LEADER 05711nam 2200757Ia 450 001 9910141395703321 005 20200520144314.0 010 $a1-118-51115-8 010 $a1-283-64539-4 010 $a1-118-51113-1 010 $a1-118-51109-3 035 $a(CKB)2670000000242544 035 $a(EBL)1029515 035 $a(OCoLC)812482184 035 $a(SSID)ssj0000719046 035 $a(PQKBManifestationID)11417900 035 $a(PQKBTitleCode)TC0000719046 035 $a(PQKBWorkID)10762445 035 $a(PQKB)10733436 035 $a(MiAaPQ)EBC1029515 035 $a(Au-PeEL)EBL1029515 035 $a(CaPaEBR)ebr10604345 035 $a(CaONFJC)MIL395789 035 $a(PPN)175045887 035 $a(EXLCZ)992670000000242544 100 $a20120925d2012 uy 0 101 0 $aeng 135 $aur|n|---||||| 181 $ctxt 182 $cc 183 $acr 200 00$aSour gas and related technologies$b[electronic resource] /$fedited by Ying (Alice) Wu, John J. Carroll, and Weiyao Zhu 210 $aHoboken, N.J. $cJohn Wiley and Sons ;$aSalem, Mass. $cScrivener Pub.$dc2012 215 $a1 online resource (296 p.) 225 1 $aAdvances in Natural Gas Engineering 300 $aDescription based upon print version of record. 311 $a0-470-94814-0 320 $aIncludes bibliographical references and index. 327 $aSour Gas and Related Technologies; Contents; Preface; Introduction; Part 1: Data: Experiments and Correlation; 1. Equilibrium Water Content Measurements for Acid Gas at High Pressures and Temperatures; 1.1 Introduction; 1.2 Experimental; 1.3 Recent Results and Modelling; 1.3.1 Partitioning of Hydrogen Sulfide (H2S Solubility in Water); 1.3.2 Partitioning of Water (Water Content in H2S); 1.3.3 Discussion of Results; 1.4 Conclusions; References; 2. Comparative Study on Gas Deviation Factor Calculating Models for CO2 Rich Gas Reservoirs; 2.1 Introduction; 2.2 Deviation Factor Correlations 327 $a2.2.1 Empirical Formulas2.2.1.1 Dranchuk-Purvis-Robinsion (DPR) Model; 2.2.1.2 Dranchuk-Abu-Kassem (DAK) Model; 2.2.1.3 Hall-Yarborough (HY) Model; 2.2.1.4 Beggs and Brill (BB) Model; 2.2.1.5 Sarem Model; 2.2.1.6 Papay Model; 2.2.1.7 Li Xiangfang (LXF) Model; 2.2.1.8 Zhang Guodong Model; 2.2.2 Correction Methods; 2.2.2.1 Guo Xuqiang Method; 2.2.2.2 Carr-Kobayshi-Burrows Correction Method; 2.2.2.3 Wiehert-Aziz Correction Method [16]; 2.3 Model Optimization; 2.4 Conclusions; References; 3. H2S Viscosities and Densities at High-Temperatures and Pressures; 3.1 Introduction; 3.2 Experimental 327 $a3.3 Results and Discussion3.4 Conclusions and Outlook; 3.5 Acknowledgement; References; 4. Solubility of Methane in Propylene Carbonate; 4.1 Introduction; 4.2 Results and Discussion; 4.3 Nomenclature; 4.4 Acknowledgement; References; Part 2: Process; 5. A Holistic Look at Gas Treating Simulation; 5.1 Introduction; 5.2 Clean Versus Dirty Solvents: Heat Stable Salts; 5.2.1 CO2 Removal Using MEA, and MDEA Promoted With Piperazine; 5.2.2 Piperazine-promoted MDEA in an Ammonia Plant; 5.2.3 Post-combustion CO2 Capture; 5.2.4 LNG Absorber; 5.3 Summary 327 $a6. Controlled Freeze ZoneTM Commercial Demonstration Plant Advances Technology for the Commercialization of North American Sour Gas Resources6.1 Introduction - Gas Demand and Sour Gas Challenges; 6.2 Acid Gas Injection; 6.3 Controlled Freeze ZoneTM - Single Step Removal of CO2 and H2S; 6.4 Development Scenarios Suitable for Utilizing CFZTM Technology; 6.5 Commercial Demonstration Plant Design & Initial Performance Data; 6.6 Conclusions and Forward Plans; Bibliography; 7. Acid Gas Dehydration - A DexProTM Technology Update; 7.1 Introduction; 7.2 Necessity of Dehydration; 7.3 Dehydration Criteria 327 $a7.4 Acid Gas - Water Phase Behaviour7.5 Conventional Dehydration Methods; 7.5.1 Desiccant Adsorption; 7.5.2 Desiccant Absorption; 7.5.3 Separation Based Processes; 7.5.4 Avoidance Based Processes; 7.5.5 Thermodynamic/Refrigerative Based Processes; 7.6 Development of DexPro; 7.7 DexPro Operating Update; 7.8 DexPro Next Steps; 7.9 Murphy Tupper - 2012 Update; 7.10 Acknowledgements; 8. A Look at Solid CO2 Formation in Several High CO2 Concentration Depressuring Scenarios; 8.1 Introduction; 8.2 Methodology; 8.3 Thermodynamic Property Package Description; 8.4 Model Configuration; 8.5 Results 327 $a8.6 Discussion 330 $aCarbon dioxide has been implicated in the global climate change, and CO2 sequestration is a technology being explored to curb the anthropogenic emission of CO2 into the atmosphere. The injection of CO2 for enhanced oil recovery (EOR) has the duel benefit of sequestering the CO2 and extending the life of some older fields. This volume presents some of the latest information on these processes covering physical properties, operations, design, reservoir engineering, and geochemistry for AGI and the related technologies. 410 0$aAdvances in Natural Gas Engineering 606 $aNatural gas$vCongresses 606 $aGas wells$vCongresses 606 $aOil wells$vCongresses 606 $aOil field flooding$vCongresses 615 0$aNatural gas 615 0$aGas wells 615 0$aOil wells 615 0$aOil field flooding 676 $a665.7/3 701 $aWu$b Ying$cMSc.$0968787 701 $aCarroll$b John J.$f1958-$0920715 701 $aZhu$b Weiyao$0968788 712 12$aInternational Acid Gas Injection Symposium$d(3rd :$f2012 :$eBanff, Alta.) 801 0$bMiAaPQ 801 1$bMiAaPQ 801 2$bMiAaPQ 906 $aBOOK 912 $a9910141395703321 996 $aSour gas and related technologies$92200896 997 $aUNINA