawing of Steam-Jacketed Sulfur Rundown Line through Seal Pot Figure 4.35 Schematic Drawing of WorleyParsons Degassing Process Equipment

Figure 4.36 Schematic Drawing of Aquisulf Degassing Process Equipment Figure 4.37 Schematic Drawing of Shell Degassing Process Equipment Figure 4.38 Schematic Drawing of Enersul HySPEC™ Degassing Process Equipment Figure 4.39 Schematic Drawing of Goar Allison D’GAASS® Degassing Process Equipment Figure 4.40 Schematic Drawing of Amoco (BP) Degassing Process Equipment

Figure 4.41 Sketch of a Typical Sulfur Storage Block Figure 4.42 Illustration of Five Different Sulfur Forms Figure 4.43 Illustration of Sandvik Sulfur Flaking Process Equipment Figure 4.44 Illustration of a Polish Air Prilling Tower Figure 4.45 Illustration of Process Equipment for Generating Sandvik Rotoform Pastilles

Figure 4.46 Annual Sulfur Production by Sour Gas Plants in Alberta, Canada, from 1972 to 2012 Figure 4.47 Sources of Sulfur Production in Alberta Figure 4.48 Chart Showing Inventory of Sulfur in Alberta from 1973 to 2012 Figure 4.49 Chart Showing the Price of Sulfur at Different Locations Figure 4.50 Chart Showing Comparison of World Sulfur Recovery from Sour Gas (left) and Total World Sulfur Production (right)

Figure 5.1 Schematic Drawing Showing Options for Handling Acid Gas Figure 5.2 Chart Showing Vapor Pressure Curves for H2S, CO2 and CH4 Figure 5.3 Chart Showing Water Content of H2S with P and T Figure 5.4 Chart Showing Water Content of CO2 with P and T Figure 5.5 Chart Showing Water Content of various Gases at 37.8°C (100°F) with P and T

Figure 5.6 Chart Showing Vapor Pressure Curves for H2S, CO2, CH4, and Hydrate Lines for H2S and CO2 Figure 5.7 Chart Showing Pressure – Enthalpy Diagram for CO2 Figure 5.8 Chart Showing Pressure – Enthalpy Diagram for H2S Figure 5.9 Chart Showing Phase Diagram for an Acid Gas Mixture Containing 50% H2S, 35% CO2 and 15% CH4

Figure 5.10 Chart Showing Phase Diagrams for Various Mixtures of H2S and CO2 Figure 5.11 Chart Showing Phase Envelope of an Acid Gas Mixture Containing 55.25% H2S and 44.75% CO2 (Mixture D of Figure 5.9) Figure 5.12 Chart Showing Phase Envelopes of Three Different Acid Gas Mixtures Figure 5.13 Chart Showing Dewpoint Lines vs. P and T for Various Acid Gas Comps Figure 5.14 Chart Showing Water Content of Sweet Gas vs. P and T Figure 5.15 Hydrate Temperature vs. Pressure for Acid Gas Mixtures Containing 2% CH4, H2S as Shown and Balance CO2

Figure 5.16 Chart Showing Mass Density for an Acid Gas Mixture Containing 49% H2S, 49% CO2 and 2% CH4 vs. Pressure and Temperature Figure 5.17 Chart Showing Pressure Enthalpy (P-H) Diagram for an Acid Gas Mixture Containing 49% H2S, 49% CO2 and 2% CH4 Figure 5.18 Schematic Drawing Showing Equipment for Water Control by Refrigeration Figure 5.19 Schematic Drawing Showing Typical Equipment for Acid Gas Dehydration by Glycol Figure 5.20 Schematic Drawing Showing Typical Equipment for Acid Gas Dehydration by Dry Desiccant, with Acid Gas Regeneration

Figure 5.21 Schematic Drawing Showing Typical Equipment for Acid Gas Dehydration by Dry Desiccant, with Sour Gas Regeneration Figure 5.22 Chart Showing Water Content at Saturation of an Acid Gas Mixture Containing 49% H2S, 49% CO2 and 2% CH4, log-log Coordinates Figure 5.23 Chart Showing Water Content at Saturation of an Acid Gas Mixture Containing 49% H2S, 49% CO2 and 2% CH4, Linear Coordinates Figure 5.24 Chart Showing Water Content of Acid Gas Mixtures at 30°C Containing 2% CH4, H2S as indicated and Balance CO2, on log-log Coordinates Figure 5.25 Chart Showing Water Content of Acid Gas Mixtures at 30°C Containing 2% CH4, H2S as Indicated and Balance CO2, on Linear Coordinates

Figure 5.26 Chart Showing P-T Diagram and Hydrate Line for an Acid Gas Containing 49% H2S, 49% CO2 and 2% CH4 Figure 5.27 Guide for Estimating Cooling Requirements after Three Stages of Compression for Water Control by Interstage Cooling of Acid Gas containing H2S, CO2 and 2% CH4 Figure 5.28 Diagram of Phase Envelope, Hydrate Line and Pressure Steps for Acid Gas Mixture of Composition as Shown on Chart Figure 5.29 Tabulation of Results of Compression Stages and Data for Figure 5.28 Figure 5.30 Diagram of Phase Envelope, Hydrate Line and Pressure Steps for Acid Gas Mixture of Composition as Shown on Chart

Figure 5.31 Tabulation of Results of Compression Stages and Data for Figure 5.30 Figure 5.32 Diagram of Phase Envelope, Hydrate Line and Pressure Steps for Acid Gas Mixture of Composition as Shown on Chart Figure 5.33 Tabulation of Results of Compression Stages and Data for Figure 5.32 Figure 5.34 Simulation of Injection of Acid Gas with 49% each of H2S and CO2 plus Hydrocarbons, at 30 103 Sm3/d, Showing Input and Output Data Figure 5.35 Simulation of Injection of Acid Gas with 49% each of H2S and CO2 plus Hydrocarbons, at 30 103 Sm3/d, Showing Input and Output Data for Figure 5.34

Figure 5.36 Simulation of Injection of Acid Gas with 49% each of H2S and CO2 plus Hydrocarbons, at 5 103 Sm3/d, Showing Input and Output Data Figure 5.37 Simulation of Injection of Acid Gas with 49% each of H2S and CO2 plus Hydrocarbons, at 5 103 Sm3/d, Showing Input and Output Data for Figure 5.36 Figure 5.38 Simulation of Injection of Acid Gas with 49% each of H2S and CO2 plus Hydrocarbons, at 5 103 Sm3/d, Showing Input and Output Data, with Backpressure on the Injection Line Figure 5.39 Simulation of Injection of Acid Gas with 49% each of H2S and CO2 plus Hydrocarbons, at 5 103 Sm3/d, Showing Input and Output Data, for Figure 5.38, with Backpressure on Injection Line Figure 5.40 Pressure-Enthalpy Diagram for an Acid Gas Containing 49% each of H2S and CO2 plus Hydrocarbons, and the Pressure-Temperature Path of the Gas in Figure 5.38 and Figure 5.39

Figure 5.41 Diagram of Phase Envelope, Hydrate Line and Pressure Steps for Acid Gas Mixture of Composition as Shown on Chart Figure 5.42 Calculation Results for Figure 5.41 Figure 5.43 Pressure-Enthalpy Diagram for an Acid Gas Mixture Containing 30% H2S, 68% CO2, plus Hydrocarbons, and the Pressure-Temperature Path from Compressor Discharge Pressure Through Cooling, Condensation, and Pressure Reduction to Injection Pressure Figure 5.44 Chart Showing Hydrate Line, Process Steps and Phase Envelope for Acid Gas Containing 49% H2S and 49% CO2 plus Hydrocarbons, with Four Stages of Compression Figure 5.45 Calculation Results for Figure 5.44

Figure 5.46 Chart Showing Hydrate Line, Process Steps and Phase Envelope for Acid Gas Containing 49% H2S and 49% CO2 plus Hydrocarbons, with Five Stages of Compression Figure 5.47 Calculation Results for Figure 5.46 Figure 5.48 Chart Showing Pressure-Enthalpy (P-H) Diagram for an Acid Gas Containing 49% each H2S and CO2 plus Hydrocarbons, and Process Steps in Four Stages of Compression from 150 kPa to 9 600 kPa, for Figure 5.46 Figure 5.49 Schematic Drawing of Compression Facilities in a Four-Stage Unit showing Moisture-Saturated (blue line) and Undersaturated (red line) Acid Gas Flow Figure 5.50 Schematic Drawing of Piping for Condensed Water Handling, Gas Recycling and Connections for Depressurizing Compressor and Pipeline Facilities

Figure 5.51 Typical Wellsite Equipment at an Acid Gas Injection Well Figure 5.52 Schematic Drawing of Typical Acid Gas Injection Well Completion and Temperature Profiles Figure 5.53 Solubility of Acid Gas containing 20% H2S, 79% CO2 and 1% CH4 in fresh Water Figure 5.54 Solubility of Acid Gas containing 50% H2S, 49% CO2 and 1% CH4 in fresh Water Figure 5.55 Solubility of Acid Gas containing 80% H2S, 19% CO2 and 1% CH4 in fresh Water

On the following six pages are shown example illustrations (Figures) from the text, one for each Chapter.

CHAPTER 1

Figure 1.1 Chart Showing Sulfur Solubility at Saturation in Natural Gas Containing 35% H2S vs. Pressure and Different Compositions. (Reproduced with permission from the Canadian Institute of Mining, Metallurgy and Petroleum.)

CHAPTER 2

Figure 2.2 Schematic Drawing of a Well Completion with Hot Fluid Circulating String.

CHAPTER 3

Figure 3.2 Schematic Drawing of Typical Sweetening Process Equipment.

CHAPTER 4

Figure 4.17 Schematic Drawing Showing Process Cycle for Four-Converter Claus MCRC TGCU Equipment.

CHAPTER 5

Figure 5.1 Schematic Drawing Showing Options for Handling Acid Gas.

CHAPTER 6

(There are no figures in Chapter 6, so the space allocated to Chapter 6 is used for an additional figure from Chapter 5.)

CHAPTER 5

Figure 5.28 Diagram of Phase Envelope, Hydrate Line and Pressure Steps for Acid Gas Mixture of Composition as Shown on Chart.

To injection well

Figure 5.29 Tabulation of Results of Compression Stages and Data for Figure 5.28.