The document discusses natural gas liquid (NGL) recovery processes. It describes several types of NGL recovery processes including refrigeration processes like mechanical refrigeration, self-refrigeration, and cryogenic refrigeration. It also discusses lean oil absorption, solid bed adsorption, membrane separation, and twister supersonic separation. The document provides details on different types of natural gas reservoirs and discusses various refrigeration techniques in depth. It concludes by mentioning modern NGL recovery processes are based on turbo expanders using reflux configurations.
Natural gas contains water that must be removed through dehydration. There are three main dehydration methods: direct cooling, adsorption, and absorption. Glycol absorption is most common, using triethylene glycol to continuously remove water down to 0.5 lb of H2O/MMSCF. Glycol dehydration has lower costs than alternatives due to easier regeneration and makeup of glycol, as well as less heat required per pound of water removed. Removing water prevents issues like reduced heating value, gas hydrate formation, and corrosion in downstream pipelines and equipment.
This document describes gas sweetening processes used to remove acid gases like H2S and CO2 from natural gas. It focuses on chemical absorption processes using alkanolamine solvents like MEA, DGA, DEA, and MDEA in aqueous solutions. The general process involves absorbing acid gases from the feed gas in an absorber column, regenerating the solvent in a regenerator column, and recycling the regenerated solvent. Key unit operations discussed include the absorber, flash drum, amine/amine heat exchanger, regenerator, reboiler, and condenser. Process conditions and equipment details are provided for the typical operation of each unit.
Crude oil production systems involve exploration, drilling, and surface production operations to extract crude oil and separate it from other fluids and gases. Surface production operations include separating the well effluent into gas, oil, and water streams using separators. The separated streams undergo further treatment, which may include dehydration to remove water, emulsion breaking, stabilization to control vapor pressure, and removal of impurities. Produced water is typically reinjected, while associated gas may be reinjected, used for power generation, or flared if not needed onsite. Wastes are also handled through treatment and disposal or reuse to protect the environment.
Three phase separators separate gas, oil, and water. They consist of three zones: an inlet zone, a liquid-liquid settling zone, and a gas-liquid separation zone. Key factors that affect separator efficiency include the inlet flow pattern and devices, feed pipe geometry, entrainment, and internals. Separators can be horizontal or vertical, with horizontal separators often used for foamy streams and liquid-liquid separation, while vertical separators handle large liquid slugs. Proper sizing considers flow rates, residence times, velocities, and droplet sizes to achieve efficient phase separation with minimum carryover.
The document provides information about gas processing and separation. It discusses reservoir fluids and the components found in a barrel of crude oil. It then covers fluid emulsions and conditions in pipelines. Several pages are dedicated to explaining separators, including their definition, functions, factors affecting separation, and classifications based on geometry, function, number of phases separated, operating pressure, and application. Separator types discussed include vertical, horizontal, and spherical separators.
Phase separation occurs in a pressure vessel called a separator that is used to separate well fluids produced from oil and gas wells into gaseous and liquid components. Separators employ mechanisms like gravity settling, centrifugal force, and baffling to separate the phases. Separator design and performance is dependent on factors like flow rates, fluid properties, presence of impurities, and foaming tendencies. Common types of separators include test separators, production separators, and low temperature separators that are used for primary separation, secondary separation, and removal of specific phases like free water.
Gas Condensate Separation Stages – Design & OptimizationVijay Sarathy
The life cycle of an oil & gas venture begins at the wellhead where subsurface engineers work their way through surveying, drilling, laying production tubing and well completions. Once a well is completed, gathering lines from each well is laid to gather hydrocarbons and transported via a main trunk line to a gas oil separation unit (GOSP) to be processed further to enhance their product value for sales. Gas condensate wells consist of natural gas which is rich in heavier hydrocarbons that are recovered as liquids in separators in field facilities or gas-oil separation plants (GOSP).
The following tutorial is aimed at demonstrating how to optimize and provide the required number of separation stages to process a gas condensate mixture and separate them into their respective vapour phase and liquid phase – termed as “Stage Separation”. Stage separation consists of laying a series of separators which operate at consecutive lower pressures to strip out vapours from the well liquids & resulting in a stabilized liquid. Prior to any hydrocarbon processing in a gas processing plant or a refinery, it is imperative to maximize the liquid recovery as well as provide a stabilized liquid hydrocarbon.
Here are the key steps to take in the event of an LNG spill:
1. Evacuate the area immediately and move upwind. LNG vapors are heavier than air and can accumulate in low-lying areas.
2. Call emergency services and report the spill. Provide details on location, size of spill, and any injuries.
3. Warn others and prevent access to the spill area. Use barricades or barriers if possible.
4. Do not attempt to extinguish a LNG fire unless trained and it is safe to do so. Evacuate immediately instead.
5. Avoid direct contact with spilled LNG as it can cause frostbite or freeze skin/eyes on
Natural gas contains water that must be removed through dehydration. There are three main dehydration methods: direct cooling, adsorption, and absorption. Glycol absorption is most common, using triethylene glycol to continuously remove water down to 0.5 lb of H2O/MMSCF. Glycol dehydration has lower costs than alternatives due to easier regeneration and makeup of glycol, as well as less heat required per pound of water removed. Removing water prevents issues like reduced heating value, gas hydrate formation, and corrosion in downstream pipelines and equipment.
This document describes gas sweetening processes used to remove acid gases like H2S and CO2 from natural gas. It focuses on chemical absorption processes using alkanolamine solvents like MEA, DGA, DEA, and MDEA in aqueous solutions. The general process involves absorbing acid gases from the feed gas in an absorber column, regenerating the solvent in a regenerator column, and recycling the regenerated solvent. Key unit operations discussed include the absorber, flash drum, amine/amine heat exchanger, regenerator, reboiler, and condenser. Process conditions and equipment details are provided for the typical operation of each unit.
Crude oil production systems involve exploration, drilling, and surface production operations to extract crude oil and separate it from other fluids and gases. Surface production operations include separating the well effluent into gas, oil, and water streams using separators. The separated streams undergo further treatment, which may include dehydration to remove water, emulsion breaking, stabilization to control vapor pressure, and removal of impurities. Produced water is typically reinjected, while associated gas may be reinjected, used for power generation, or flared if not needed onsite. Wastes are also handled through treatment and disposal or reuse to protect the environment.
Three phase separators separate gas, oil, and water. They consist of three zones: an inlet zone, a liquid-liquid settling zone, and a gas-liquid separation zone. Key factors that affect separator efficiency include the inlet flow pattern and devices, feed pipe geometry, entrainment, and internals. Separators can be horizontal or vertical, with horizontal separators often used for foamy streams and liquid-liquid separation, while vertical separators handle large liquid slugs. Proper sizing considers flow rates, residence times, velocities, and droplet sizes to achieve efficient phase separation with minimum carryover.
The document provides information about gas processing and separation. It discusses reservoir fluids and the components found in a barrel of crude oil. It then covers fluid emulsions and conditions in pipelines. Several pages are dedicated to explaining separators, including their definition, functions, factors affecting separation, and classifications based on geometry, function, number of phases separated, operating pressure, and application. Separator types discussed include vertical, horizontal, and spherical separators.
Phase separation occurs in a pressure vessel called a separator that is used to separate well fluids produced from oil and gas wells into gaseous and liquid components. Separators employ mechanisms like gravity settling, centrifugal force, and baffling to separate the phases. Separator design and performance is dependent on factors like flow rates, fluid properties, presence of impurities, and foaming tendencies. Common types of separators include test separators, production separators, and low temperature separators that are used for primary separation, secondary separation, and removal of specific phases like free water.
Gas Condensate Separation Stages – Design & OptimizationVijay Sarathy
The life cycle of an oil & gas venture begins at the wellhead where subsurface engineers work their way through surveying, drilling, laying production tubing and well completions. Once a well is completed, gathering lines from each well is laid to gather hydrocarbons and transported via a main trunk line to a gas oil separation unit (GOSP) to be processed further to enhance their product value for sales. Gas condensate wells consist of natural gas which is rich in heavier hydrocarbons that are recovered as liquids in separators in field facilities or gas-oil separation plants (GOSP).
The following tutorial is aimed at demonstrating how to optimize and provide the required number of separation stages to process a gas condensate mixture and separate them into their respective vapour phase and liquid phase – termed as “Stage Separation”. Stage separation consists of laying a series of separators which operate at consecutive lower pressures to strip out vapours from the well liquids & resulting in a stabilized liquid. Prior to any hydrocarbon processing in a gas processing plant or a refinery, it is imperative to maximize the liquid recovery as well as provide a stabilized liquid hydrocarbon.
Here are the key steps to take in the event of an LNG spill:
1. Evacuate the area immediately and move upwind. LNG vapors are heavier than air and can accumulate in low-lying areas.
2. Call emergency services and report the spill. Provide details on location, size of spill, and any injuries.
3. Warn others and prevent access to the spill area. Use barricades or barriers if possible.
4. Do not attempt to extinguish a LNG fire unless trained and it is safe to do so. Evacuate immediately instead.
5. Avoid direct contact with spilled LNG as it can cause frostbite or freeze skin/eyes on
This document describes the process of solid bed gas dehydration. It begins with an introduction to gas dehydration and why it is needed to meet contractual water content specifications. It then covers determining the water content in a gas stream and corrections that must be made. The main part of the document discusses how solid bed dehydration systems work using adsorption onto a desiccant and provides details on the process, design considerations, example calculations, and heat requirements for regeneration. It concludes with a solved example to design a solid bed dehydration unit to treat a specific gas feed.
The document outlines the design of a gas and oil separator for an oil field. It discusses the key functional sections of separators including inlet diverters to separate gas and liquid, a liquid collection section, a gravity settling section, and mist extractor section. It also describes different types of separators such as vertical, horizontal, and spherical separators. The functions of oil and gas separators are given as removing oil from gas, removing gas from oil, isolating water from oil, and maintaining optimum pressure. Components inside the separator vessel like inlet diverters and wave breakers are also explained.
This document provides an overview of designing wells for high pressure high temperature (HPHT) environments. It discusses HPHT definitions, challenges, case studies, and recommendations for various well design aspects. Key points include defining three HPHT envelopes based on temperature and pressure limits, outlining completion, testing and data acquisition challenges, reviewing global HPHT fields and standards, analyzing an Indian HPHT case study, and providing recommendations for casing design, drilling fluids, cementing, and material selection tailored for HPHT wells.
This document provides information on fired heaters, including methods of heat transfer, combustion, types of fired heaters, furnace parts, problems that can occur, and introduces several heaters at a refinery. It discusses the three main methods of heat transfer as conduction, convection, and radiation. Fired heaters use combustion of fuel to generate heat that is transferred to process fluids through tubes. Box and cylindrical designs are described. Key furnace parts and issues like overfiring, vibration, and inefficiency are outlined. Example heaters at the refinery include crude, vacuum, visbreaker, and hydrotreating unit heaters.
The document discusses enhanced oil recovery (EOR) methods, focusing on steam injection. It defines EOR as techniques for extracting more crude oil from reservoirs beyond primary and secondary recovery methods. Steam injection is a thermal EOR method that involves injecting steam into reservoirs to lower oil viscosity and produce more oil. There are two main steam injection techniques - cyclic steam stimulation (also called huff-and-puff) which alternates between steam injection and production from single or multiple wells, and steam flooding which continuously injects steam into reservoirs to displace oil towards production wells. The document outlines some advantages and disadvantages of steam injection and economic considerations.
Amine Gas Treating Unit - Best Practices - Troubleshooting Guide Gerard B. Hawkins
Amine Gas Treating Unit Best Practices - Troubleshooting Guide for H2S/CO2 Amine Systems
Contents
Process Capabilities for gas treating process
Typical Amine Treating
Typical Amine System Improvements
Primary Equipment Overview
Inlet Gas Knockout
Absorber
Three Phase Flash Tank
Lean/Rich Heat Exchanger
Regenerator
Filtration
Amine Reclaimer
Operating Difficulties Overview
Foaming
Failure to Meet Gas Specification
Solvent Losses
Corrosion
Typical Amine System Improvements
Degradation of Amines and Alkanolamines during Sour Gas Treating
APPENDIX
Best Practices - Troubleshooting Guide
Sucker rod pumps are a type of artificial lift used in oil wells that involves components both above and below ground. The surface pumping unit is connected via sucker rods to the subsurface pump located downhole. The pumping cycle involves the plunger moving up and down inside the barrel, using the traveling or standing valves to draw fluid into the barrel on the upstroke and push it up on the downstroke. Sucker rod pumps are suitable for shallow wells producing 10-1000 bbl/day but become less effective at greater depths or in wells with high gas levels.
Ai Ch E Overpressure Protection Trainingernestvictor
The document provides an overview of overpressure protection and relief system design. It discusses key concepts such as causes of overpressure, applicable codes and standards, the relief system design process, relief device terminology, and methods for determining relief loads from scenarios such as blocked outlets, thermal expansion, external fires, and automatic control failures. The document is intended to educate engineers on important considerations for properly sizing and designing pressure relief systems.
This document is a report on natural gas dehydration processes submitted by students at Koya University. It discusses the importance of removing water from natural gas and describes various dehydration methods. The most common methods are absorption using glycol and adsorption using desiccants. Absorption using triethylene glycol is identified as the most economical and effective process, as it requires less energy and maintenance than adsorption while achieving the necessary low water levels. The report provides details on how each dehydration method works and the advantages and limitations of absorption and adsorption processes.
This document discusses flare technology and applications. It begins with an outline and defines a flare as safety equipment used to burn unwanted gases from oil, gas, and chemical plants. It notes that flares ensure safe combustion to prevent explosions. The document then discusses: the widespread use of flares globally; types of flares including utility, steam-assisted, air-assisted, and multi-point ground flares; factors that influence flare design and performance such as gas composition and flow rates; and issues with flaring including emissions and strategies to minimize flaring.
The document discusses drill stem testing (DST), which is used to evaluate reservoir properties. It describes the key components of a DST tool, including pressure recorders, test valves, packers, and more. It also outlines the steps to design a DST plan, considering factors like the test interval, packer selection and location, choke selection, and more. Finally, it explains how to execute a DST, interpreting the pressure chart by describing the initial flow, initial shut-in, final flow, and final shut-in periods marked on a sample chart.
This document provides procedures for well test operations. It describes various types of well tests including drawdown, build-up, and deliverability tests. It outlines responsibilities for company and contractor personnel involved in well testing. Safety barriers for well tests include well test fluid, mechanical barriers, casing overpressure valves, and more. Test string equipment, surface equipment, data acquisition methods, sampling procedures, and other well testing steps are also covered. The document aims to provide uniform guidelines for Agip's well testing operations worldwide.
Asphaltenes & wax deposition in petroleum production systemChirag Vanecha
This document discusses asphaltene and wax deposition in production systems and remedial measures. It provides information on the characteristics of paraffins and asphaltenes, factors that influence their deposition, and methods to remove deposits. Common removal techniques include mechanical cleaning, applying heat, using solvents, and adding dispersants. Preventing deposition involves methods such as using crystal modifiers, plastic pipelines, deposition inhibitors, and downhole heaters. The document also covers asphaltene deposition in detail, including how it occurs, influencing factors, typical locations, measuring techniques, diagnosis, and preventive actions.
Natural gas processing technology sweetening processesMohamad Abdelraof
The document discusses hydrogen sulfide (H2S) concentration and toxicity levels at different ppm concentrations. It then discusses requirements for gas entering LNG plants and different sweetening processes used to remove sour gases like H2S and CO2. The amine sweetening process is described in detail, including major equipment used like absorbers, strippers, heat exchangers. Different amines used and their properties are also discussed. Mercury and nitrogen removal processes are briefly covered.
This document outlines the key steps in the liquefied natural gas (LNG) production process. It begins with extracting natural gas from the ground, then treating the gas to remove impurities. The treated gas is then condensed into a liquid by cooling it to -260°F through a multi-stage liquefaction process. The LNG is stored and transported in specialized cryogenic tanks on ships or trucks, then regasified back into gas form before being distributed through pipelines. The document provides details on each stage of the LNG value chain from production to regasification and discusses related technologies like compressed natural gas.
Valves operation and functions complete guideElsayed Amer
Eng. El Sayed Amer is a senior process and production engineer at Suez Oil Co. He has worked as a drilling and completion engineer for Weatherford drilling international. He is also an instructor for oil and gas courses. He is a member of several professional engineering organizations and certified in process modeling and reservoir simulation software. He has expertise in valves technology and operations in the process industry.
Common poisons include
Sulfur
Chlorides and other halides
Metals including arsenic, vanadium, mercury, alkali metals (including potassium)
Phosphates
Organo-metalics
The document discusses natural gas liquid (NGL) recovery from natural gas streams. It covers key terms, factors that affect recovery like gas composition and sales gas specifications, various process options for NGL recovery like low temperature separation and straight refrigeration, and provides an example problem calculating recovery values.
Three main methods are used to remove nitrogen from natural gas: cryogenic distillation, adsorption, and membrane separation. Cryogenic distillation involves using low temperatures and pressures to separate gas components. It is most effective at recovering ethane, propane, butane, and natural gasoline. Adsorption uses materials like molecular sieves to attract moisture and other compounds from the gas stream. Membrane separation exploits differences in molecular sizes to selectively permeate some components over others.
This document describes the process of solid bed gas dehydration. It begins with an introduction to gas dehydration and why it is needed to meet contractual water content specifications. It then covers determining the water content in a gas stream and corrections that must be made. The main part of the document discusses how solid bed dehydration systems work using adsorption onto a desiccant and provides details on the process, design considerations, example calculations, and heat requirements for regeneration. It concludes with a solved example to design a solid bed dehydration unit to treat a specific gas feed.
The document outlines the design of a gas and oil separator for an oil field. It discusses the key functional sections of separators including inlet diverters to separate gas and liquid, a liquid collection section, a gravity settling section, and mist extractor section. It also describes different types of separators such as vertical, horizontal, and spherical separators. The functions of oil and gas separators are given as removing oil from gas, removing gas from oil, isolating water from oil, and maintaining optimum pressure. Components inside the separator vessel like inlet diverters and wave breakers are also explained.
This document provides an overview of designing wells for high pressure high temperature (HPHT) environments. It discusses HPHT definitions, challenges, case studies, and recommendations for various well design aspects. Key points include defining three HPHT envelopes based on temperature and pressure limits, outlining completion, testing and data acquisition challenges, reviewing global HPHT fields and standards, analyzing an Indian HPHT case study, and providing recommendations for casing design, drilling fluids, cementing, and material selection tailored for HPHT wells.
This document provides information on fired heaters, including methods of heat transfer, combustion, types of fired heaters, furnace parts, problems that can occur, and introduces several heaters at a refinery. It discusses the three main methods of heat transfer as conduction, convection, and radiation. Fired heaters use combustion of fuel to generate heat that is transferred to process fluids through tubes. Box and cylindrical designs are described. Key furnace parts and issues like overfiring, vibration, and inefficiency are outlined. Example heaters at the refinery include crude, vacuum, visbreaker, and hydrotreating unit heaters.
The document discusses enhanced oil recovery (EOR) methods, focusing on steam injection. It defines EOR as techniques for extracting more crude oil from reservoirs beyond primary and secondary recovery methods. Steam injection is a thermal EOR method that involves injecting steam into reservoirs to lower oil viscosity and produce more oil. There are two main steam injection techniques - cyclic steam stimulation (also called huff-and-puff) which alternates between steam injection and production from single or multiple wells, and steam flooding which continuously injects steam into reservoirs to displace oil towards production wells. The document outlines some advantages and disadvantages of steam injection and economic considerations.
Amine Gas Treating Unit - Best Practices - Troubleshooting Guide Gerard B. Hawkins
Amine Gas Treating Unit Best Practices - Troubleshooting Guide for H2S/CO2 Amine Systems
Contents
Process Capabilities for gas treating process
Typical Amine Treating
Typical Amine System Improvements
Primary Equipment Overview
Inlet Gas Knockout
Absorber
Three Phase Flash Tank
Lean/Rich Heat Exchanger
Regenerator
Filtration
Amine Reclaimer
Operating Difficulties Overview
Foaming
Failure to Meet Gas Specification
Solvent Losses
Corrosion
Typical Amine System Improvements
Degradation of Amines and Alkanolamines during Sour Gas Treating
APPENDIX
Best Practices - Troubleshooting Guide
Sucker rod pumps are a type of artificial lift used in oil wells that involves components both above and below ground. The surface pumping unit is connected via sucker rods to the subsurface pump located downhole. The pumping cycle involves the plunger moving up and down inside the barrel, using the traveling or standing valves to draw fluid into the barrel on the upstroke and push it up on the downstroke. Sucker rod pumps are suitable for shallow wells producing 10-1000 bbl/day but become less effective at greater depths or in wells with high gas levels.
Ai Ch E Overpressure Protection Trainingernestvictor
The document provides an overview of overpressure protection and relief system design. It discusses key concepts such as causes of overpressure, applicable codes and standards, the relief system design process, relief device terminology, and methods for determining relief loads from scenarios such as blocked outlets, thermal expansion, external fires, and automatic control failures. The document is intended to educate engineers on important considerations for properly sizing and designing pressure relief systems.
This document is a report on natural gas dehydration processes submitted by students at Koya University. It discusses the importance of removing water from natural gas and describes various dehydration methods. The most common methods are absorption using glycol and adsorption using desiccants. Absorption using triethylene glycol is identified as the most economical and effective process, as it requires less energy and maintenance than adsorption while achieving the necessary low water levels. The report provides details on how each dehydration method works and the advantages and limitations of absorption and adsorption processes.
This document discusses flare technology and applications. It begins with an outline and defines a flare as safety equipment used to burn unwanted gases from oil, gas, and chemical plants. It notes that flares ensure safe combustion to prevent explosions. The document then discusses: the widespread use of flares globally; types of flares including utility, steam-assisted, air-assisted, and multi-point ground flares; factors that influence flare design and performance such as gas composition and flow rates; and issues with flaring including emissions and strategies to minimize flaring.
The document discusses drill stem testing (DST), which is used to evaluate reservoir properties. It describes the key components of a DST tool, including pressure recorders, test valves, packers, and more. It also outlines the steps to design a DST plan, considering factors like the test interval, packer selection and location, choke selection, and more. Finally, it explains how to execute a DST, interpreting the pressure chart by describing the initial flow, initial shut-in, final flow, and final shut-in periods marked on a sample chart.
This document provides procedures for well test operations. It describes various types of well tests including drawdown, build-up, and deliverability tests. It outlines responsibilities for company and contractor personnel involved in well testing. Safety barriers for well tests include well test fluid, mechanical barriers, casing overpressure valves, and more. Test string equipment, surface equipment, data acquisition methods, sampling procedures, and other well testing steps are also covered. The document aims to provide uniform guidelines for Agip's well testing operations worldwide.
Asphaltenes & wax deposition in petroleum production systemChirag Vanecha
This document discusses asphaltene and wax deposition in production systems and remedial measures. It provides information on the characteristics of paraffins and asphaltenes, factors that influence their deposition, and methods to remove deposits. Common removal techniques include mechanical cleaning, applying heat, using solvents, and adding dispersants. Preventing deposition involves methods such as using crystal modifiers, plastic pipelines, deposition inhibitors, and downhole heaters. The document also covers asphaltene deposition in detail, including how it occurs, influencing factors, typical locations, measuring techniques, diagnosis, and preventive actions.
Natural gas processing technology sweetening processesMohamad Abdelraof
The document discusses hydrogen sulfide (H2S) concentration and toxicity levels at different ppm concentrations. It then discusses requirements for gas entering LNG plants and different sweetening processes used to remove sour gases like H2S and CO2. The amine sweetening process is described in detail, including major equipment used like absorbers, strippers, heat exchangers. Different amines used and their properties are also discussed. Mercury and nitrogen removal processes are briefly covered.
This document outlines the key steps in the liquefied natural gas (LNG) production process. It begins with extracting natural gas from the ground, then treating the gas to remove impurities. The treated gas is then condensed into a liquid by cooling it to -260°F through a multi-stage liquefaction process. The LNG is stored and transported in specialized cryogenic tanks on ships or trucks, then regasified back into gas form before being distributed through pipelines. The document provides details on each stage of the LNG value chain from production to regasification and discusses related technologies like compressed natural gas.
Valves operation and functions complete guideElsayed Amer
Eng. El Sayed Amer is a senior process and production engineer at Suez Oil Co. He has worked as a drilling and completion engineer for Weatherford drilling international. He is also an instructor for oil and gas courses. He is a member of several professional engineering organizations and certified in process modeling and reservoir simulation software. He has expertise in valves technology and operations in the process industry.
Common poisons include
Sulfur
Chlorides and other halides
Metals including arsenic, vanadium, mercury, alkali metals (including potassium)
Phosphates
Organo-metalics
The document discusses natural gas liquid (NGL) recovery from natural gas streams. It covers key terms, factors that affect recovery like gas composition and sales gas specifications, various process options for NGL recovery like low temperature separation and straight refrigeration, and provides an example problem calculating recovery values.
Three main methods are used to remove nitrogen from natural gas: cryogenic distillation, adsorption, and membrane separation. Cryogenic distillation involves using low temperatures and pressures to separate gas components. It is most effective at recovering ethane, propane, butane, and natural gasoline. Adsorption uses materials like molecular sieves to attract moisture and other compounds from the gas stream. Membrane separation exploits differences in molecular sizes to selectively permeate some components over others.
The document provides an overview of refrigeration systems, including:
1) It describes the basic principles and types of refrigeration systems, including vapor compression, absorption, and natural/mechanical refrigeration.
2) It explains common refrigerants used in primary and secondary systems, and discusses factors like thermal conductivity, viscosity, and thermodynamic properties that influence refrigerant selection.
3) It provides an overview of the main components in a typical vapor compression refrigeration system, including the evaporator, compressor, condenser, and expansion valve.
This document discusses waste heat recovery through the use of a reverse refrigeration cycle or organic Rankine cycle (ORC). It begins by outlining the problem of inefficient production processes that lose a significant amount of heat. The document then provides an overview of how a reverse refrigeration cycle works using a lower boiling point fluid to convert low-temperature waste heat into electricity. It discusses some key components of the cycle like the evaporator, turbine, condenser and pump. The document outlines the methodology that will be used to analyze implementing a reverse refrigeration cycle for waste heat recovery, including specifying the problem, evaluating heat sources, selecting a working fluid, calculating the ideal cycle, sizing heat exchangers, and calculating the real cycle
This document discusses natural gas liquefaction processes. It describes how natural gas can be cooled and liquefied by compressing it and using refrigerants in a thermodynamic cycle to transport heat from the natural gas to cooler temperatures. This allows natural gas to be transported over long distances in liquid form, taking up much less volume. Common liquefaction processes involve precooling, liquefying, and subcooling zones using refrigerants that match the cooling curves of the natural gas. Joule-Thomson and closed refrigeration cycles are also discussed as methods used for liquefaction.
This document discusses the thermodynamic analysis of a nitrogen liquefaction system based on the Kapitza cycle, which is a modified Claude cycle. Some key points:
- The Kapitza cycle was modified from the Claude cycle by eliminating the third heat exchanger and using a rotary expander instead of a reciprocating one.
- A mathematical model of the Kapitza cycle was developed using EES to evaluate parameters like expander flow fraction, isentropic efficiency, and the figure of merit (FOM) of the cycle.
- The FOM is defined as the ratio of theoretical minimum work to actual work and provides a measure of how close the real system comes to ideal performance.
LNG is regasified at receiving terminals by pumping it through pipes heated by various methods to warm it from a liquid to a gas. There are several types of regasification systems that utilize different heat sources like seawater or combustion. Intermediate fluid vaporizers use a secondary fluid like propane or water/glycol to indirectly heat the LNG through heat exchangers. Ambient air vaporizers use air as the heat source through surface heat exchangers. Open rack vaporizers use seawater in direct contact heat exchangers. Shell and tube vaporizers also use seawater but with the LNG in tubes surrounded by seawater in the shell. Submerged combustion vaporizers use underwater burn
A Systemic Optimization Approach for the Design of Natural Gas Dehydration PlantIJRES Journal
In designing dehydration units for natural gas, several critical parameters exist which can be varied to achieve a specified dew point depression. This paper studies the effects of varying number of trays in the contactor, glycol circulation rate through the contactor, temperature of the reboiler in the regenerator, amount of stripping gas used and operating pressure of the regenerator on the water content of the gas in a glycol dehydration unit. The effect of incorporating free water knock out (FWKO) tank before the absorber is also presented. An offshore platform in the Arctic region was chosen as the base case of this simulation and was modeled by using ASPEN HYSYS. Results show that the incorporation of FWKOT does not affect the TEG circulation rate required to approach equilibrium.
This document presents a summary of Pradeep Kumar's presentation on absorption refrigeration systems. The presentation covered the principle of operation, working fluids, experimental results using different fluids, and various designs of absorption refrigeration systems. It discussed how absorption systems use natural refrigerants like ammonia and water, have lower electricity usage than vapor compression systems, but also have lower COP. The presentation analyzed different absorption system designs including single effect, double effect, dual cycle, ejector systems, and combined cycle systems to improve performance. It provided diagrams to illustrate the various designs and discussed experimental results showing potential COP improvements over single effect systems.
The document outlines a senior design project to design, build, and test an optimized refrigeration system using a binary mixture of refrigerants. A team was formed to research various binary refrigerant mixtures to replace traditional single refrigerants and maximize the coefficient of performance (COP) of a domestic refrigerator. The team selected R-125 and R-152a as the binary mixture based on properties like enthalpy and safety. The project will involve building a refrigerator prototype, experimentally determining the optimal mass fraction mixture, and testing to verify the analytical optimization results.
The document discusses offshore gas production and processing systems. It explains that associated gas from an FPSO can be 1) exported, 2) used for gas lifting/injection, 3) used as fuel gas, or 4) flared during shutdowns. It then describes the multi-stage compression and cooling processes the gas undergoes, including scrubbing, dehydration using glycol or molecular sieves, and cooling to remove condensates before export via pipelines. Hydrates are gas-water compounds that can form and block pipes, but chemical injection or dehydration can prevent their formation.
This document discusses HVAC and refrigeration systems. It provides information on types of refrigerants used in centrifugal chillers and unitary AC units. It notes that R-11, R-12 and R-22 are being phased out due to being CFCs and lists phase-out dates for various refrigerants. It also discusses vapor compression systems, properties of commonly used refrigerants, and ways to improve system performance and reduce energy consumption through maintenance and optimization of operating parameters.
This document describes the design and fabrication of a solar powered lithium bromide vapor absorption refrigeration system. It uses lithium bromide and water as the working fluids, with solar energy powering the generator to separate the water vapor from the lithium bromide solution. The water vapor then condenses and evaporates to provide cooling, while the strong lithium bromide solution absorbs the water vapor back into a weak solution to complete the cycle. The document provides details on the system components, operating principles, and achievable COP between 0.7-0.8 using this environmentally friendly solar powered system.
This document discusses using cold boiler feed water from membrane deaerators for heat recovery in refineries. Specifically, it proposes supplying cold boiler feed water to waste heat streams to replace steam duty currently used in deaerators. As an example, it describes using cold feed water in the heat exchanger of a hydrocracker hydrogen production unit, which could recover more waste heat and reduce steam usage by 8.8 Gcal/h in the deaerator. Overall, maximizing heat recovery from waste streams with cold boiler feed water can significantly improve energy efficiency in refineries.
DOMESTIC REFRIGERATION USING LPG CYLINDERIRJET Journal
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1. Ferdowsi University of Mashhad.
Faculty of Engineering.
Chemical engineering department
Study of NGLs recovery plant
Name of supervisor : Dr. B. Aminshahidy
Name of student : Mohammed Al-isawi
3. 1-Introduction:
Most natural gas is processed to remove the heavier hydrocarbon liquids from the natural gas stream.
These heavier hydrocarbon liquids, commonly referred to as natural gas liquids (NGLs), include ethane,
propane, butanes, and natural gasoline.
• Recovery of NGL components in gas required for:
1- Hydrocarbon dew point control in a natural gas stream (to avoid the unsafe formation of a liquid phase during transport).
2- A source of revenue, as NGLs normally have significantly greater value as separate marketable products than as part of the natural gas stream.
4. Natural Gas: Any reservoir classified as natural gas reservoir
if the temperature of this reservoir above the critical
temperature of hydrocarbon system. The composition of
natural gas varies considerably from lean non-associated gas
to rich associated gas containing a significant intermediate
components (C2 –C6).
Associates Gas: Associated gas is produced from oil
reservoirs. This gas is dissolved in oil or exists in free gas
phase. Associated gas is produced in association with oil.
Non-Associated Gas: reservoirs that contain only natural gas
and no oil.
The gas reservoirs are classified as:
A. Gas-condensate reservoir
B. Wet gas reservoir
C. Dry gas reservoir
5. Gas-condensate reservoir:
•Retrograde Gas-condensate
Reservoir temperature lies between the critical temperature
and cricondentherm temperature. This category of gas
reservoir is a unique type of hydrocarbon accumulation in
that the special thermodynamic behavior of the reservoir
fluid is the controlling factor in the development and the
depletion process of the reservoir.
The associated physical characteristics.
1- Gas-oil ratios between 8,000 to 70,000 scf/STB.
2- Condensate gravity above 50o API.
3- Stock-tank liquid is usually water-white or slightly colored.
6. •Near Critical Gas-Condensate
The gas reservoir temperature is near critical temperature.
The volumetric behavior described through the isothermal
pressure declines and by corresponding liquid drop-out
curve.
7. Wet gas reservoir:
Reservoir temperature is above the cricondentherm of the
hydrocarbon mixture. Because the reservoir temperature
exceeds the cricondentherm of the hydrocarbon system the
reservoir fluid will always remain in the vapor phase region.
Wet gas reservoirs properties:
1- Gas-oil ratios between 60,000 to 100,000 scf/STB.
2- Stock-tank oil gravity above 60o API.
3- Liquid is water-white in color.
4- Separator conditions (pressure and temperature) lie
within the two phase region.
Dry gas reservoir:
The hydrocarbon mixture exists as a gas both in the
reservoir and the surface facilities. The only liquid associated
with gas from a dry gas reservoir is water. Usually a system
having a gas-oil ratio greater than 100,000 scf/STB is
considered to be a dry gas.
8. 2- NGL recovery process
2-2 Refrigeration Processes:
2-2-1 Mechanical Refrigeration:
Is a simple process used widely in gas conditioning
applications (e.g., hydrocarbon dew point controlling), but it is
also used in NGL recovery applications as the primary
refrigeration option or in conjunction with another
refrigeration option.
source of refrigeration when inlet pressure is low.
is supplied by a vapor-compression refrigeration cycle that
usually uses propane as the refrigerant and reciprocating or
centrifugal types of compressors to move the refrigerants
from the low- to high-pressure operating conditions.
A mechanical refrigeration process is adopted when sizeable
amounts of condensate are expected.
Propane is by far the most popular refrigerant in the gas
processing applications. It is readily available (often
manufactured on-site), is inexpensive, and has a “good” vapor
pressure curve. It is flammable, but this is not a significant
problem if proper consideration is given to the design and
operation of the facility
9. A-Cascade Refrigeration:
Cascade refrigeration refers to two refrigeration circuits thermally connected by a cascade condenser, which is the condenser of the low-
temperature circuit and the evaporator of the high-temperature circuit. A cascade system utilizes one refrigerant to condense the other primary
refrigerant, which is operating at the desired evaporator temperature. This approach is usually used for temperature levels below –90 F, when
light hydrocarbon gases or other low boiling gases and vapors are being cooled. To obtain the highest overall efficiency for the system, the
refrigerants for the two superimposed systems are different. Cascade refrigeration systems are not common in gas processing.
B-Mixed Refrigerants:
An alternative to cascade refrigeration is to use a mixed refrigerant. A mixed refrigerant is a mixture of two or more components. The light
components lower the evaporation temperature, and the heavier components allow condensation at ambient temperature. The evaporation
process takes place over a temperature range rather than at a constant temperature as with pure component refrigerants. The mixed refrigerant
is blended so that its evaporation curve matches the cooling curve for the process fluid. Heat transfer occurs in a countercurrent exchanger,
probably aluminum plate-fin, rather than a kettle-type chiller. Mixed refrigerants have the advantage of better thermal efficiency because
refrigeration is always being provided at the warmest possible temperature. The amount of equipment is also reduced to a cascade system.
Disadvantages include a more complex design and the tendency for the heavier components to concentrate in the chiller unless the refrigerant is
totally vaporized.
Advantages and drawbacks:
1. Mechanical refrigeration is a simple and flexible process, adopted when sizeable amounts of condensate are expected.
2. this process occupies a large area, and the equipment involved in such systems is heavy with respect to other NGL recovery alternatives such
as the Turbo expansion process.
3. requires a high maintenance cost and a high utility requirement.
4. If the feed gas contains a large amount of inert components, the efficiency of process will be reduced due to the interference of the inert.
5. Propane refrigeration becomes inappropriate for feed throughputs of less than 25 million standard cubic feet per day (MMSCFD).
6. the amount of C02 in the feed must be as low as temperatures of the process can cause freezing of C02
10. 2-2-2 Self-Refrigeration:
in the self-refrigeration process the inlet gas is cooled by
isenthalpic expansion (i.e., Joule–Thomson expansion)
This process is usually used in hydrocarbon dew point controlling
applications, but is also used in NGL recovery applications. If the
objective is to recover ethane or more propane than obtainable
by mechanical refrigeration, a good process can be self
refrigeration, which is particularly applicable for smaller gas
volumes of 5–10 MMcfd.
Advantages and drawbacks:
1. The advantages of this process are simplicity and low cost.
2. The primary drawback is the pressure Drop that occurs
across the valve, which often ranges from 500 to 1,000 psia.
3. This process may be attractive when the plant inlet pressure
is sufficiently high to eliminate the need for compression.
4. Due to this chilling, the self-refrigeration process achieves
high ethane recoveries; typical ethane recoveries are about
70%.
11. 2-2-3 Cryogenic Refrigeration:
processes are commonly used for deep NGL recovery, with minimum
temperatures below –150 F achieved routinely. In the cryogenic or
turbo-expander plant, the chiller or Joule–Thomson ( JT) valve used in
the two previous processes is replaced by an expansion turbine. As
the entering gas expands, it supplies work to the turbine shaft, thus
reducing the gas enthalpy. This decrease in enthalpy causes a much
larger temperature drop than that found in the simple JT (constant
enthalpy) process.
Cryogenic processes can be applied only if the gas pressure after
expansion is sufficiently high for condensation of the heavier
components to take place.
Cryogenic refrigeration processes are also used for hydrocarbon dew
point controlling applications in which the required pressure drop
across the expander is substantially less than that required across a JT
valve, resulting in lower compression costs over the life of the field.
The cryogenic refrigeration process is generally the most technically
advanced type of NGL recovery used today. This combines high
recovery levels (typically allowing full recovery of all of the propane
and heavier NGLs and recovery of 50% to more than 90% of the
ethane) with low capital cost and easy operation . This is less
attractive on very rich gas streams or where the light NGL product (C2
andC3) are not marketable, whereas for gases very rich in NGL,
simple refrigeration is probably the best choice.
.
12. Modern NGL Recovery Processes:
Modern NGL recovery processes are based on turbo expanders
using various reflux configurations. There are many patented
processes that can be used to improve NGL recovery, either for
propane recovery or ethane recovery.
A-Dual-Column Reflux Process The dual-column process.
the first column acts as an absorber recovering the bulk of the NGL
components and the second column serves as deethanizer during
propane recovery and demethanizer during ethane recovery.
refluxes to the dual-column design process was originally
configured for high propane recovery. The process is very efficient
and can achieve over 99% propane recovery.
B-Ortloff's Gas Sub cooled Process.
Increasing ethane recovery beyond the 80% achievable with the
conventional Design requires that a source of reflux must be
developed for the demethanizer.
Ortloff’s Gas Subcooled Process (GSP) was developed to overcome
this problem and others encountered with the conventional
expander scheme. GSP configuration allows recovering ethane
from around 50% to 99%, with propane recovery at 99%.
13. C- Ortloff SCORE The SCORE (single-column overhead recycle
process).
The SCORE process is designed to recover over 99% propane
from the feed gas in a single-column configuration.
This process recovers the C3+ hydrocarbons from the feed gas
and produces a lean residual gas for sales. Alternatively, the
residue gas can be
sent to the natural gas liquefaction plant.
D-Residue Gas Recycle
When high ethane recovery is required, additional cooling is
required by recycling a portion of the residue gas as reflux to the
absorber.
14. E-Fluor Twin-Column High Absorption Process.
When the sales gas must be compressed to the pipeline pressure, it is
desirable to operate the demethanizer at as high a pressure as
possible.
Fluor has developed the twincolumn high absorption process (TCHAP)
using a dual-column approach. The first column operates as an
absorber at 600 psig or higher pressure and is designed for bulk
absorption. The second column, which serves as a demethanizer or
deethanizer, operates at a lower pressure at about 450 psig. To
improve NGL recovery, the overhead vapor from the second column is
recycled using a small overhead compressor. The recycle gas is chilled
using the absorber overhead vapor and used as a cold reflux to the
absorber.
F-Fluor Twin-Reflux Absorption Process.
NGL recovery units are frequently required to operate in ethane
rejection mode when the profit margin of the ethane product is low.
During these periods, the NGL recovery units are required to reject
their ethane content to the sales gas Pipeline.
When operated in ethane rejection mode, some propane is lost with
the rejected ethane, resulting in a loss of liquid revenue.
The process can be operated on ethane recovery and can also operate
in ethane rejection while maintaining high propane recovery.
15. Advantages and drawbacks:
1. The turbo expander is compact with a low weight and low space requirement compared with absorption equipment or external refrigeration
systems.
2. The operational as well as capital costs are relatively low.
3. Another disadvantage of this process is the height required for the de-methanizer tower.
4. The installation of an elevated tower is extremely difficult on offshore plants and could also present operational problems due to the
common strong winds in the sea .
5. Another drawback is the lack of tolerance to wet gas in the feed since it can damage the mechanical system. Nevertheless, a certain amount
of liquid can be managed in the exit of the equipment.
6. Another important limitation of the turbo expander is the elevated maintenance cost.
7. the operation of this equipment represents a major issue in terms of safety.
16. 2-3 Lean Oil Absorption:
Lean oil absorption is the oldest and least efficient process to
recover NGLs. In this process the gas to be processed is
contacted in a packed or tray absorption column (typically
operated at the ambient temperature and a pressure close to
the sales gas pressure) with an absorption oil. which absorbs
preferentially the most heavy hydrocarbons (C3,C7+) from
natural gas.
Note that the oil absorption plant cannot recover ethane and
propane effectively when it requires circulating large amounts of
absorption oil, demands attendant maintenance, and consumes
too much fuel.
oil absorption plant can be modified to improve its propane
recovery by adding a propane refrigeration cycle for cooling. The
refrigerated lean oil absorption process improves the recovery
of propane to the 90% level, and depending on the gas
composition, up to 40% of ethane may be recovered.
Lean oil absorption plants are not as popular as they once were
and are rarely They are expensive and more complex to operate,
and it is difficult to predict their efficiency at removing liquids
from the gas as the lean oil deteriorates with time.
17. Advantages and drawbacks:
1. This process is selective to propane, and a low ethane recovery is achieved.
2. Inert gases in the feed gas do not interfere with the process of the absorption of the hydrocarbon and pre-treatment of the gas is not
needed. This is also true for feed gas with water.
3. For the case of associate gas treatment, this process is rarely used.
4. There are also the possible environmental impacts of chemical use including spills, storage of virgin/waste oil, etc.
5. For feed pressures below 2,800 kPa absorption systems operate well, but for higher pressures a dual pressure absorber column with high and
low pressure sections is required. Above 8,500 kPa the efficiency of the absorption system will be reduced.
6. The efficiency of the absorption process is improved with rich gases.
7. The absorption systems also suffer from the high-energy costs needed to run solvent circulating pumps and also regeneration of oil.
18. 2-4 Solid Bed Adsorption:
The solid bed adsorption method uses adsorbents that have the
capability to adsorb heavy hydrocarbons from natural gas. The
adsorbent may be silica gel or activated charcoal, activated
alumina cannot be used .
This process is appropriate for relatively low concentrations of
heavy hydrocarbons. It can be also appropriate if the gas is at a
high pressure, close to the cricondenbar. In this case, refrigeration
processes become ineffective and separation by adsorption may
offer the only way to obtain the required specifications.
Advantages and drawbacks:
1. An adsorption process requires enormous amount of energy
due to the regeneration process.
2. the equipment involved is heavy and expensive.
3. Safety is a considerable issue for this process since the high
temperature with the hydrocarbon solids could produce a fire
or related accident.
19. 2-5 Membrane Separation Process:
The membrane separation process offers a simple and low-cost
solution for removal and recovery of heavy hydrocarbons from
natural gas.
The separation process is based on a high-flux membrane that
selectively permeates heavy hydrocarbons compared to methane.
These hydrocarbons permeate the membrane and are recovered as
a liquid after recompression and condensation. The residue stream
from the membrane is partially depleted of heavy hydrocarbons
and is then sent to the sales gas stream.
Gas permeation membranes are usually made with vitreous
polymers that exhibit good diffusional selectivity. However, for
separation to be effective, the membrane must be very permeable
with respect to the contamination to be separated, which passes
through the membrane driven by pressure difference, and it must
be relatively impermeable to methane.
Membrane systems are very versatile and are designed to process a
wide range of feed conditions. With very compact footprint and
low weight, these systems are well suited for offshore applications.
Membranes could potentially remove water and heavier
hydrocarbons simultaneously, thus making these systems an
attractive alternative to replace the conventional dehydration and
hydrocarbon dew pointing design.
20. Advantages and drawbacks:
1. membranes are operationally simple and do not require additional separation agents
2. membrane is the flexibility of its operations. This means production conditions can be modified, and the membrane process can be easily
adapted to it.
3. The membranes are arranged in modules, which can be orientated in horizontal or vertical positions.
4. the membrane separation technologies are appropriate for small to medium production
5. Membranes typically have lower installation, operation, and maintenance costs compared with other technologies.
21. 2-6 Twister Supersonic Separation:
Twister supersonic technology uses the concept that feed gas passing
through a nozzle accelerates to supersonic speed, suffering a pressure
and temperature drop, where the temperature drop causes condensation
of the heavier hydrocarbons.
Condensation and separation at supersonic velocity are key to achieving a
significant reduction in both capital and operating costs.
Twister supersonic technology shares similar benefits of simplicity,
robustness, and ease of operation as the LTS ( JT valve). Two studies
showed that Twister can recover more hydrocarbons than the JT valve for
the same pressure drop.
Therefore, it could potentially be operated at a reduced pressure drop for
the same performance as a JT valve. This reduces the sales gas
compression power and cost. It can be particularly interesting for
debottlenecking or upgrading existing gas plants. An additional benefit of
Twister is the ability to remove water and hydrocarbons simultaneously
in its tubes. Twister technology also offers environmentally friendly,
chemical-free operation within a small footprint.
22. Advantages and drawbacks:
1. Twister supersonic technology shares similar benefits of simplicity, robustness, and ease of operation as the LTS (JT valve). Two studies
showed that Twister can recover more hydrocarbons than the JT valve for the same pressure drop. Therefore, it could potentially be operated
at a reduced pressure drop for the same performance as a JT valve. This reduces the sales gas compression power and cost.
2. Twister is the ability to remove water and hydrocarbons simultaneously in its tubes.
3. Twister technology also offers environmentally friendly.
4. Twister BV introduced the Twister SWIRL valve, which improves HC dew pointing performance of existing LTS plants by improving the
separation of two-phase flow across a pressure reduction valve, such as a choke valve, JT valve, or control valve.
in turn, significantly improves the liquid separation efficiency of downstream separators. This improved separation can be used to either increase
flow capacity of existing LTS plants or to reduce the pressure drop required for JT cooling or to lower the HC dew point and also reduce glycol
carryover.
23. 2-7 Selection of NGL Recovery Processes:
The case Recovery process
sufficiently high inlet pressure. the self-refrigeration process requires the lowest capital
investment.
the feed gas pressure is close to the treated gas pressure,
over a large pressure drop range.
more economical to employ a cryogenic refrigeration
process.
When the feed gas pressure is clearly below the required
pipeline pressure.
most economical to apply mechanical refrigeration.
When the feed gas pressure is equal to or lower than the
required pipeline pressure,.
solid bed adsorption seems a good option.
24. 3-NGL FRACTIONATION
Once NGLs have been removed from the natural gas stream, they must be fractionated into their base components, which can be sold as high-
purity products. Fractionation of the NGLs may take place in the gas plant but may also be performed downstream, usually in a regional NGL
fractionation center.
25. 4-LIQUIDS PROCESSING
Hydrocarbon condensate recovered from natural gas must be treated to make it safe and environmentally acceptable for storage, processing, and
export. Therefore, removing water and salt is mandatory to avoid corrosion. Separation of any dissolved gases, which belong to the light
hydrocarbon components (methane and ethane in particular), along with hydrogen sulfide, mercaptans, and other sulfur compounds, will make
condensate safe and environmentally acceptable to handle.
4-1 Sweetening
If acidic and sulfur compounds are present in the feed gas and have not been removed before NGL recovery, then they will end up in the NGL
products. The distribution of the contaminants for the various NGL products
A. Caustic Processes
A number of caustic processes, both regenerative and non-regenerative, can be used to remove sulfur compounds from hydrocarbon liquids. The
simplest process is the use of a non-regenerative solid potassium hydroxide (KOH) bed, which is effective for removal of H2S but not for other
sulfur compounds. One of the common processes for treating hydrocarbon liquids is the use of regenerative caustic wash with sodium hydroxide
(NaOH).
B. Adsorption
Molecular sieve technology is commonly used for treating NGLs. Molecular sieves can be used for removal of sulfur compounds (H2S, COS, and
mercaptans) either in the gas or liquid phase. There are advantages and disadvantages for either option. The adsorber efficiency is higher in the
gas phase since the mass transfer rate of sulfur compounds is much faster in the gas phase.
C. Amine Treating
Amine treating is an attractive alternative, especially when an amine gas sweetening unit is already on-site. In such cases, the liquid treating unit
can often be operated using a slipstream of amine from the main sweetening unit. Amine treating is often used upstream of caustic treaters to
minimize caustic consumption caused by irreversible reactions with CO2.
26. 4-2 NGLs stabilization
Process separation of the very light hydrocarbon (methane
and ethane) from the heavier components. Increasing the
amount of intermediate (C3 to C5) and heavy component.
This process is performed primarily in order to reduce the
vapor pressure of the condensate liquids so that a vapor
phase is not produced upon flashing the liquid to
atmospheric storage tanks.
Flash vaporization:
Is a simple operation employing only two or three flash
tanks this process is similar to stage separation utilizing the
equilibrium principles between the vapor and condensate
phases. Equilibrium vaporization occurs when the vapor and
condensate phases are in equilibrium at the temperature
and pressure of separation.
Fractionation:
Stabilization by fractionation is a detailed process, very
popular in the industry and precise enough to produce
liquids of suitable vapor pressure. During the operation, the
undesirable components (low boiling-point hydrocarbons
and hydrogen-sulfide gas) are removed.
27. NGLs market:
The global natural gas liquids market size is expected to
reach 11,468 kilo barrels/day by 2022 from 7,306 kilo
barrels/day in 2015 with a CAGR of 6.67% from 2016 to
2022.
The global natural gas liquids market is segmented based on
product type and geography. According to product type, the
market is categorized into ethane, propane, isobutene, and
others, which include normal butane, pentane, and pentane
plus. Geographically, the market is analyzed across North
America, Europe, Asia-Pacific, and LAMEA.