Gas Injection into Geological Formations and Related Topics
Description
Written by some of the most well-known and respected chemical and process engineers working with natural gas today, the chapters in this important volume represent the most state-of-the-art processes and operations being used in the field. Not available anywhere else, this volume is a must-have for any chemical engineer, chemist, or process engineer in the industry. Advances in Natural Gas Engineering is an ongoing series of books meant to form the basis for the working library of any engineer working in natural gas today.
More details
Other editions
Additional editions
Persons
Ying (Alice) Wu is currently the President of Sphere Technology Connection Ltd. (STC) in Calgary, Canada. From 1983 to 1999 she was an Assistant Professor and Researcher at Southwest Petroleum Institute (now Southwest Petroleum University, SWPU) in Sichuan, China.
John J. Carroll, PhD, PEng is the Director at Geostorage Process Engineering for Gas Liquids Engineering, Ltd. in Calgary, Canada. His first book, Natural Gas Hydrates: A Guide for Engineers, is now in its second edition, and he is the author or co-author of 50 technical publications and about 40 technical presentations.
Mingqiang Hao, PhD, is a senior engineer of reservoir engineering and the deputy chief engineer of Oilfield Development at the Research Institute of Petroleum Exploration & Development (RIPED), PetroChina.
Weiyao Zhu is a Professor of Mechanics at the University of Science & Technology, Beijing, holding the Chair in the Department of Building Environment of Energy Engineering and the Institute of Applied Mechanics. He has published twelve books and over 330 research papers and has 17 patents and 26 software copyrights to his credit. He has also been recognized with many professional and academic awards.
Content
Preface xvii
1 Modifying Effects of Hydrogen Sulfide When Contemplating Subsurface Injection of Sulfur 1 Mitchell J. Stashick, Gabriel O. Sofekun and Robert A. Marriott
1.1 Introduction 2
1.2 Experimental 3
1.2.1 Materials 3
1.2.2 Rheometer 4
1.3 Results and Discussion 5
1.4 Conclusions 7
References 8
2 Experimental Determination of CO2 Solubility in Brines At High Temperatures and High Pressures and Induced Corrosion of Materials in Geothermal Equipment 9 Marie Poulain, Jean-Charles Dupin, Hervé Martinez and Pierre Cézac
2.1 Introduction 9
2.2 Experimental Section 11
2.2.1 Chemicals 11
2.2.2 Test Solutions 11
2.2.3 Metals 11
2.2.4 CO2 Solubility Measurements 12
2.2.5 Material Corrosion Study 13
2.3 Results and Discussion 15
2.3.1 CO2 Solubility Measurements 15
2.3.2 Material Corrosion Study 16
2.4 Conclusion 19
2.5 Acknowledgments 19
References 19
3 Experimental Study of the Liquid Vapour Equilibrium of the System Water-CO2-O2-NOx Under Pressure at 298 K 21 Esther Neyrolles, Georgio Bassil, François Contamine, Pierre Cézac and Philippe Arpentinier
3.1 Introduction 22
3.2 Literature Review 23
3.2.1 Carbon Dioxide and Water System 23
3.2.2 Nitrogen Oxides and Water System 24
3.2.3 Nitric Oxide Henry Constant at 298 K 25
3.3 Experimental Section 26
3.3.1 Chemicals 26
3.3.2 Apparatus 26
3.3.3 Operating Procedure 27
3.3.4 Experimental Analysis 29
3.3.4.1 Aqueous Analysis 29
3.3.4.2 Gas Phase Analysis 30
3.3.5 Estimation of the Concentrations of All the Species in the Aqueous Phase 31
3.3.6 Uncertainties 32
3.4 Results and Discussion 33
3.4.1 Solubility of Carbon Dioxide 33
3.4.2 Nitrogen Oxides Repartition in the Aqueous Phase 35
3.4.3 Nitric Oxide Henry Constant at 298 K 37
3.5 Conclusion 38
3.6 Acknowledgments 38
References 38
4 The Use of IR Spectroscopy to Follow the Absorption of CO2 in Amine Media - Evaluation of the Speciation with Time 41 E. Brugere, J-M. Andanson and K. Ballerat-Busserolles
4.1 Introduction 41
4.2 Materials and Methods 44
4.2.1 Chemicals 44
4.2.2 Sample Preparation 44
4.3 Experimental Device 44
4.4 Results and Discussion 46
4.4.1 Kinetic of Absorption 46
4.4.2 Calibration of Speciation 46
4.4.2.1 Sample Preparation 46
4.4.2.2 Spectra and Results 48
4.4.2.3 Physisorption 49
4.4.2.4 Full Curve Speciation 51
4.5 Conclusion 52
4.6 Acknowledgments 53
References 53
5 Solubility of Methane, Nitrogen, Hydrogen Sulfide and Carbon Dioxide in Mixtures of Dimethyl Ethers of Polyethylene Glycol 55 Alan E. Mather and Kurt A. G. Schmidt
5.1 Introduction 56
5.2 Experimental 56
5.3 Equation of State Development 57
5.4 EoS Model Results 62
5.5 Krichevsky-Ilinskaya Equation 67
5.6 Conclusions 70
5.7 Nomenclature 71
References 72
6 Water Content of Hydrogen Sulfide - A Review 77 Eugene Grynia and Bogdan Ambrozek
6.1 Introduction 77
6.2 Literature Review 78
6.2.1 Wright and Maass (1932) 79
6.2.2 Selleck et al. (1951, 1952) 82
6.2.3 Kozintseva (1964) 84
6.2.4 Clarke and Glew (1971) 88
6.2.5 Lee and Mather (1977) 89
6.2.6 Gillespie and Wilson (1982) 92
6.2.7 Carroll and Mather (1989) 94
6.2.8 Suleimenov and Krupp (1994) 96
6.2.9 Chapoy et al. (2005) 97
6.2.10 Marriott et al. (2012) 100
6.3 Discussion of the Results 102
6.4 Conclusions 108
References 112
7 Acid Gas Injection at SemCAMS Kaybob Amalgamated (KA) Gas Plant Operational Design Considerations 115 Rinat Yarmukhametov, James R. Maddocks and Jason Lui
7.1 Project Drivers 116
7.2 Process Design Basis 117
7.2.1 Acid Gas Inlet Design Conditions 117
7.2.2 Acid Gas Compositions 117
7.2.3 Acid Gas Compressor Discharge 118
7.2.3.1 Acid Gas Conditions 118
7.2.3.2 Acid Gas Composition 118
7.3 Acid Gas Compression Description 120
7.4 AGI System Capacity Control 120
7.5 Project Execution 123
7.6 Risk Assessment Strategy 125
7.7 Utilities & Tie-Ins 126
7.8 Relief System Design 127
7.8.1 KA Gas Plant Flare System 127
7.8.2 AGI System Flare System 128
7.8.3 Evaluation of Existing Plant Blowdowns Concurrent with the AGI Compressors Blowdown 128
7.8.4 Inherently Safer Design (ISD) Strategies in Pressure Relief System Design for AGI Systems 129
7.8.5 MDMT Evaluation 131
7.8.6 Drain Management 132
7.9 Discussion 133
7.10 Start-Up 133
7.11 Conclusions 135
8 Reciprocating Compressors in Acid Gas Service 137 Dan Hannon
8.1 Introduction 138
8.2 Reactivity 138
8.3 Safety 138
8.4 Design 139
8.5 Materials 140
8.6 Condensate/Dewpoint 141
8.7 Compressor Selection 142
8.8 Conclusion 144
9 Case Study: Wellbore Thermodynamic Analysis of Erhao Acid Gas Injection Project 145 Zhu Zhu and Shouxi Wang
9.1 Introduction 145
9.2 Erhao Station Process and Injection Basic Data 147
9.3 Acid Gas Injection Well and Reservoir 148
9.3.1 Injection Well 148
9.3.1.1 Basic Data 149
9.3.1.2 Characteristics 149
9.3.2 Injection Reservoir 150
9.4 Thermodynamic Analysis and Injection Pressure 151
9.4.1 Comprehensive Model 151
9.4.2 Initial Acid Gas 152
9.4.3 Compressed and Dehydrated Acid Gas 155
9.4.4 Comparison of Different Acid Gas Composition 158
9.4.5 Comparison of Different Wellhead Temperature 158
9.5 Conclusion 159
References 159
10 Selecting CO2 Sinks CCUS Deployment in South Mid-West Kansas 161 Eugene Holubnyak, Martin Dubois and Jennifer Hollenbach
10.1 Introduction 161
10.2 Process for Determining Potential Phase II Sites 165
10.2.1 Geologic Setting 165
10.3 Oil Production History and CO2 Enhanced Oil Recovery Potential in the Region 170
10.4 Estimating CO2 Storage Volume-Building the Static Model 171
10.4.1 Workflow for Building 3-D Static Model 171
10.4.2 Well Data 172
10.4.3 Petrophysics 173
10.4.4 Three-Dimensional Static Model 174
10.5 Estimating CO2 Storage Volume-Running the Dynamic Model 175
10.5.1 Initial Reservoir Conditions and Simulation Constraints 176
10.5.2 Simulation Results 177
10.6 Summary/Discussion 179
References 180
11 Salt Precipitation at an Active CO2 Injection Site 183 Stephen Talman, Alireza Rangriz Shokri, Rick Chalaturnyk and Erik Nickel
11.1 Introduction 184
11.2 Laboratory and Field Data 186
11.2.1 Data Sources 186
11.2.2 Chemical Composition of Formation Water 186
11.2.3 X-Ray Diffraction Analysis of Recovered Salt Samples 187
11.2.4 Downhole Video Analysis and Image Sizing 188
11.2.4.1 Material Fixed to the Wellbore 188
11.2.4.2 Lowest Reaches of the Well 190
11.2.4.3 Dislodged Materials 191
11.3 Implication and Interpretation 193
11.4 Conclusions and Remarks 196
11.5 Acknowledgments 198
References 198
12 The Development Features and Cost Analysis of CCUS Industry in China 201 Hao Mingqiang, Hu Yongle, Wang Shiyu and Song Lina
12.1 Introduction 202
12.2 Characteristics of CCUS Project 202
12.2.1 Distribution and Characteristics of CCUS Project 202
12.2.2 Types and Scales of CCUS Emission Sources 202
12.2.3 Emission Scales and Composition of CO2 Emission Enterprises in China 204
12.2.4 Distributions of CO2 Sources in China 204
12.2.5 Characteristic Comparison Between Projects in China and Abroad 205
12.3 Industry Patterns & Driving Modes 209
12.3.1 CCUS Industry Patterns at Home and Aboard 209
12.3.2 Driving Modes of CCUS Industry 210
12.4 Composition & Factors of CO2 Source Cost 213
12.5 Conclusions 215
References 216
13 CO2 Movement Monitoring and Verification in a Fractured Mississippian Carbonate Reservoir during EOR at Wellington Field in South Kansas 217 Yevhen Holubnyak, Eric Mackay, Oleg Ishkov and Willard Watney
13.1 Introduction 218
13.2 Wellington Field Faults and Fractures 219
13.3 EOR Field Operations and Production/Injection History 220
13.4 Geochemical Monitoring Survey Setup 221
13.5 Geochemical Monitoring Survey Observations 222
13.6 Conclusions 225
13.7 Acknowledgements 225
13.8 Disclaimer 225
References 226
14 Simulation Study On Carbon Dioxide Enhanced Oil Recovery 227 Maojie Chai and Zhangxin Chen
14.1 Introduction 227
14.2 Phase Behavior Study 229
14.3 Simulation Study 230
14.3.1 Fluid Sample Properties 230
14.3.2 Phase Behavior Simulation 230
14.3.3 Lab Scale Core Flooding Simulation 235
14.3.4 Sensitivity Analysis of Uncertain Parameters 240
14.3.5 Updated Relative Permeability Through History Match 241
14.4 Conclusions 243
References 243
15 Blowout Recovery for Acid Gas Injection Wells 245 Ray Mireault
15.1 Introduction 246
15.2 Methodology 247
15.3 Wellbore Behaviour 247
15.4 Acid Gas Flammability and Toxicity 249
15.5 Escape Plume Behaviour 250
15.6 Blowout Recovery Operations 252
15.6.1 Initial Reconnaissance 253
15.6.2 Heavy Equipment for AG Recovery Operations 253
15.7 Recommendations for Further Investigation 254
15.7.1 Acid Gas Escape Cloud Modelling 254
15.7.2 Personnel Training 255
15.7.3 Development of Recovery Equipment and Procedures 256
15.8 Acknowledgments 256
References 257
16 The Comprehensive Considerations of Leak Detection Solutions for Acid Gas Injection Pipelines 259 Shouxi Wang, John Carroll, Fan Ye, Lirong Yao, Jianqiang Teng and Haifeng Qiu
16.1 Introduction 260
16.2 Flowing and Layout Features, Leak Detection Strategies of the Acid Gas Pipelines 260
16.3 The Behavior of the Acid Gas Flows with Leakages 261
16.3.1 Leak Experiments on Liquid Pipeline 261
16.3.2 Leak Experiments on Gas Pipeline 262
16.3.3 Summary of Leak Responses 265
16.4 Specification, Measurement Requirements and Features of the Available Pipeline Leak Detection Methods 267
16.4.1 Mass Balance (MB) 267
16.4.2 Pressure Point Analysis (PPA) 268
16.4.3 Real-Time Model (RTM) 269
16.4.4 Data Requirements of the CPM Leak Detection Methods 270
16.4.5 Matrix Features of the Pipeline LDS 271
16.5 Evaluation of the Erhaolian AGI LDS System 271
16.5.1 Erhaolian AGI System 271
16.5.2 Measurement Responses to Different Leak Size and Location 271
16.5.3 The Performances of CPM Leak Detection Methods 278
16.6 Conclusion 281
16.7 Acknowledgments 281
References 282
17 Injection of Non-Condensable Gas in SAGD Using Modified Well Configurations - A Simulation Study 283 Yushuo Zhang and Brij Maini
17.1 Introduction 284
17.1.1 Background 284
17.1.2 Project Objectives 284
17.2 Relevant Field History 285
17.2.1 Depositional History 285
17.3 Reservoir Characterization 285
17.3.1 Geology Overview 285
17.3.1.1 Core Analysis 285
17.3.1.2 Log Analysis 285
17.3.1.3 Shale Volume Calculations 286
17.3.1.4 Porosity Calculations 286
17.3.1.5 Water and Oil Saturation 286
17.3.2 Permeability Data 287
17.3.3 PVT Data 287
17.3.4 Reservoir Values 288
17.4 Analytical Production Forecast 288
17.4.1 Butler Model 288
17.4.2 Reservoir Performance with NCG Co-Injection 291
17.5 Reservoir Simulation 291
17.5.1 Geological Model 291
17.5.2 Reservoir Property 292
17.5.3 Well Location 292
17.5.4 Initial Reservoir Simulation Inputs 293
17.5.5 Relative Permeability Data 293
17.5.6 Well Operational Parameters 294
17.5.7 History Match 295
17.5.7.1 Flowing Boundary Condition 295
17.5.7.2 Final History Match Results 295
17.5.8 SAGD Production Forecasts 297
17.5.8.1 Base Case HZ Well Production with Steam Only (Flowing Boundary) 298
17.5.8.2 Forecast Results: Production Rate 299
17.5.8.3 Forecast Results: Steam-to-Oil Ratio 299
17.5.9 Modified Well Simulation Forecast 299
17.5.9.1 Modified Well Configuration with Non-Flowing Boundary 299
17.5.9.2 Perforating Below Top Water Zone 299
17.5.9.3 Forecast Results: Production Rate 302
17.5.9.4 Forecast Results: Steam-to-Oil Ratio 302
17.5.9.5 Steam Chamber Development without NCG 303
17.5.9.6 Steam Chamber Development with NCG 304
17.5.9.7 Simulation Sensitivity Analysis in Non-Flowing Boundary 304
17.5.9.8 Summary of Simulation Results 306
17.6 Conclusion 306
References 308
18 The Study on the Gas Override Phenomenon in Condensate Gas Reservoir 311 Kun Huang, Weiyao Zhu, Qitao Zhang, Jing Xia and Kai Luo
18.1 Introduction 311
18.2 Experimental 312
18.2.1 Pressure-Volume-Temperature Tests 312
18.2.2 Pressure-Volume-Temperature Tests Design 313
18.3 Results and Discussion 313
18.3.1 Phase Behavior During the Injection Process 313
18.3.2 The Effect of Mass Transfer on the Phase Behavior 315
18.3.3 Composition of the Mixture in the Cylinder 317
18.4 Conclusions 319
References 319
19 Study on Characteristics of Water-Gas Flow in Tight Gas Reservoir with High Water Saturation 321 Qitao Zhang, Weiyao Zhu, Wenchao Liu, Yunqing Shi and Jin Yan
19.1 Introduction 322
19.2 Experiments 322
19.2.1 Materials 322
19.2.2 Experimental Procedure 323
19.2.3 Experimental Results and Analysis 324
19.3 Numerical Simulation for Tight Gas Reservoir with Low Gas Saturation 327
19.3.1 Model Description 327
19.3.2 Model Validation 328
19.3.3 Effect of Threshold Pressure Gradient 329
19.4 Conclusions 331
References 331
20 The Description and Modeling of Gas Override in Condensate Gas Reservoir 333 Weiyao Zhu, Kun Huang, Yan Sun and Qitao Zhang
20.1 Introduction 333
20.2 Mathematical Formulation 335
20.2.1 Numerical Scheme 337
20.3 Results and Discussion 337
20.3.1 The Development and Assessment of Gas Override 337
20.3.2 Sensitivity Analysis 339
20.3.2.1 The Influence of Density Difference on Gas Override 340
20.4 Conclusions 341
References 342
21 Research on the Movable Water in the Pores of Tight Sandstone Gas Reservoirs 343 Guodong Zou, Weiyao Zhu, Wenchao Liu, Yunqing Shi and Jin Yan
21.1 Introduction 343
21.2 Experimental 344
21.2.1 Experimental Equipment 344
21.2.2 Experimental Procedure 345
21.3 Results and Discussion 346
21.3.1 Change of the Saturated Water 346
21.3.2 Test of the Movable Water 348
21.4 Conclusion 349
References 350
22 Probabilistic Petroleum Portfolio Options Evaluation Model (POEM) 351 Darryl Burns
22.1 Project Economic Evaluation Tool (PEET) 351
22.2 Portfolio Options Evaluation Tool (POET) 352
22.3 Program Calculation Procedures 352
22.3.1 General Cash Flow Calculation and Profitability Indicators 352
22.3.1.1 General Cash Flow Calculation 352
22.4 General Calculation Steps 353
Index 361
1
Modifying Effects of Hydrogen Sulfide When Contemplating Subsurface Injection of Sulfur
Mitchell J. Stashick, Gabriel O. Sofekun and Robert A. Marriott*
Department of Chemistry, University of Calgary, Calgary, Alberta, Canada
Abstract
Transportation and handling of molten sulfur is inevitably challenging due to the anomalous rheological behaviour of sulfur with changing temperature. After melting at 115 °C, sulfur's viscosity remains close to 10 cP. The onset of the ?-transition region is observed at T ~ 160 °C. The viscosity drastically rises in this region, increasing to a maximum of about 93000 cP at 187 °C. This anomaly is due to the cleavage of sulfur rings and production of reactive diradical sulfur species that concatenate to create sulfur polymers. The entanglement of these sulfur chains causes the dramatic rise in viscosity. Within this work, new data is reported that examines the modifying effects of hydrogen sulfide (H2S) within liquid sulfur. This may be used when considering the potential injection of liquid sulfur into depleted reservoirs for safe long-term storage. H2S, when present in liquid sulfur, can either physically dissolve or chemically react to generate polysulfane. The chemical reaction causes significant changes in the sulfur chain distribution and consequently changes the viscosity curve of liquid sulfur as a function of temperature. This study reports viscosity measurements performed from 120 < T < 280 °C with concentrations of H2S in sulfur ranging from 0 ppmw to 284 ppmw.
Keywords: Rheology, viscosity, ?-transition, sulfur, polymers, hydrogen sulfide
1.1 Introduction
Sulfur requires transportation and handling on an industrial scale. After acknowledging that there were approximately eighty million metric tons of elemental sulfur produced globally in 2018, this becomes abundantly clear [1]. Sulfur recovery from oil refineries and sour gas treatment plants (sour gas is natural gas with hydrogen sulfide (H2S) > 5.7 mgm-3) has continued to increase, bringing about more deliberation on the utilization and/ or storage of sulfur product. When the value of sulfur is not high enough to economically justify transportation and sale of the material, it is often common to block pour for long-term storage. Block pouring sulfur is a relatively inexpensive method where sulfur is solidified within retaining walls on large plots of land. However, there are some disadvantages to this technique. The land on which the blocks are poured must be leased or owned and this can cause some financial strain. Also, bacteria classified as Thiobacilli are known to metabolize sulfur by oxidizing the material to sulfate and in doing so produce sulfuric acid (H2SO4). This along with rain and further weathering results in the need for water treatment of the acid runoff, incurring additional cost. Lastly, large amounts of weathering sustained by sulfur blocks can yield high content of materials such as dirt, sand and moisture. This can create issues of purity if the price of sulfur rises and it makes economic sense to sell the product again [2]. Alternatively, producers have chosen to inject H2S (acid gas injection) to mitigate stranded sulfur. With acid gas injection, one needs to consider the energy required for compression of gas, storage under pressure and the loss of energy due to eliminating the Claus plant.
In future operations, an alternative to block pouring or acid gas injection could include the potential injection of liquid elemental sulfur into depleted reservoirs for safe long-term storage. This method would diminish some of the issues experienced with block pouring, but would likely sustain other costs needed for infrastructure and operation. Also, other fundamental understanding is currently lacking in order to pursue this approach. The conditions under which an injection such as this would take place must be known and understood in how they will impact the rheological behavior of sulfur.
One of several conditions to consider is that all sulfur produced in Sulfur Recovery Units at refineries and gas processing facilities will contain some residual H2S. This is because sulfur is recovered before complete conversion from H2S. Generally, recovered sulfur from a plant process can have up to 380 ppmw of dissolved H2S depending on the facility set up [3]. Another condition to consider is the temperature of the depleted underground reservoir. For this, the range of interest for potential injection was found to be around 120 < T < 280 °C. It should be recognized that this temperature range includes the ?-transition region of liquid sulfur. Also, high shear must be considered as this will be encountered in sulfur pumps and the near-wellbore region. Studying sulfur's shear flow with and without H2S over the specified temperature range could therefore greatly improve the fundamental understanding needed for injection of molten sulfur.
The viscosity temperature dependence of sulfur within the ?-transition region can be explained by a scission-recombination equilibrium for polymers and the term reptation. In this occurrence, reptation is defined as the thermal motion of entangled macromolecular sulfur chains. At T > 160 °C, cleavage of sulfur S8 rings results in the generation of reactive diradical sulfur species that combine to create sulfur polymers [4]. The average polymer chain lengths increases as a function of temperature leading to more entanglement and higher viscosity values. At 187°C, the maximum polymer chain length is reached, along with the maximum viscosity. Beyond this temperature, the viscosity decreases due to the thermal scission of polymer chains; however, if H2S is present, the viscosity profile of sulfur changes depending on concentration. H2S is known to chemically react with diradical sulfur species during the ?-transition to produce polysulfane, as shown in Eq. (1-1). This reaction terminates the polymerization, which reduces the average sulfur polymer chain length. Therefore, a reduction in the viscosity of the liquid is observed [5-7].
(1.1)1.2 Experimental
1.2.1 Materials
Oxygen-free, nitrogen gas (N2; 99.998% as per certificate of analysis) was purchased from Praxair Technology, Inc. Hydrogen sulfide gas (H2S; 99.6% containing N2, Ar and trace CO2 as per certificate of analysis and in-house gas chromatography analysis) was purchased from Praxair Technology, Inc.
Sulfur used for this study was air prilled and supplied by Keyera Energy from their Strachan, Alberta, gas plant in 2017. Analyses of the air prills were performed and reported in Table 1.1. Moisture (volatiles) content, total nonpolymer sulfur content/overall purity, and ash content were determined by methods used at ASRL, reported by Sofekun et al. [4]. Total carbon content and H2S content were also performed on the sulfur prills. Additionally, it was necessary to perform analyses of H2S content before and after rheometric measurements. Total carbon content was measured using an analysis method established by Dowling et al. [8]. H2S content was measured using an analysis method detailed by Sofekun et al., Marriott et al., and Tuoro and Wiewioroski [3, 4, 9, 10]. Large sulfur samples that had been equilibrated with H2S were partially used to record infrared spectra (six total measurements) prior to each set of rheometric measurements. All samples were analyzed using a Nicolet 380 FT-IR (Thermo Electron Corp.) spectrometer.
Table 1.1 Analytical results of the Keyera air prilled sulfur.
Moisture Content (wt. %) Purity (wt. %) Ash Content (ppmw) Total Carbon Content (ppmw) Total H2S Content (ppmw) 0.14 99.995 8 34 < 0.21.2.2 Rheometer
The experimental system was composed of an Anton-Paar MCR 302 rheometer with a custom built gravity-fed charging rig, a high-pressure N cylinder and a thermostated Fourier Transform Infrared (FT-IR) cell used2 fromprevious studies [4, 9, 10]. A head pressure tee for inducing H2S partial pressures along with a purging setup connected to KOH traps for removal of H2S before venting was added. This permitted the safe introduction of differing concentrations of H2S in liquid sulfur samples. All valves and tubing used for both the pressure tee and gravity-fed charging rig were made of 316L stainless steel. The system was housed inside a negative-pressure bay equipped with automatic toxic gas detectors.
Geometry and measuring limitations for the Anton-Paar MCR 302 were detailed by Sofekun et al. [4]. Air checks and motor adjustments were performed at a rotational speed of 0.3 min-1 at set time intervals as recommended by the instrument manufacturer. This confirmed on a regular basis that the rheometer was in good working condition.
The procurement of viscosity data sets corresponding to each differing H2S concentration in sulfur were carried out using the following experimental procedure: Two hundred grams of high purity sulfur prills were placed in an oven overnight at 135 °C. The experimental system was prepared for rheometric measurements of liquid elemental sulfur by inputting set points for the temperature controllers on the gravity-fed charging rig and rheometer cylinder jacket of 135 °C. After...
