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NATURAL GAS DEHYDRATION
NATURAL GAS DEHYDRATION
NATURAL GAS DEHYDRATION
NATURAL GAS DEHYDRATION
NATURAL GAS DEHYDRATION
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NATURAL GAS DEHYDRATION

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ALL ABOUT NATURAL GAS : DEFINITION,FORMATION,PROPERTIES,COMPOSITION,PHASE BEHAVIOR ,CONDITIONING"DEHYDRATION ,SWETENING" AND FINAL PROCESSING TO END USER PRODUCTS

ALL ABOUT NATURAL GAS : DEFINITION,FORMATION,PROPERTIES,COMPOSITION,PHASE BEHAVIOR ,CONDITIONING"DEHYDRATION ,SWETENING" AND FINAL PROCESSING TO END USER PRODUCTS

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  • NCB prepared by:Ahmed Shoman
  • NCB prepared by:Ahmed Shoman Smail
  • NCB prepared by:Ahmed Shoman
  • NCB prepared by:Ahmed Shoman
  • NCB prepared by:Ahmed Shoman
  • NCB prepared by:Ahmed Shoman
  • NCB prepared by:Ahmed Shoman 1- Trays types. 2- rest of dehydration clip. 3- amine unit troubleshooting . 4- amine unit vedio clip .
  • NCB prepared by:Ahmed Shoman
  • Transcript

    • 1. Prepared by // Eng. Ahmed Mohamed Shoman 1
    • 2. Content• Definitions of Frequently Used Parameters in Natural Gas Industry.• Introduction for natural gas. 1. Natural Gas Terminology. 2. Natural Gas Formation. 3. Natural Gas Composition. 4. Natural Gas Properties. 5. Natural Gas Phase Behavior..• Natural Gas Conditioning. • Field Separation. • Gas Sweetening. • Gas Dehydration.Sweetening /Dehydration Trouble Shooting (Amine & Glycol Unit). – Gas is not Sweet – Amine solution not regenerated – Dirty, degraded amine – Excessive Corrosion – Foaming of amine solution – Inlet gas temperature too low – Wrong or off-spec – chemicals – Misuse or abuse of antifoam chemicals in amine units – Incoming gas is not adequately scrubbed and contains salt water 2 – Tray down comers are plugged, causing amine to stack up in the trays .
    • 3. Content• Natural Gas Processing.  By Refrigerated lean oil Absorption.  By J.T and LTS.  By Turbo Expander.• Examples for Gas Plants  Ras Shukier Gas Plant . "GUPCo"  Amreya Gas Plant.  Port Said NGL Plant.  The UGD Company.  Syrian "Dier El-zour " D.Z Gas Plant.  Ras Shukier NGL Plant "EBGDCO" • NGL Recovery – NGL and LPG recovery technology. – GTL production technologies. - Separation of NGL 3
    • 4. Content • Fractionation Towers. – Types of Fractionation Tower. – Types of Trays. – Tray Towers Operation Problems. – Packing Types• Sulfur Recovery Unit “SRU”: – Sulfur content in natural Gas & its Economic Value. – SRU “ Clause process”• Natural Gas Compression• o Introduction• o Reciprocating Compressors• o Centrifugal Compressors• o Comparison between Compressors• o Compressor Selection• o Multistage Compression• o Compressors Calculations• o Compressor Performance Maps 4
    • 5. Definitions1- Associated Gases : Gas associated with liquids.2- Non associated gases: Gas produced from gas wells without liquids.3- Dry gas : Natural gas is considered dry when it isalmost pure methane, having most of the other commonly associatedhydrocarbons removed.4- Wet gas : When other hydrocarbons are present, the natural gas is wet.5- Sour gas : Natural gas which contains H2S and CO2(acid gases).6- Sweet gas : natural gas which doesn’t contains H2S and CO2. 5
    • 6. Definitions7- Hydrated gas : Natural gas which contains H2O.8- Dehydrated gas: Natural gas after removal of H2O.9- LNG : Liquefied natural gas , mainly CH410- LPG : Liquefied petroleum gases , “Commercial Propane- Butane mixture”11- Condensate : pentanes and heavier , C5+12- GTL : Gas to liquids.13- NGL : Natural gas liquids , ethane and heavier.14- SRU : Sulfer Recovery Unit 6
    • 7. Definitions15- Acid Gas : Feed stream to sulfur recovery plant consisting H2S, CO2,H2O, and usually less than 2 mol % hydrocarbons.16-Claus Process:The process in which 1⁄3 of the H2S in the acid gas feed is burned to SO2which is then reacted with the remaining H2S to produce sulfur. This is alsoreferred to as the modified Claus process. ( H2S + 1⁄2 O2 → S + H2O )17-Residence Time: the period of time in which a process stream will becontained within a certain volume or piece of equipment, seconds.18-Tail Gas Cleanup Unit: a process unit designed to take tail gas from aClaus sulfur recovery plant and remove additional sulfur with the goal ofmeeting environmental sulfur emission standards. 7
    • 8. Introduction: Natural Gas is a vital component of the worlds supply of energy. It is one of the cleanest, safest, and most useful of all energy sources. What is Natural Gas: Natural gas is a combustible mixture of hydrocarbon gases( from CH4 to C8H18”OCTANE) consisting essentially of METHANE ,other hydrocarbons and non Hydrocarbon Gases in gaseous state ,which isextracted from the subsurface of the earth in its natural state ,separately or together with liquid hydrocarbons 8
    • 9. The Formation of Natural Gas:Natural gas is a fossil fuel like oil and coal.Fossil fuels are, essentially, the remains ofplants ,animals and microorganisms thatlived millions and millions of years ago. 9
    • 10. Natural Gas Under the Earth:Although there are several ways that methane,and thus natural gas, may be formed, it isusually found underneath the surface of theearth. As natural gas has a low density, onceformed it will rise towards the surface of theearth through loose , shale type rock and othermaterial.With natural gas trapped under the earth in thisfashion, it can be recovered by drilling a holethrough the impermeable rock. Gas in thesereservoirs is typically under pressure, allowing itto escape from the reservoir on its own. 10
    • 11. Typical Composition of Natural Gas : Water Impurities CO2,H2S, Hg Nitrogen Methane LNG Ethane NGL’s Propane Butane LPG Pentane Hexane C5 + Heptane Octane 11
    • 12. Typical Composition of Natural Gas : 12
    • 13. Oxygen: Max. ( 0.1% ) by mole.* Carbon dioxide: Max. ( 3 % ) by mole.* Hydrogen sulphide: Max. ( 4 ) PPM* Sulphur: Max. (50 ) mgm / SCM* H.C. dew point: Mercury: Max. (6 ) mgm / SCM* Gross Heating Value : Min. 980 ( +5 ) Deg.C* Max. 1180 BTU/SCF* .( zero ) Deg. C at a pressure of ( 70 ) kg /cm2 gauge Water dew point : Max. ( 1 ) PPM or below 13
    • 14. Natural Gas Properties 14
    • 15. Ideal Gas Law PV = Where : nRT P : Absolute pressure V : Volume T : Absolute temperature R : Universal gas constant n : Number of moles n = m / M m : Mass of the gas M: Molecular weightThe ideal gas law can be expressed as : PV = (m/M) RT m = MPV/RT m/V = ρ = MP/RT ρ is density of gas 15
    • 16. Behavior of Real Gases PV = ZnRTWhere : Z is deviation or compressibility factor and can be expressed as Z = [ actual volume of n moles of gas / (ideal volume of n moles of gas at certain P & T) at same P & T ]where Z is dimensionless. 16
    • 17. Properties of Gaseous MixturesComposition of natural gas may be expressed as either mole fraction, volumefraction or weight fraction. Mole Fraction yi = ni/∑ni where: yi : Mole fraction of component i ni : Number of moles of component i ∑ni : Total number of moles of all components in the mixtures Volume fraction vi = vi/∑vi Weight Fraction w i =Wi/∑Wi 17
    • 18. Determination of Z FactorFrom the next chart after determination of Pr and Tr we can determine Z factor Pr = P / P c Tr Tr = T / T c Z Where : Pc= ∑Pci*Yi Tc= ∑Tci*Yi Pr 18
    • 19. Natural Gas Phase Behavior The natural gas phase behavior is a plot of pressure vs temperature thatdetermines whether the natural gas stream at a given pressure andtemperature consists of a single gas phase or two phases: gas and liquid.The phase behavior for natural gas with a given composition is typicallydisplayed on a phase diagram, an example of which is shown in Figure 1-1. The left-hand side of the curve is the bubble point line and divides thesingle phase liquid region from the two-phase gas–liquid region.The right-hand side of the curve is the dew point line and divides the two-phase gas–liquid region and the single-phase gas region. 19
    • 20. 20
    • 21. :At point XXi=xy/zy Retrograde region idYi=xz/zy liq u z Gas x y 21
    • 22. DefinitionsPhase Diagram-1A record of the effects of temperature, pressure and composition on the kinds and.numbers of phases that can exist in equilibrium with each otherBubble Point-2The point at which the first small vapour bubble appears in a liquid system. The.bubble point curve on a phase diagram represents 0% vapourDew Point-3The point at which the first infinitesimally small droplet of condensation forms in agaseous system. The dew point curve on a phase diagram represents 0%.liquidPhase Envelope-4The area on a pressure-temperature phase diagram for a mixture enclosed by thebubble and dew point curves. This area represents the set of conditions for the. mixture were vapour and liquid phases co-exist in equilibrium )Cricondenbar (Pmax-5.The maximum pressure at which vapour and liquid can co-exist in equilibrium 22
    • 23. Definitions6-Cricondentherm (Tmax).The maximum temperature at which vapour and liquid can co-exist in equilibriumCritical Pressure-7.The vapour pressure at critical temp8-Critical TemperatureThe temp. above which all the mixture cannot be liquidQuality Lines-9Lines through the two-phase region showing a constant percentage of liquid and.vapour10-RetrogradeThe name given to phase behaviour above the critical temperature and pressure were vapour and liquid phases coexist and the amount of vaporisation or condensation changes with pressure and temperature in the opposite direction to normal behaviour. (e.g:condensation of liquids occur by lowering pressure or increasing temperature) 23
    • 24. Definitions 11-Equation of State (e.g : ideal gas law)An equation which describes the relationship between pressure,temperature and molar volume of any homogenous fluid at equilibrium12- Critical PointThe point on the phase diagram where The bubble point and dew point linesintersect , where the distinction between gas and liquid properties disappears.The natural gas phase behavior is a function of the composition of thegas mixture and is strongly influenced by the concentration of theheavier hydrocarbons, especially C+ . The presence of heavierhydrocarbons will increase the phase envelope and failure to includethem in a phase calculation will under predict the phase envelope.:As shown by the next exmple 24
    • 25. 25
    • 26. 26
    • 27. 2500 ( TSCF ) 36.2 %2000 3.1 % 4.9 % 36.1 %1500 7.2 %1000 4.6 % 500 7.9 % 0 N-America S-America Europe Africa Mid-East Sov- Asia/Austr. Countries 27
    • 28. Fertilizer Methane: /Methanol/Olefin / GTL Feedstock Ethane : Petrochemical Feedstock. Petrochemical Feedstock Propane: or Fuel.NATURAL Refinery Feedstock / GAS I-Butane: Fuel. Gasoline Blending / Fuel N-Butane: / Petrochemical Feedstock. Natural Gasoline (IC5+) Refinery Feedstock or Petrochemical Feedstock. Condensate 28
    • 29. Separation between the Oil &Gas Sweetening remove the Acid Gases Conditioning Dehydration remove the Water vapour Main Target H.C Dew Point & Heating Value -Extract main component into separate products which are)Extraction (Processing Methane Main Target Ethane Propone LPG Natural Gasoline 29
    • 30. 30
    • 31. Training VideosI- Natural Gas Processing Principles 30 31
    • 32. Gas Conditioning• Field Separation.• Gas Sweetening.• Gas Dehydration. 33
    • 33. • Large Vessels are used to separate the gas, oil, water and sand using their different densities.• Sufficient time has to be given to HP Gas LP Gas allow the water droplets to settle from the oil and vice versa. HP Separator LC LP Separator• Multiple stages are used to LC liberate gas and remove water. Heating/ Heating/ Cooling Cooling• The number of stages is assessed Water balancing cost, energy efficiency, effect on the reservoir and safety. Export• The separation process may Dehydration/ Cooling require heating to help destabilise Desalter LC Pump oil-water emulsions.• Chemicals are utilised to assist droplet coalescence, break foams Water and prevent corrosion.• To prevent remixing and effective separation the separator is fitted 34 with a range of devices.
    • 34. Separator Internals• Internals design is often key to efficient separator operation. – Inlet device to reduce liquid momentum (centrifugal/impingeme nt) – Distributor plate – Coalesce pack to provide surface area for small droplets to coalesce to larger ones, enhancing liquid/liquid separation – Vane packs or demisters to collect oil droplets from the gas – Vortex breakers to prevent gas underflow – Sand jets to remove sand from the 35 separator
    • 35. Separator Internals Baffle Plate Set Inlet Diffuser & Cascade Tray Cyclone Inlet Device Cyclone Inlet Device Foam Reducing Pack Assembly with 36Perforated Baffle Plate
    • 36. Separators Types • Separator features :• Horizontal Separators – Primary separation section to – Large liquid handling separate the bulk of the liquid from the gas capacity – Sufficient capacity to handle liquid – Sufficient time for settle out surges of liquid droplets from the – Sufficient liquid residence time to allow small droplets to settle out gas – Some inlet device to reduce• Vertical Separators turbulence and velocity in the main separation section (scrubbers) – A mist extractor to capture entrained – High gas volumes droplets – Small footprint area – Back pressure and liquid level controls 37 – Relief and blowdown
    • 37. Training VideosII- Natural Gas Separators Principles 30 38
    • 38. 39Day#2
    • 39. •Sweetening process is to remove acid gases from natural gases.•This can be done either by adsorption or absorption processes.•The most famous adsorption process is solid desiccant beds which canperform Sweetening and dehydration for natural gas at the same time withhigher efficiency.•The most famous absorption process is amine. 40
    • 40. AMINE PROCESS 41
    • 41. CHEMICAL ABSORPTION H H -HO-C - C H H 42
    • 42. 43
    • 43. Ty pic al 44
    • 44. 45
    • 45. FIG. 21-5 Physical Properties of Gas Treating Chemicals ”“weak bases Mono- Di- Tri- Property Ethanolamine Ethanolamine Ethanolamine Formula HOC2H4NH2 HOC2H4)2NH) HOC2H4)3N) Molecular Wt 61.08 105.14 148.19Boiling point @ 170.5 269 (decompose )360760 mm Hg, °CDensity @ 20°C, 1018 1095 1124 .kg/m3 46
    • 46. A brief review of the more frequent problems and corrective •: procedures follow 1- Gas is Not “ Sweet “/Dehydrated :Check solution concentration – Too low : Check make up water addition. :Check amine flow rate – Too low : Open by pass valve. :Check amine regeneration – Increase firing rate. :Check reflux rate and temperature – Probably too low : Increase firing rate. :Check stripping column pressure – It may be too low : Check for foaming – Carry over into outlet separator and / or pressure fluctuations across absorber. 47
    • 47. 2- Amine solution not regenerated• Check reboiler temperature ,pressure and the reflux rate.• Check for leaks in lean/rich amine heat exchanger.• Check the re-claimer for primary amine.• Check for foaming in stripper : - pressure fluctuations. 48
    • 48. 3- Dirty, degraded amine• Gas contains oxygen.• Storage or make up tank blanket gas valve is not functioning: - Repair if any.• Make up water contains free oxygen: - Add oxygen scavenger or use distillated water.• Sparge amine with sweet gas to strip oxygen. 49
    • 49. 4- Excessive CorrosionAmine concentration is too high:  Add make up water .Amine is highly degraded:  Replace .Make up water is high in dissolved solids :  Treat make up water or use deionized water.Insufficient amine regeneration:Insufficient amine filtration :  Increase filter rate or change filter elements more frequently.Qxygen is entering system:  Eliminate.Velocities too high :  reduce temperature to stripper. 50
    • 50. 5- Foaming of amine solution• Foaming is a very unpredictable phenomenon. It can be caused by any or a combination of the following conditions:  Dirty amine (solids) – check filter elements.  Degraded amine.  Liquid hydrocarbon in gas or amine. 51
    • 51. 6- Hydrocarbon condensation• It will be caused by lower inlet amine temperature.• So the Inlet amine temperature must be at least 10-15 oF above the inlet gas temperature to eliminate H.C condensation . 52
    • 52. 7- Wrong or off-spec – chemicals• Well treating chemicals.• Surfactants.• Corrosion inhibitors.• Very fine particles. e.g. iron sulfide, in sour gas.• Inadequate cleaning of amine plant before start-up. 53
    • 53. 9- Incoming gas is not adequately scrubbed and contains salt water• Make up water contains iron, sulfides, chlorides, etc… (Use deionized or de-mineralized water) 54
    • 54. 10- Tray down comers are plugged, causing amine to stack up in the trays• (This is really not a foaming problem but behaves so; usually with older plants).• Note :  Always add antifoaming downstream of the carbon filter.  The following antifoaming are recommended Dilute with 50% isopropyl alcohol use in concentrations of 5 to 50 PPMW . 55
    • 55. Training Videos”II- Gas Sweetening “Amine Uint 18 56
    • 56. AMINE UNIT CASE STUDY Gupco U104 amine unit 7 ge PaCOS “Carbonyl sulfide” it is a colorless flammable gas with an unpleasant odor. Itis a linear molecule consisting of a carbonyl group double bonded to a sulfur atomit decomposes to H2S & Co2 in presence of humidity and bases 57
    • 57. Day#3•Dehydration process is to remove water vapor from natural gases.•This can be done either by adsorption or absorption processes.• )gas 2 solid( )gas 2 liquid(• The most famous adsorption process is solid desiccant beds which canperform Sweetening & Dehydration for natural gas at the same time withhigher efficiency according to its material affinity and pour size .• The most famous absorption process is Glycol unit.Water in NG :  Most free associated water removed by simple extraction method at or near wellhead  Water vapor in NG solution need more complex treatment  Process of dehydration of NG – absorption or adsorption  Pipeline specs: 7.0 lb H2O/MMSCF { max. =1 ppmv} 58
    • 58. Water Removal Absorption “Glycol Dehydration”:  Glycol solution (high affinity to water) – diethylene glycol (DEG) or triethylene Glycol (TEG)  TEG/DEG contact wet gas stream (called contactor)  absorb water  glycol soln. sink to bottom  removed  Glycol recovery – vaporize glycol using special boiler  New tech: addition of flash tank separator condensers before boiler to condense methane (90 – 99% recovery) 59
    • 59.  Solid-Desiccant Dehydration : “Adsorption”  Adsorption process consists of 2 or more adsorption tower filled with solid desiccant.  At least 1 working, 1 regenerating  Desiccants: activated alumina or granular silica gel  Wet NG  pass through towers from top to bottom  H2O retains on particle surface  dry NG exits  saturated desiccant heated with heater to vaporize water  Best suite for large volumes gas under very high P 60
    • 60. 61
    • 61. HYDRATES IN NATURAL GAS SYSTEMS• A hydrate is a physical combination of water and other small moleculesto produce a solid which has an “ice-like” appearance but possesses adifferent structure than ice. , it cause flow interrupting.• There are three recognized crystalline structures I,II,H• Their formation in gas and/or NGL systems can plug pipelines,equipment, and instruments, restricting or for such hydrates. In both,water molecules build the lattice and hydrocarbons, nitrogen, CO2 andH2S occupy the cavities. 62
    • 62. • HYDRATES IN NATURAL GAS SYSTEMS• Smaller molecules (CH4, C2H6, CO2, H2S) stabilize a body-centered cubic called Structure I.• Larger molecules (C3H8, i-C4H10, n - C4H10) form a diamond-lattice called Structure II.• Normal paraffin molecules larger than n-C4H10 do not form Structure I and II hydrates as they are too large to stabilize the lattice.However, some iso paraffins and cyclo –alkanes larger than pentane are known to form Structure H hydrates. 63
    • 63. 64
    • 64. Hydrocarbons )C1,C2,C3,iC4+nC4( and / or H2S, N2, CO2 + Metastable H20 @ )P, T( ------------------------------------------ = HYDRATES Metastable water is liquid water which, at equilibrium, will exist as a hydrate 65
    • 65. The conditions which affect hydrate formation are:1- Primary Considerations• Gas or liquid must be at or below its water dew point or saturation condition. To allow water droplet condensation• Temperature.• Pressure.•Composition.2- Secondary Considerations• Mixing.• Kinetics• Physical site for crystal formation such as a pipe elbow, orifice, thermowell, or line scale.• Salinity. 66
    • 66. FIG. 20-4 Water Content of Hydrocarbon Gas P hydrate formation line , function of composition Th 67
    • 67. Hydrate Inhibition•The formation of hydrates can be prevented by dehydrating the gas orliquid to eliminate the formation of a condensed water )liquid or solid(phase.• In some cases, however, dehydration may not be practical oreconomically feasible.• In these cases, chemical inhibition can be an effective method ofpreventing hydrate formation.• Chemical inhibition utilizes injection of thermodynamic inhibitors or lowdosage hydrate inhibitors (LDHIs).•Thermodynamic inhibitors are the traditional inhibitors )i.e., one of theglycols or methanol(, which lower the temperature of hydrate diminishformation “Th”•LDHIs are either kinetic hydrate inhibitors (KHIs) or anti -agglomerants (AAs).• They do not lower the temperature of hydrate formation, but do itseffect. 68
    • 68. Natural Gas Dehydrationby: Liquid & Solid Desiccants 70
    • 69. 71
    • 70. 72
    • 71. 73
    • 72. 74
    • 73. 75
    • 74. 76
    • 75. 77
    • 76. 78
    • 77. Day #3 Glycol Dehydration Unit                                                                                                                                        79
    • 78. 80
    • 79. GLYCOLS PHYSICAL PROPERTIES Ethylene Glycol Di-ethylene Tri-ethylene Tetraethylene HO—)CH2(2—OH Glycol Glycol GlycolFormula C2H6O2 C4H10O3 C6H14O4 C6H18O5Molecular weight 62.1 106.1 150.2 194.2Boiling point at 760 mm Hg, °F 387.1 472.6 545.9 597.2Boiling point at 760 mm Hg, °C 197.3 244.8 285.5 314Vapor pressure at 77°F (25°C) mm Hg 0.12 0.002 0.0004 0.00005Vapor pressure at 140°F (60°C) mm Hg 1.5 0.08 0.025 < 0.01Density (g/cc) at 77°F (25°C) 1.110 1.113 1.119 1.120Density (g/cc) at 140°F (60°C) 1.085 1.088 1.092 1.092Density (Kg/m3 ) at 77°F (25°C) 1110 1113 1119 1120Freezing point, °C -13 -8 -7 -5.5Pour point, °C - -54 -58 -41Viscosity in centipoise at 77°F (25°C) 16.5 28.2 37.3 44.6Viscosity in centipoise at 140°F (60°C) 4.68 6.99 8.77 10.2Surface tension at 77°F (25°C), dynes/cm 47 44 45 45Specific heat at 77°F (25°C), kJ/(kg.K) 2.43 2.30 2.22 2.18Flash point, °C (PMCC) 116 124 177 204Fire point, °C (C.O.C.) 118 143 166 191Initial decomposition temperature °C 165 164 207 238 81
    • 80. Training Videos”III- Gas Dehydration “Glycol Unit 15min 10 82 .min
    • 81. 83
    • 82. GLYCOL DEHYDRATION UNIT 84
    • 83. 85
    • 84. 86
    • 85. DEA : 2-6 M3/100 LIT 87
    • 86. 88
    • 87. 89
    • 88. 90
    • 89. 91
    • 90. 92
    • 91. C’99’195C 93
    • 92. 94
    • 93. 95
    • 94. 96
    • 95. Training VideosIV- Gas Dehydration “Principles of Glycol ”Unit 15min 97
    • 96. Solid Adsorpant Dehydration Unit                                                                                                                                        98
    • 97. 99
    • 98. 100
    • 99. Molecular Sieves Adsorber / Internal Arrangement 101
    • 100. GAS DEHYDRATION / Molecular sieves 102
    • 101. GAS DEHYDRATION / Molecular sieves 103
    • 102. GAS DEHYDRATION / Molecular sieves 104
    • 103. GAS DEHYDRATION / Molecular sieves 105
    • 104. GAS DEHYDRATION / Molecular sieves 106
    • 105. GAS DEHYDRATION / Molecular sieves 107
    • 106. GAS DEHYDRATION / Molecular sieves 108
    • 107. FV-4004 RDV MDV RDV MDV RDV MDV 4-E3 4007 4001 4009 4003 4011 4005 GUPCO U-104 G/P FV-4003 Dryers Scheme 4-D1C 2FV-4020 4-D1A 4-D1B 4-V43 4-C1A/B PH-I FV-4005 2FV-4011 Amine Unit RDV MDV RDV MDV RDV MDV 4008 4002 4010 4004 4012 4006 FV-4006 4-F17 4-C3A/B Tie-in 4-V15 FV-4007 2FV-4013 2FV-4019 FV-4002 BDV-4001 4-C5A/B FV-4001 2FV-4014 2FV-4012 2RDV 2MDV 2RDV 2MDV 2RDV 2MDV Tie-in 4007 4001 4009 4003 4011 4005 2FV-4015 ESD-1908 2FV-4017 4-V143 4-D101C 4-D101A 4-D101B 4-C103A/B 4-C101A/B PH-II 4-F217 ESD-1907 4-H1D 2FV-4018 2FV-4016 2RDV 2MDV 2RDV 2MDV 2RDV 2MDV 4008 4002 4010 4004 4012 4006 109 4-F117Pg.9 Of 10 P. Eng. / A.Z
    • 108. 1” Ceramic Ball ( 52 CF ) Upper Screen ( 20 Piece ) 6” Molecular Sieve Charge ( 80,200 lb ) Dimensions: 144” I.D 20’ S/S 1/8” Ceramic Ball ( 26 CF ) 1/4” Ceramic Ball ( 26 CF ) 3” 3” Lower Screen 4-D1A/B/C Dimensions 11010 Of 10 P. Eng. / A.Z
    • 109. Table 1 Molecular Sieve Operation Chart Process Step 1 2 3 4 5 6 D1A-4 D D D H C D D1B-4 D H C D D D D1C-4 C D D D D H D101A-4 D D D D H C D101B-4 D D H C D D D101C-4 H C D D D DFV-4003, 2FV-4015, 2FV4018, 2FV-4020 Open Close Open Close Open CloseFV-4004, 2FV-4016, 2FV4017, 2FV-4019 Close Open Close Open Close Open 111
    • 110. DAY# 4 113
    • 111. 1. By lean oil absorption2. By Refrigeration & LTS.3. By Cryogenic Process 114
    • 112. 115
    • 113. CompressorSales . Gas FlareSales . Gas Feed Dry . Gas LTS Wet . Gas Exchanger InletSeparator Dehydration Stabilzer Water .Cond F.G Cooler To. Stabilizer 116
    • 114. Cryogenics : Is the study of the production of very low temperature materials(below −43°C) and the behavior of materials at those temperatures. 117
    • 115.  Process Units  Deethanizer – separates ethane from NGL stream  Depropanizer – separates propane  Debutanizer – boils off butanes leaving pentanes and heavier HC in NGL stream  Butane splitter (Desiobutanizer) – separates iso and n butanes Component BP oF at 1 atm Ethane -127 (-88 oC) Propane -44 (-42) oC Iso-butane 11 (-11 oC) n-butane 31 (-0.5 oC) Pentane 97 (36oC) 118
    • 116. Turbo Expanders• The use of turbo expanders in gas processing plants began in the early sixties.• By 1970, most new gas processing plants for ethane or propane recovery were being designed to incorporate the particular advantages characteristic of an expander Producing usable work.• The trend in the gas processing industry continues toward increased use of the turbo expander.• Selection of a turbo expander process cycle is indicated when one or more of the following conditions exist:  “Free” pressure drop in the gas stream.  Lean gas.  High ethane recovery requirements (i.e., over 30% ethane recovery).  Compact plant layout requirement.  High utility costs. 119  Flexibility of operation (i.e:easily adapted to wide variation in pressure and products).
    • 117. Turbo expanders 120
    • 118. • This figure represents the pressure- Turbo expanders temperature diagram for this expander process.• The solid curve represents the plantinlet gas & the dashed one representexpander inlet gas (less in heavy H.C)• At a fixed pressure and, if the temperature of the gas is to the right of this dew point line, the gas is 100 percent vapor.• If the gas is cooled, liquid starts to condense when the temperature reaches the dew point line.• As cooling continues, more liquid is condensed until the bubble point line is reached — the solid line on the left. At this point, all of the gas is liquid. 121 Additional cooling results in colder liquid
    • 119. Turbo expanders• A turbo expander recovers useful work from the expansion of a gas stream.• The process operates Isentropically in the ideal case and produces somethingless than the theoretical work in the real case.• In the process of producing work, the expander lowers the bulk streamtemperature which can result in partial liquefaction of the bulk stream. 122
    • 120. To Sales Gas Compressor Re Expander comp 3 4 FeedGas Lts Jt Valve 11 Dehydration Pkg Q-1 7 De-Methaniser To De- De-Propaniser Ethaniser De-Butans 123
    • 121. "”Mixed Refrigerant Processes Mixed Refrigerant Processes are used through LNG/NGL plants to avail sub-cooling for natural gas where a single mixed refrigerant is used (composed of nitrogen, methane,ethane, propane, butane and pentane). The refrigerant is designed so that the refrigerant boiling curve nearly matches the cooling curve of the gas being liquefied. The closeness of the match of these two curves is a direct measure of the efficiency of the process. 124
    • 122. “Cold box exchangers”The cold box is a series of aluminum plate fin exchangers which providevery close temperature approaches between the respective process streams. The low pressure refrigerant is compressed and condensedagainst air or water in a closed system. The refrigerant is not totallycondensed before being sent to the cold box. The high pressurevapor and liquid refrigerant streams are combined and condensedin the main exchanger. The condensed stream is flashed across a J-T valve and this lowpressure refrigerant provides the refrigeration for both the feed gasand the high pressure refrigerant. 125 ,see fig 16-31 GPSA sec.16 in which
    • 123. Training VideosIIV- Cryogenic Principles 15min 126
    • 124. Examples for LPG,NGL andLNG Gas Plants 127
    • 125. Boosting & Sales Gas Comp. Send sales 4-W4A gas to GASCO net ( 64-100) kg/cm2 Chilling Area PH-I LPG 4-W1A 4-C3A 4-W4B 4-T1 Drying Area PH-I 4-T2 4-D1C 4-D1A 4-D1B 4-W4C 4-C3B 4-W1B 4-W105 COND. Fractionation Area - Produce LPG & Condensate Chilling Area PH-II LPG 4-W104A 4-W101A 4-C103A Sales Gas Drying Area PH-II Utilities 4-D101A 4-T101 4-T102 4-D101B 4-D101C - Inst. Air System 4-W104B - Heating Oil System - Refrigeration4-W101B Package 4-C103B - Cooling WaterCompression System Area - Power House-Compress gas COND. - Fuel Gas Systempress from 6-47 - Multi-Nozzle Flarekg/cm . Expansion & Chilling System Area - Nitrogen Unit- pre-separation - Loading Areafor heavy H.C Separate Heavy H.C by cooling down to -60 ‘c 128 -Storage Area -LPG Berth # 4
    • 126. N.G ( 1043 Demethanizer MMSCFD ) 26.3 Bar Depropanizer Packed Tower Condenser -76 °C 25.6 Bar Condenser Bubble cap -43 °C ( 30 Tray ) M Packed Tower 18 Bar 26.6 Bar 27.3 Bar 50.7 °C -74.4 °C -31.7 °C -74.5 °C C3 Expert 27.3 Bar ( 925 T/D ) -74.4 °C Demethanizier 26.6 Bar Depropanizer Absorber -68 °C -33 °C Sales Gas -36 °C 1043 20 Bar ( MMSCFD ) 31 Bar -78.2 50 °C °C Propane T/D 925 10-E-04 -69.5 °C 30-E-01 LPG T/D 1215 LPG Local Turbo 20 Bar Market Compressor Expander Condensate T/D 348 78.2 °C LPG Rundown 1215 T/D Cools M 13.5 Bar 50 °C Plat Fin 25.6 Bar Dehydration -43 °C Debutanizer Package 1100 66 BarMMSCFD Inlet Filter Mercury 40 °C 64.7 Bar 64.7 Bar 70 Bar Separator Removal -24 °C -35 °C Plat Fin 30 °C 10.2 Bar 62 °C 1.85 Bar -58 °C 120.8 °C 28.3 Bar Separator 28.2 Bar 28.5 Bar 30 –E -02 -50.9 °C -69.5 °C -36 °C -33 °C M 12910.2 °C 50 Bar DNG Rundoum Cools Condensate ( Local Market ) ( 348 T/D )
    • 127. 130
    • 128. Regeneration Gas Compressors C-111/112 Regeneration Gas Cooler A-311Feed U-104 PCV-410 Dehydration Dust Filter F- 416/417 Regeneration Gas Scrubber Dust Filter F-451 V-418 Dehydration Gas Scrubber Mercury Removal Bed Dehydration inlet V-410 V-450 Filter Coalescer Dehydration Adsorbers Regeneration Gas Heater Residue Gas To Pipeline F-412 V-413/414/415 E-211 Cold Gas Reflux Exchanger E-222 Exp/Comp Discharge Cooler A-321 Depropanizer Reflux Condenser A-341 C-121/122 Deethanizer Reflux Acc. V-422 Depropanizer Reflux Drum V-441 Depropanizer Deethanizer T-541 V-521 P-621/622/623 JT Warm Gas/Gas Exchanger E-221 Depropanizer Reflux Pumps P-641/642 Propane To Storage Cold Separator Deethanizer Side Reboiler V-421 E-224 Depropanizer Reboiler E-241 Deethanizer Bottom Reboiler Butane to Storage E-225 Feed P-695/696 Booster P-693/694
    • 129. EXAMPLES FOR NGL GAS PLANTSDOVE ENERGY-YEMEN PLANT 15min 132
    • 130. NGL ExtractionTypical Product Recoveries ( % ): Plant Type Turbo- Joule Lean Oil Refrigera -> Expander Thompson tion Product Ethane 60 – 96% 45 – 60% 25 – 45% 1 – 5% C2 Propane 90 – 98% 85 – 95% 80 – 95% 20 – 40% C3 Iso-Butane 96 – 100% 96 – 100% 93 – 99% 40 – 60% IC4 N.Butane 97 – 100% 97 – 100% 94 – 99% 40 – 60% NC4 •NGL Recovery 133
    • 131. Distillation or Fractionation Towers and Tray Troubleshooting 134
    • 132. Fractionation Towers• There are two main types of Fractionation Towers according to its inside configuration : • 1- Trays Towers . • 2- Packed Towers.• Here below we will concentrate on Trays one as for its widely usage all over the world . 135
    • 133. Trays TowersTRAY TYPS :Flow Regime 136
    • 134. TRAY TYPS :Perforation Regime 137
    • 135. TRAY TYPS :Perforation Regime 138
    • 136. 139
    • 137. 140
    • 138. 141
    • 139. Tray Towers Problem 142
    • 140. Tray Towers Problem1 143
    • 141. Tray Towers Problem2 144
    • 142. Tray Towers Problem3 145
    • 143. Tray Towers Problem4 146
    • 144. Packing Types 147
    • 145. 148
    • 146. BOOSTER STATION UTILITIES 149
    • 147. FT’’FM-Ashrafi 20 ’’20 ’’FM-Hilal 20 PV-321 PI 4.7 Kg/cm2.g TI 34 C To Flare U-102 SLUG CATCHER .GAS COMP C1A-2 .GAS COMP PI 19-26 Kg/cm2.g FT C1B-2 TI 50 C Glycol PCV-308 .Unit ESDV FT TO U-104 New .GAS COMP Glycol C1C-2 Unit ved mo d y re ’’16 lrea re a ls we .GAS COMP te rna C1D-2 e s in ’’4 alv ckv che Fuel To Unit ’’8 ’’8 Closed )suco pipe line’’ ( 12 Pig receiver Process Div
    • 148. BOOSTER STATION UTILITIES * Utilities : -Gas compressor -Heat Exchanger - Inst. Air System - Refrigeration Package - Cooling Water System - Power House - Fuel Gas System - Flare System - Nitrogen Unit - Storage Area 152
    • 149. Natural GasCompression
    • 150. Purposes of gas compressionTheory of gas compressionMain types of compressorsCentrifugal CompressorReciprocating Compressor
    • 151. Purposes of Gas CompressionFor transportation facilities.For extra processing (liquefaction, dehydration & sweetening).
    • 152. Theory of GasCompression PV = ZnRT = Z (m/M)RT P1V1/T1 = P2V2/T2
    • 153. Main Types of Compressors1- Dynamic type (Centrifugal) P1 T1 V1Construction: P2 T 2 V 2 1- Rotor − − − − − + + + + + 2- Stator
    • 154. Anti-surge Control
    • 155. 2-Reciprocating Compressor: Stroke Compression chamber Piston Each cylinder consists of : Piston Chemise Inlet valve Outlet valve
    • 156. Comparison of reciprocating & centrifugal compressors
    • 157. HEAT EXCHANGERS 15min 15min vedio presentation 162
    • 158. N2 UNIT N2 unit PFD CW in Potable water Fuel Gas Plate H.E Combustion chamber Cooling pumps CW out Exhausts Comp.Air intake filter CW in After cooler Co2&H2O Absorber CW out Cond. Water OD tape Air Blower N2 Reservoir OD Design To plant utilities 90 psig 80fo air Fuel gas Exhaust N2 OD Cooling water 163
    • 159. U-102Hilal 4” FUEL PIC-307 PIC -316A GAS PIC -316B V21-2 LV-716 V6-2 0 LV-710
    • 160. Course Final quiz• 1// What is Natural Gas , definition , composition ,formation and uses?• 2// What the sections and devices of horizontal separators ?• 3// What does this Appreciations mean? – LNG - SRU – NGL - Acid Gas and tail gas – P&ID – PFD – LTS – Dew Point Depression .• 4// What is the difference between the:• Absorption and Adsorption Process ? Give examples!• Hazard and Risk• 5// what is the recommended temp. difference between Gas & Liquid desiccant interring to a contactor tower ?• 6// What are the Filter Types used at the TEG and DEA units ? (and purpose of every type)• 7// draw a schematic drawing for a TEG typical Dehydration Unit ?• 8// What are the main four types of gas cryogenic process ?• 9// what are the Towers ‘ performance constraints & main cause of every constraints ?• 10// what are the rout parameters affect LPG Specifications at the Fractionation Area ? 168 ------------------------------------------------------------------------------
    • 161. 11// why the TEG is widely used at Glycol Dehydration?12// what the recommended temp./pressure for TEG still reboiler ?13// What are the booster station utilities ?14// what is the main types of compressors ? Advantages and disadvantages?15// what are the main types of heat exchangers ? Give exapmles of H.Exchangers at your plant ?16// what are the two types of air coolers ?17// what is the solid disicants used at your plants?------------------------------------------------------------------------------ 169
    • 162. 11// what are the main reactions take place at SRU?12//what meant by sulfer recovery ? Feeds,products,recovery, components….13// what are the operating parameters of SRU?14// what are the precautions before the SRU start up?15//what is the source of SRU acid gas ?16// why we treatment the tail gas?TGT?17//what is the purpose of sulferpit degassing system? how does it work?18// what is the blanket gas system, give example?19//The 1/5 of h2s will be nurned out in the thermal claus reactor?20//what are the waste heat recovery unit?21//steam boiler in SRU? tell how & why ! ------------------------------------------------------------------------------ 170
    • 163. THANKS ,,,Eng. Ahmed ShomanNatural Gas Processing EngineerGUPCO "Gulf of Suez Petroleum Co."Mobile: +2-0122-743-2850 , +2-0100-800-4930e-mail:shomanAM@gupco.net / shomanNMC@yahoo.com 171

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