Report

Project Report On Molecular Sieve Turbo Expander (MSTE) Plant (Sylhet Gas Fields Limited, a Company of Petrobangla)

Supervisor Dr. Muhammad Nurunnabi Siddiquee Associate Professor Department of Chemical Engineering and Polymer Science Shahjalal University of Science & Technology, Sylhet, Bangladesh.

Submitted By Ahsan Habib Registration No: 2012332008

Approval This is to certify that, Ahsan Habib, Registration no: 2012332008, Session: 2012-2013, a student of Chemical Engineering & Polymer Science of Shahjalal University of Science & Technolgy, Sylhet, Bangladesh, has successfully completed the project work in MSTE Plant (Sylhet Gas Fields Limited), for the fulfillment of the degree of B.Sc. in Chemical Engineering & Polymer Science.

SUPERVISOR

……………………. Dr. Muhammad Nurunnabi Siddiquee Associate Professor Department of Chemical Engineering and Polymer Science Shahjalal University of Science & Technology, Sylhet, Bangladesh.

Acknowledgement First of all, I would like to express my deepest sense of faith and gratitude to almighty Allah who is merciful to all and all good things that happened and is being happened by his wish. I am highly grateful to thank and express my gratitude to Prof. Dr. Abu Yousuf , Head, Department of Chemical Engineering and Polymer Science, Shahjalal University of Science and Technology, Sylhet. I express my thanks and gratitude to our academic supervisor Dr. Muhammad Nurunnabi Siddiquee, Associate Professor, Department of Chemical Engineering and Polymer Sciene, Shahjalal University of Science and Technology, Sylhet for his sincere guidance and valuable advice throughout the progress of internship. I would also like to express my gratitude to all teachers of our department. We are also grateful to:

Engr. Md. Abdul Jalil Pramanik (DGM, Kailashtila Gas Fields) Mr. Forrukh Ahmed (Manager, Operation, MSTE Plant)

For their assistance and cooperation throughout the internship. Also thanks to the all the members of MSTE Gas Fields Limited

Author

Abstract Natural gas processing consists of separating all of the various hydrocarbons and fluids from the pure natural gas, to produce what is known as ‘pipeline quality’ dry natural gas. Major transportation pipelines usually impose restrictions on the make-up of the natural gas that is allowed into the pipeline. That means that before the natural gas can be transported it must be purified. While the ethane, propane, butane, and pentanes must be removed from natural gas. this does not mean that they are all ‘waste products’. In fact, associated hydrocarbons, known as ‘natural gas liquids’ (NGLs) can be very valuable byproducts of natural gas processing. NGLs include ethane, propane, butane, iso-butane, and natural gasoline. These NGLs are sold separately and have a variety of different uses; including enhancing oil recovery in oil wells, providing raw materials for oil refineries or petrochemical plants, and as sources of energy.

MSTE Plant is the only plant in South Asia which produces NGL through Turboexpander Technology (At present bypass JT technology). In this work I tried to discuss the effectiveness and advantages of more energy and cost friendly Supersonic Separation Technology over these existing Technologies.

Table of Content Chapter 1: Introduction ……………………………………………………..…………………………. (8 – 11)

1.1 Introduction to the Natural Gas Industry ……………………………………………………..8 1.2 Characteristics of Natural Gas …………………………………………………………………..8 1.3 Natural Gas Conditioning and Processing …………………………………………………….8 1.4 Gas Conditioning ………………………………………………………………………………………..9 1.5 Gas Processing …………………………………………………………………………………………...9 1.6 Plant Products ……………………………………………………………………………………………9 1.7 Hydrocarbon Recovery Processes………………………………………………………………10 1.8 Cryogenic Expansion …………………………………………………………………………………10 1.9 Development of Cryogenic Expander Plant Technology …………………………….10 1.10 An Overview of MSTE Plant……………………………………………………………………..11

Chapter 2: Process Flow Description………………………………………………………………. (13-22) 2.1.1 Gas Well Heater ……………………………………………………………………………………13 2.1.2 Inlet separator ………………………………………………………………………………………13 2.1.3 Abnormal Operating Conditions ……………………………………………………………13 2.2 Stabilizer System………………………………………………………………………………………14 2.2.1 Stabilizer ………………………………………………………………………………………………14 2.2.2 Stabilizer Water Separator……………………………………………………………………14 2.2.3 Caution………………………………………………………………………………………………….14 2.2.4 Abnormal Operating Condition………………………………………………………………14 2.3.1 Inlet Filter separators………………………………………………………………………….…15

2.3.2 Abnormal Operating Conditions………………………………………………………………15 2.4.1 Inlet Gas Dehydration System……………………………………………………………….…15 2.4.2 Molecular Sieve Dehydration System………………………………………………………15 2.4.3 Abnormal Operating Problems……………………………………………………..…………17 2.5 Regeneration Gas System………………………………………………………………………..…17 2.5.1 Regeneration Gas Heater…………………………………………………………………………17 2.5.2 Regeneration Gas Cooler…………………………………………………………………….……17 2.5.3 Regeneration Gas Scrubber…………………………………………………………….…………17 2.6 Cryogenic Process Flow Description……………………………………………………..………18 2.6.1 Inlet Gas Cooling…………………………………………………………………………..……………18 2.6.2 Cold Separator…………………………………………………………………………………………18 2.6.3 Expander Separator…………………………………………………………………….……………19 2.6.4 Residue Gas Handling………………………………………………………………………………19 2.6.5 De-Ethanizer……………………………………………………………………………………………19 2.6.6 De-ethanizer Reboiler………………………………………………………………………………19 2.6.7 De-ethanizer Reflux Condenser…………………………………………………………………20 2.6.8 NGL Product Coolers…………………………………………………………………………………20 2.6.9 NGL Flash System………………………………………………………………………………..……20 2.6.10 L.P. Flash Drum…………………………………………………………………………………….…21 2.7.1 Product Booster Pumps……………………………………………………………………………21 2.7.2 NGL Product Handling………………………………………………………………………………21 Simplified Flow Diagram……………………………………………………………………………………22

Chapter 3: A Comparative Study of Supersonic Gas Separation…………………… (24-37)

3.1 NGL/LPG Recovery and Fractionation………………………………………………………24 3.2.1 An Overview On Turboexpander …………………………………………………………25 3.2.2 TurboExpander In MSTE Plant ……………………………………………………………..26 3.2.3 Operational Error …………………………………………………………………………………26 3.3.1 The Joule-Thomson (JT) effect ………………………………………………………………26 3.3.2 Definitions of Symbols Used to Describe the Joule-Thomson Effect ……. 27 3.3.3 The Joule-Thomson co-efficient ……………………………………………………………29 3.3.4 Inversion Temperature …………………………………………………………………………30 3.4.1 Supersonic Gas Separation ……………………………………………………………………32 3.4.2 Laval Nozzle …………………………………………………………………………………………32 3.4.3 Supersonic Separation Technologies ……………………………………………………33 3.4.4 3S Separator Flow Scheme …………………………………………………………………..33 3.4.5 3-S Technology Studies ………………………………………………………………………34 3.4.6 Comparison among Existing Technologies …………………………………………35 3.4.7 Advantages in Field Plants …………………………………………………………………36 3.4.8 Conclusions ………………………………………………………………………………………36

References ………………………………………………………………………………………………37

1.1 Introduction to the Natural Gas Industry: Natural gas has been used commercially as a fuel for over a hundred and thirty years in America and for centuries in China. The production and distribution of natural gas has become an important segment of our domestic economy. Engineering methods have been developed for designing facilities to produce the gas from the earth, to separate it from liquid hydrocarbons, and to deliver this superior gaseous fuel to market. Natural gas is composed primarily of methane (CH4) with minor amounts of the paraffin hydrocarbon family: ethane (C2H6), propane (C3H8) and butanes (C4H10). Non hydrocarbon constituents include nitrogen, hydrogen sulfide, carbon dioxide, helium, and water vapor. Although natural gas occurs as gas under pressure in porous rock beneath the earth’s surface, often it is in solution with crude oil or condensate. Then it may be described as the volatile portion of petroleum.

1.2 Characteristics of Natural Gas: Natural gas is a mixture of hydrocarbon gases along with some impurities that are the result of decomposed organic material. When raw natural gas is withdrawn from underground reservoirs to supply energy demands, these impurities are considered objectionable and are usually removed by various processing schemes. Usually the ethane and heavier fractions are removed for additional processing because of their high market value as gasoline blending stock and chemical raw feedstock. What usually reaches the transmission line for sale as natural gas is mostly a mixture of methane and ethane with some small percentage of propane. Methane is usually the largest percentage.

1.3 Natural Gas Conditioning and Processing: The natural gas industry may be divided into four main subdivisions:    

Drilling Discovery Conditioning and Processing Production Transportation

1.4 Gas Conditioning: Gas conditioning refers to processes required to condition the gas to make it marketable, i.e, removal of impurities, water, excess hydrocarbon liquids, control of delivery pressure through the use of pressure reducing regulators, compressors, etc. Impurities are usually found in natural gas and must be removed because they cause difficulties in handling and processing. Components such as hydrogen sulfide, carbon dioxide, mercaptans, water vapor, noncombustible gases (such as nitrogen and helium), pentanes, and the heavier hydrocarbons are generally considered impurities since the processed natural gas is usually burned as fuel and these compounds may cause extremely unreliable and hazardous combustion conditions for the consumer.

1.5 Gas Processing: Gas processing plants are usually designed to remove certain valuable products over and above those needed to make the gas marketable; that is natural gasoline, butane, propane, ethane, and even methane in some instances. In order to do so, plant processes include many of the functions ordinarily performed by gas conditioning equipment such as dehydration and hydrogen sulfide removal. Plants usually provide fractionating equipment to separate the liquid hydrocarbons recovered into pure or specified mixtures. Where hydrogen sulfide is removed from the gas, a plant may include facilities to recover elemental sulfur from this impurity.

1.6 Plant Products: Plant products are normally considered to be those materials recovered from the natural gas stream that have value in addition to the residue gas itself. The type of operation determines the product to be saved. Cycling plants may produce everything from ethane to naphtha or heavy condensate, including motor fuels. With the growth of the worldwide market for natural gas liquids (NGL), additional processes for higher recovery of the ethane, propane and butane fractions, which make up NGL, have been developed. These fractions are valuable for the petrochemical industry raw stocks. Sulfur, of course, may be produced by plants handling gas containing hydrogen sulfide.

1.7 Hydrocarbon Recovery Processes: The recovery of liquid hydrocarbons from natural gas in a plant is accomplished by changing conditions of the gas so that the equilibrium between the various components is upset, causing some components to condense and others to vaporize in attempting to reach a new equilibrium. The conditions that are changed may be pressure, temperature, or the introduction of a different material into the gas stream. More likely, it will be a combination of all three.

1.8 Cryogenic Expansion: The most recent development in low temperature, high recovery plants is the cryogenic plant using the turbo expander. In this plant, the gas is expanded through a turbine compressor from which it exhausts at extremely low temperature in the range of -160° to -180°F. At these low temperatures, most of the gas except methane is condensed. The liquids are then fractionated to recover the desired products.

1.9 Development of Cryogenic Expander Plant Technology: Primary attributes of the expander type plant over alternative processes include:       

Mechanical Simplicity Process Simplicity Decreased Maintenance Reduced Utilities Safety Labor Reduced operation supplies and waste streams

1.10 An Overview of MSTE Plant:

1. Location

: PO Golapganj, PS Golapganj, District Sylhet

2. Year of Gas Field discovery

: 1961

3. Year of MSTE Plant installation

: 1992-1995

4. Gas Field discovered by

: Pakistan Shell Oil Company (PSOC)

5. Gas reserve (recoverable)

1224 BCF (3D Seismic 2012) : 2760 BCF (RPS Energy 2009) 1992 BCF (HCU 2004)

6. Commencement of Gas Production : 25 September 1995 7.

Commencement of commercial operation of MSTE

: 25 September 1995

8.

Cumulative production of gas (upto 31 May 2015)

:

230.40 (KTL) + 415.40 (MSTE) = 645.8 BCF (structure total)

9. Condensate Gas Ratio (CGR)

: 18.5 bbl/MMSCF

10. Heating value of sales gas

: 1042.73 Btu/scft

11. Process Plant & its Capacity

:

Molecular Sieve Turbo Expander Plant (MSTE), 1 x 90 MMSCFD

12. Customers

:

Gas: JGTDSL, TGTDCL Liquids: RPGCL, SRL, Aqua, PHP, CRL, CVOPRL

A 90 million cubic feet/day capacity Molecular Sieve Turbo Expander (MSTE) Plant situated at the location of KTL-2 was installed in 1992-95 by Press Construction (UK) Ltd. MSTE Plant went into commercial operation in September 1995. This plant, first of its kind in Bangladesh, employs modern cryogenic mechanism to recover liquefiable hydrocarbons. The advantage of employing this mechanism is that an additional amount of Natural Gas liquids (NGL) in the range of 8-10 bbl/MMSCF is being recovered which would have otherwise remained unrecovered had conventional plant been used. The present average condensate/NGL recovery from the MSTE Plant is around 18 bbl/MMSCF. The gas delivered from the MSTE Plant is fed through the 24 inch diameter National Gas Grid Line. Of the total condensate/NGL recovered at the MSTE Plant, about 600 bbl/day is supplied as feed to LPG Plant of RPGCL to fractionate the NGL into LPG and MS (Motor Spirit). LPG is subsequently marketed by BPC in LPG Bottle/Cylinder.

Process Flow Description

Inlet Heaters Flow Diagram: 2.1.1 Gas Well Heater: The inlet heater is a double pipe type heat exchanger with the inlet gas on the tube side and hot oil on the shell side. The inlet gas from the heater flows through a pressure control valve station and enters the top of the inlet separator. To prevent hydrate formation across pressure valve the pressure is reduced 82.6 bar, a flow of 307°F hot oil is used on the shell side of the heat exchanger to warm the inlet gas. The hot oil flow is 6573 Kg/Hr. Decreasing temperature increases the flow of hot oil.

2.1.2 Inlet separator: The inlet gas flows to the inlet separator where free water is separated from the hydrocarbon condensate liquid and he gas is separated from the liquids. The water is heavier so it separates and migrates to a boot mounted on the bottom of the vessel. A water hydrocarbon interface level is maintained in the boot by a level controller and control valve in the boot bottom outlet line to the closed drain. The hydrocarbon liquid floats on top of the water and must accumulate to a vessel 610 MM above the bottom of the vessel before it can enter the hydrocarbon section of the vessel.

2.1.3 Abnormal Operating Conditions: 1) 2) 3) 4) 5) 6) 7) 8)

High pressure on inlet gas well pipeline to plant. High pressure on inlet gas after pressure reduction valves. Low temperature from inlet gas heater. Low level in inlet separator “boot” High level in inlet separator “boot” Low level in separator hydrocarbon end. High level in separator hydrocarbon end. Low pressure in inlet separator.

2.2 Stabilizer System: The stabilizer system provides a means of removing light hydrocarbons, mostly methane and ethane and most propane and some H2O, N2 and CO2 entrained in recovered condensate from the three inlet gas separators.

2.2.1 Stabilizer: The stabilizer is a fractionation tower used to make a rough cut of the hydrocarbon condensate from the inlet separators. At design condition, tower pressure of 12.1 Bar and a reboiler outlet temperature of 220°C. 97% of the ethane and lighter hydrocarbon components and 38% of the propane exit the top of the tower and 62% of the propane plus heavier components exit the bottom as a stabilized NGL product. In addition to stabilizing the NGL product, the stabilizer removes all of the N2 and CO2 from the feed stream. 2.2.2 Stabilizer Water Separator: The tower has one feed source, 18.1°C condensate from the three inlet gas separators which enters onto the top tray #1. The feed also provides reflux liquid for product separation. The pressure is decreased from 103.4 Bar to 12.1 Bar as it enters the stabilizer resulting in the 18.1°C feed temperature. The total liquid feed from the 3 inlet separators is 5.01 M 3/Hr, however, some flashing occurs across the level control valves in the 3 feed lines. The tower feed is saturated with water; therefore a water separator is required to remove the water. The separator is fed from a draw-off tray below tray #8 and returns hydrocarbon condensate feed beneath the draw-off tray. In the separator section water is separated from the hydrocarbon condensate and accumulated in the separator boot. A water/hydrocarbon condensate interface should be maintained at all times to insure proper operation. Water accumulated in the separator boot must be drained manually at regular intervals. 2.2.3 Caution: If water is not drained from the separator, stabilizer flooding will occur, reducing the efficiency of the stabilizer. This will result in off-spec NGL product in the bottom of the tower.

2.2.4 Abnormal Operating Condition: 1) Stabilizer High Pressure 2) Stabilizer NGL off-spec, excess light ends in NGL. 3) Stabilizer Reboiler high level.

2.3.1 Inlet Filter separators: The inlet filter separator is the final cleanup of the total inlet feed gas flow from the inlet separators and protects the expensive molecular sieve in the dehydrators. Two 100% units are provided and one is a spare. The unit has an inlet filter area with replaceable filter elements in the first stage and a vane type mist extractor in the second stage to knockout entrained liquid droplets. A small bottle is placed below each stage of the filter, all liquid that accumulates falls into the divided bottle. Each end of the bottle has its own level control loop for pressuring the liquid into the closed drain. Low and high level alarms are provided and on the second stage of each unit a high level switch is provided to shut down the plant to prevent damage to the dehydrator sieve. A differential pressure switch is placed across the filter elements to warn that they are dirty. 2.3.2 Abnormal Operating Conditions: 1) Inlet filter separator high level. 2) Inlet filter separator high high level. 3) Inlet filter separator high DP. 2.4.1 Inlet Gas Dehydration System: The sole purpose of the dehydrators is the total removal of all moisture in the process gas stream. The gas stream entering the cryogenic expander plant must be dehydrated to as low a dew-point (the temperature at which a vapor begins to deposit as a liquid) as possibly due to the extremely be subjected. The importance of inlet gas dehydration and proper operation of this system cannot be over emphasized.

2.4.2 Molecular Sieve Dehydration System: After final cleanup in the inlet filter separator, the inlet gas processing conditions of about 108,320 M3/Hr, 103.1 Bar pressure and 19°C temperature, the inlet feed gas is down-flow dehydrated of moisture in the Mol Sieve system on 8 hour cycles. These two dehydrators are filled with molecular sieve desiccant. This porous bead looking material has tiny cavities that are big enough to trap water molecules, but small enough to allow hydrocarbon gas molecules to flow by. There are no “process controls” as such on mol sieve beds, but the vessel switching valves are time cycle controlled. There is a high moisture content alarm downstream of the bed to alert of a malfunction in the sieve, and there are shutdown functions to protect the cryogenic plant equipment if there is a major malfunction in the mol sieve system.

Mol sieve regeneration is the part of the process where water vapor is driven from the sieve cavities by flowing very hot, dry gas over the sieve at reduced system pressures. The plant’s regeneration scheme uses hot oil to heat dry, residue gas to about 232°C at 38 Bar. This combination of temperature and low pressure “ultra dries” the mol sieve so dew-points for cryogenic processing is obtainable. Typical regeneration gas process conditions for the plant require 3830 M3/Hr of residue gas, 38 Bar pressure and 30.9°C temperature to the regeneration gas heater. At least 5730 Kg/Hr of 307°C hot oil is necessary to transfer the required heat for regeneration gas temperatures of 232°C. The regeneration gas temperature from the heater is controlled manually by FI-840 in the hot oil line. The regeneration gas flow is controlled automatically by a control panel mounted reverse acting flow indicating controller FIC-820 flow controller. That operates the FV820A control valve with fall open action in the residue gas compression suction header, increasing flow opens FV-820A. The dry regeneration gas is supplied upstream of FV-820A and the wet regeneration gas is returned downstream. The control valve is throttled only to force the design regeneration flow through the regeneration gas system. To ensure the driest sieve closest to the cryogenic process, regeneration gas flows up through the bed of mol sieve. Flow rates are high enough to ensure thorough drying but low enough to prevent “lifting and fluidizing” the sieve. If this happens, the sieve beads begin to grind against each other, creating unwanted dust and fines, potentially reducing drying effectiveness and increasing pressure drop through the sieve bed. The heat input by the regeneration gas first heats the vessel internals and the mol sieve before any effective heat input begins to drive water vapor off the mol sieve. Since the mol sieve inlet gas drying cycle is 8 hours long, all regeneration activities (heating, cooling, bed pressurization/depressurization, valve switching sequence, etc) is concluded by the same cycle period. Heating the vessel, sieve, and driving the water vapor out typically consumes about 4 hours of the available time with cooling the system below 39°C consumes about 3 hours and the vessel pressurization taking the balance. During the cool cycle, the gas is cooled so water vapor condenses and drops out of the gas stream in the regeneration gas scrubber. In principle, the cooler the gas, the more water condenses and liberates from the gas stream but take care not to approach the point of hydrate formation for the gas stream. A “safe” minimum temperature (ambient temperatures permitting) is above 15.6°C. The mol sieve dehydration system is one of the more complex operations of gas processing, due to the nature of valve switching, to maintain a smooth, continuous operation. Therefore, all valve-switching between sieve beds, through and around the regeneration gas heater, pressurization and depressurization of the sieve beds, and gas bypass routing are performed by a timed control system.

Some breakage of the mol sieve material occurs during the initial loading and also during the operations of the timed cycles. This dust is removed by the Dust Filter which is located directly downstream of the dehydration units. This filter’s function is to prevent any dust or materials from passing downstream and possible plugging or fouling any of the heat exchangers.

2.4.3 Abnormal Operating Problems: 1) High moisture from dehydrator. 2) Dust-filter high differential pressure.

2.5 Regeneration Gas System:

2.5.1 Regeneration Gas Heater: The regeneration gas heater is a shell and tube heat exchanger. The 307°C hot oil from the hot oil heater flows through the tube side and heats the regeneration gas volume for the dehydrators to 232°C, flowing through the shell side. Design hot oil flow through the tube side is 5730 Kg/Hr. The hot oil from the shell side is designed for 200°C temperature. The only function of the heater is to heat the regeneration gas to 232°C during the regeneration heat cycle, it is bypassed during the cool and switch cycle. 2.5.2 Regeneration Gas Cooler: The regeneration gas cooler is an air conditioned heat exchanger designed to condense water and hydrocarbon vapor produced during the regeneration heat cycle. The cooler outlet maximum design temperature is 49°C and the minimum is limited to about 16°C to prevent hydrate problems. The cooler the gas, the more vapor is condensed. Two 4 KW motors drive two fans for control the outlet temperature.

2.5.3 Regeneration Gas Scrubber: The regeneration gas scrubber is designed to separate gas and liquid and send any accumulated liquid into the closed drain header automatically. The gas leaving the top of the vessel must pass through a wire mesh extractor to help remove entrained liquid.

2.6 Cryogenic Process Flow Description: 2.6.1 Inlet Gas Cooling: The dehydrated inlet feed gas from the dust filter at the design process conditions of 108,320 M3/Hr rate of flow, 29°C temperature, 102.1 Bar pressure, and 17.45 MW, splits for flow through two (2) exchangers to recover refrigeration. One inlet gas flow, 75% of the total inlet gas flow or 81,240 M 3/Hr, flows through the tube side of the HE-15.02 gas-gas exchanger. One inlet gas flow, 25% of the total inlet gas flow or 27,080 M3/Hr, flows through the tube side of the HE-15.03 de-ethanizer feed heater. The exchangers are designed to the following specifications: HE-15.02:   

Duty: 16,751 MKJ/HR Shell: 41.4 Bar MWP at 66°C/-110°C Tube: 113.7 Bar MWP at 66°C/-110°C

HE-15.03:   

Duty: 1,365 MKJ/HR Shell: 41.4 Bar MWP at 66°C/-110°C Tube: 113.8 Bar MWP at 66°C/-110°C

2.6.2 Cold Separator: The cold separator PV-16.03 is designed to separate the liquid, formed (condensed) by lowering the temperature of the inlet gas from 28.5°C to -28.5°C in HE-15.02 and 15.03, from the noncondensed inlet gas stream. The separator has an internal mist extractor pad and is the final clean up before the expanders. The inlet gas stream from the cold separator, 107,160 M3/Hr, 100 Bar-shutdown valves and 17.21 MW, flows through the three expanders or their JT bypass valve into the expander separator PV-16.04. The liquid from the cold separator,2.77 m3/Hr at 0.578 SPGR, also goes to PV-16.04.

2.6.3 Expander Separator: The expander separator PV-16.04 is designed to separate the NGL liquids from the now completely processed inlet gas. The gas from PV-16.04 is the majority (88%) of the plant residue gas. It is passed through a mist extractor pad as it leaves the top of the vessel to help recover all possible NGL. The separator has two inlet lines, both two phases (gas/liquid).One from the bottom of the cold separator PV-16.03 and one from the expander outlet. The NGL liquid from PV-16.04 is the total feed to the de-ethanizer, 21.1 M3/Hr at 0.394 SPGR. The expander separator makes the de-ethanizer fractionator more efficient since it does not have to handle the large volume of residue gas.

2.6.4 Residue Gas Handling: The residue gas stream from the top of the expander separator vessel is used to condense vapor for reflux in the top of the de-ethanizer, chill the inlet gas stream in the gas/gas exchanger and is then compressed by the expander compressors into the inlet to the residue gas recompressors where the pressure is increased to residue gas pipeline pressure.

2.6.5 De-Ethanizer: The purpose of the de-ethanizer is to separate by fractionation of the methane and ethane components contained in the feed stream from the propane and heavier components, the desired products. A small amount of the ethane component is left in the bottom product, since stripping all ethane overhead would reduce the propane component recovery. Along with the column top temperature, the amount of ethane left in the bottom product is the de-ethanizer bottom temperature control point.

2.6.6 De-ethanizer Reboiler: The de-ethanizer reboiler supplies the heat input to the bottom liquid to generate sufficient vapor to strip the lighter components from the NGL product in the column trays. The kettle type reboiler has hot oil flowing on temperature control through the tube bundle. The reboiler shell has a spill-over internal weir which insures that the tube bundle iscompletely submerged in liquid at all times. The weir forms a reservoir on the downstream side where the NGL is collected. The excess NGL liquid is pressured on level control through the NGL product air coolers into the NGL surge drums.

2.6.7 De-ethanizer Reflux Condenser: The HE-15.05 is an internal shell and tube exchanger installed in the top of the de-ethanizer. The cold -84.9°C residue gas from PV-16.04 flows through the shell side on temperature control. The de-ethanizer vapor from the top tray at -45°C flows through the tubes and are cooled to 58.11°C before leaving the column. A portion of the overhead gas is condensed and this liquid falls back onto the top tray to provide reflux liquid for the trays above the feed tray. Without reflux liquid the top trays will not separate components. 2.6.8 NGL Product Coolers: The NGL product cooler lowers the NGL product temperature from 129.7°C to 48.7°C. The maximum design NGL pipeline temperature is 50°C. A manual bypass around the product coolers is provided to maintain a minimum outlet temperature in the LP flash drum. This bypass is normally fully opened. There are two (2) 100% air cooled exchangers provided, each with three (3) fans driven by 1.6 KW electric motors. Double block and in between vent valves are provided on each unit for isolation. Each fan unit (6 total) has its own high vibration shutdown switch. When tripped only the fan unit with problem stops. The vibration switch must be reset manually to restart the fan. Each fan unit, when tripped, goes to VSHH alarm lights on the MIMIC panel as well as pilot lights locally. The NGL product coolers are designed to the following specifications: Duty: 1347 MKJ/HR MWP: 41.37 Bar at 160°C.

2.6.9 NGL Flash System: The equipment used in the NGL Flash System is designed for the temporary operation required at startup to produce an atmospheric NGL product for shipment through the NGL pipeline to a remote location. At startup the remote facility fractionation equipment will not be in operation therefore requiring an NGL product with an atmospheric vapor pressure. After the remote facility fractionation system is in operation the NGL Flash System will no longer be required and the plant can produce the normal NGL product as designed.

2.6.10 L.P. Flash Drum: The L.P. Flash Drum allows the NGL product recovered in the stabilizer and de-ethanizer to flash the light hydrocarbon due to the reduced operating pressure. The L.P. Flash Drum design operating pressure is .2 BARG at 47°C. Because of the low operating pressure an atmospheric NGL product is produced. This atmospheric NGL product can then be transferred by the NGL pipeline to another facility. The L.P. Flash Drum is designed to the following specification: Size: 1219 mm ID * 2438 mm S/S Design: 10 BARG at 100°C. 2.7.1 Product Booster Pumps: The Product Booster pumps are used to transfer NGL product from the NGL Surge Drum to the NGL pipelines. Because of the reduced NGL product due to producing an atmospheric NGL product, the booster pumps are required. The Product Booster Pumps are designed to the following specification: Capacity: 6.7 m3/HR at 3 Bar ΔP Type: Centrifugal pump

2.7.2 NGL Product Handling: The NGL surge drums operate as one and provide some surge (storage) capacity to continue to run the plant in case of product pipeline or pipeline pump problems. They also provide positive suction for the pumps. The NGL product from the de-ethanizer and the stabilizer bottom product join and flow into both NGL surge drums. Each drum has isolating block valves from maintenance. From the surge drums the NGL flows to the product pipeline pumps. The pipeline pumps deliver the NGL product to the North/South NGL pipeline through custody transfer meters and/or to NGL pipeline on pressure control.

A Simplified Flow Diagram of MSTE Plant:

Figure 2.1: A Simplified Diagram of MSTE Plant.

A Comparative Study of Supersonic Gas Separation

3.1 NGL/LPG Recovery And Fractionation: NGLs and LPGs, made up of C2, C3, C4 and C5+ hydrocarbons, are a valuable fraction of natural gas and associated gas streams and can be used both in Petrochemical Industry (mostly C2 and C3) or as fuel in civil and industrial applications (mostly LPGs). Recovery of NGL/LPG is normally achieved by means of cryogenic processing, with minimum temperatures that can be as low as -80 °C (NGLs) or -100 °C (high efficiency C2 recovery). Cryogenic processing requires proper gas dehydration, which for lower temperatures is normally achieved by means of mol. sieves. Several different processes are available, based on alternative cooling methods and with different plant arrangements: 







Joule Thomson (JT) Expansion: gas cooling is achieved by adiabatic gas expansion (in JT Valve) and by means of heat recovery. This method is normally applicable to high pressure gas streams. It allows a lower investment cost but it is characterized by lower recovery and by higher pressure losses. Direct Refrigeration by means of Chiller Unit (usually Propane): gas cooling is achieved by use of a propane Chiller Unit and by means of heat recovery. This method is applicable to medium or low pressure streams and it is normally used to treat medium pressure associated gas streams rich in LPGs Turbo-Expander: gas cooling is achieved by means of an isentropic gas expansion (inside the Turbo-Expander, which is normally an Expander/Compressor to recover the expansion energy) and by means of heat recovery. This method is applicable to a wider range of pressure and gas compositions. It is more efficient than JT Expansion and requires lower pressure losses but investment costs are higher High efficiency NGL recovery: normally based on the use of Turbo-Expander in conjunction with a refluxed De-Methanizer or De-Ethanizer Column to improve the recovery efficiency. The heat recovery arrangement is normally more complex. Due to pressure losses associated to gas expansion, the treated gas stream must normally be re-compressed to be delivered to transport pipeline. The recovered raw NGL/LPG fraction is normally fractionated to recover single components or mixtures with given composition (for examples a LPG with a given C3 to C4 ratio). This is normally achieved in a fractionation train composed of different distillation columns such the De-Ethanizer, De-Propanizer, De-Butanizer or the LPG Splitter. Recovered products are normally sent to dedicated storage while the heavy C5+ is normally sent to condensate stabilization.

3.2.1 An Overview On Turboexpander: Turboexpanders are rotating machines in which the process fluid (Natural Gas) does work against the turboexpander while moving from high pressure to a lower pressure and thus is cooled. Such a process approximates an ideal isentropic expansion. This process can be compared to the isenthalpic or Joule-Thomson expansion.

Isentropic expansion has a number of advantages. It will provide cooling at any temperature (unlike isenthalpic expansion, in which the fluid must be below an inversion temperature for cooling rather than heating to take place), and isentropic expansion generally provides a larger temperature drop than isenthalpic expansion for the same pressure change. However, unlike isenthalpic expansion, which occurs through a valve or orifice, isentropic expansion requires that work be done against an external source and therefore requires an expansion engine. Modern refrigerators and liquefiers typically contain anywhere between 2 and 10 expansion engines, depending on the capacity and cycle design of the cryoplant. In earlier cryoplants, the expansion engines were reciprocating or piston expanders. This style of expansion engine has now mostly been replaced by turboexpanders, which have a number of advantages, including lower maintenance requirements and higher reliability. Turboexpanders are also a key component of small Brayton cycle cryocoolers.

The use of turboexpanders in cryogenic plants has been the result of several technological advances. The development of sophisticated computational fluid dynamic models coupled with computer aided design and manufacturing has allowed the design and construction of efficient turboexpanders operating at cryogenic temperatures. The development of reliable rotating bearing systems that function at high speeds and cryogenic temperatures has also been necessary for the successful use of turboexpanders. Bearing choices for turboexpanders include oil bearings (used only at room temperature), magnetic bearings and gas bearings. Oil bearings for turboexpanders, while still used in air separation, LNG plants and some hydrogen plants, are becoming less common due to the need to maintain a separate oil skid and the due to the risk of oil contamination into the process stream. Helium plants commonly, though not exclusively, are using gas bearings for turboexpanders. Gas bearings can be divided into two types, static and dynamic. In static gas bearings, the bearing gas is provided by an independent helium system and is available regardless of the speed of the turboexpander. In dynamic gas bearings, the bearing gas is taken

from the process stream itself. In this approach, supplemental bearings may be required during plant startup. The work produced by the gas expanding through the turboexpander is available at room temperature. This work may be absorbed as heat into a cooling loop. In some plants, such as the cryoplants at the European Spallation Source, this heat is then recovered for use elsewhere. In some large cryoplants, the turboexpanders may be on the same shaft as compressors elsewhere in the cycle. The work produced by the gas expanding through the turboexpanders in this case then helps drive the compressors. 3.2.2 TurboExpander In MSTE Plant: The design was that from the cold separator the inlet gas, at design conditions of 107,106 M3/HR, 100 Bar, -28.02°C and 17.21 MW, would flow through three identical expanders and into the expander separator. The expanders are simply highly efficient turbines operating on the same principle as the steam turbine but their prime objective is to reduce the temperature than obtaining power. 3.2.3 Operational Error: Though it was designed to liquefy the natural gas and separate the higher hydrocarbon from Methane and Ethane the plant could not run on turboexpanders. The plant had to be shutdown within 6 days. At present it runs bypass valve which is JT valve.

3.3.1 The Joule-Thomson (JT) effect: The Joule-Thomson (JT) effect is a thermodynamic process that occurs when a fluid expands from high pressure to low pressure at constant enthalpy (an isenthalpic process). Such a process can be approximated in the real world by expanding a fluid from high pressure to low pressure across a valve. Under the right conditions, this can cause cooling of the fluid. This effect was first observed in an experiment conducted by James Joule and Thomson in 1852 in which they flowed high pressure air through a small porous plug causing the pressure to drop. Joule and Thomson noted that the air was cooled by this procedure (which is a good approximation of an isenthalpic process).

Building on this work, in 1895, Linde in Germany and Hampson in England independently developed and patented a refrigerator that combined the JT effect with heat exchangers and a piston compressor. This became known as the Linde-Hampson or Joule–Thomson cycle. Such a refrigerator played an important role in James Dewar’s liquefaction of hydrogen in 1898. The Joule-Thomson effect can be described by means of the Joule-Thomson coefficient which is simply the partial derivative of the pressure with respect to temperature at constant enthalpy. If this coefficient is positive, then the fluid cools upon expansion and if it’s negative the fluid warms upon expansion. The JT coefficient varies as a function of pressure and temperature and varies from fluid to fluid. The curve described by the JT coefficient equaling zero as a function of pressure and temperature is known as the inversion curve. Underneath this curve cooling of the fluid occurs upon expansion. It is also possible to define for a given fluid the maximum inversion temperature. The fluid must be colder than this temperature to cool when expanded.

3.3.2 Definitions of Symbols Used to Describe the Joule-Thomson Effect: The table below provides an overview of the relevant nomenclature:

Symbol

Quantity

SI Unit

h

Specific enthalpy

J/Kg

Cp

Heat capacity

J/(Kg.K)

T

Temperature

K

p

Pressure

Pa

s

Specific entropy

J/(Kg.K)

Symbol

Quantity

SI Unit

v

Specific volume

M3/Kg

ρ

Density

Kg/ M3

μJT

Joule-Thomson coefficient

K/Pa

Figure 3.1 : Schematic of throttling through a Porous Plug.

Let us consider, a gas flow that expands through a porous, permeable plug from a higher to lower pressure state, with thermally insulated walls.

This is an adiabatic throttling process. No heat or mechanical work is exchanged with the environment. Fundamental thermodynamic definitions can be used to develop an energy balance for the flow process into and out of the porous section, with 1 representing the inlet and 2 representing the outlet:

h1+U12/2 = h2+U22/2 where h is the enthalpy and U is the velocity (m/s). Here, any magnetic, electric, and nuclear energy contributions are neglected. For gas flows at moderate velocities, it is safe to disregard the kinetic energy change in comparison to any enthalpy changes:

h1 = h2 Therefore, it is evident that the process happens at constant enthalpy – in other words, it is isenthalpic.

3.3.3 The Joule-Thomson co-efficient : When a real gas, as differentiated from an ideal gas, expands at constant enthalpy (i.e., no heat is transfered to or from the gas, and no external work is extracted), the gas will be either cooled or heated by the expansion. That change in gas temperature with the change in pressure is called the Joule-Thomson coefficient and is denoted by µ, defined as: µ = (dT/dP) at constant enthalpy The value of u depends on the specific gas, as well as the temperature and pressure of the gas before expansion. For all real gases, µ will equal zero at some point called the "inversion point". If the gas temperature is below its inversion point temperature, µ is positive ... and if the gas temperature is above its inversion point temperature, µ is negative. Also, dP is always negative when a gas expands. Thus: If the gas temperature is below its inversion temperature: -- µ is positive and dP is always negative -- hence, the gas cools since dT must be negative If the gas temperature is above its inversion temperature: -- µ is negative and dP is always negative -- hence, the gas heats since dT must be positive

"Perry's Chemical Engineers' Handbook" provides tabulations of µ versus temperature and pressure for a number of gases, as do many other reference books. For most gases at atmospheric pressure, the inversion temperature is fairly high (above room temperature), and so most gases at those temperature and pressure conditions are cooled by isenthalpic expansion. Helium and hydrogen are two gases whose Joule-Thomson inversion temperatures at atmospheric pressure are very low (e.g., about -222 °C for helium). Thus, helium and hydrogen will warm when expanded at constant enthalpy at atmospheric pressure and typical room temperatures. It should be noted that µ is always equal to zero for ideal gases (i.e., they will neither heat nor cool upon being expanded at constant enthalpy).

3.3.4 Inversion Temperature: The inversion temperature in thermodynamics and cryogenics is the critical temperature below which a non-ideal gas (all gases in reality) that is expanding at constant enthalpy will experience a temperature decrease, and above which will experience a temperature increase. This temperature change is known as the Joule-Thomson effect, and is exploited in the liquefaction of gases.

Figure 3.2: A plot showing the throttling path in a temperature-pressure diagram. The isenthalps are indicated by h = constant. The path of a throttling process goes from a point “w” and moves left along an isenthalp, passing through x, as well as possibly y and z. Depending on the start pressure and temperature and the final pressure, the temperature can either increase or decrease for a specific gas. The limiting line where a temperature increase changes to a decrease is called the inversion line.

3.4.1 Supersonic Gas Separation: Supersonic gas separation is a technology to remove one or several gaseous components out of a mixed gas (typically raw natural gas). The process condensates the target components by cooling the gas through expansion in a Laval nozzle and then separates the condensates from the dried gas through an integrated cyclonic gas/liquid separator. The separator is only using a part of the field pressure as energy and has technical and commercial advantages when compared to commonly used conventional technologies.

3-S separators provide a cost-effective and highly efficient extraction process for C3+ gas components combined with a potential reduction in energy consumption.

3.4.2 Laval Nozzle: Existing approaches to obtaining low temperatures are based on the Joule-Thomson effect and use of gas-expansion equipment. The gas processing industry developed and has used them extensively. Recent research has produced new technologies based on adiabatic cooling, which results from gas expansion in a supersonic nozzle. Cryogenic temperatures result because part of gas enthalpy transforms to kinetic energy, which can be reused to increase the pressure in the system of supersonic and subsonic diffusers. The nozzle’s working section liquefies target components. It experiences significantly lower pressures and temperatures than would occur at the facility exit without the addition of external energy.

Figure 3.3: the degree of natural gas cooling at the same differential pressure for a JouleThomson valve, turboexpander, and the new device that uses a Laval nozzle.

3.4.3 Supersonic Separation Technologies: The supersonic nozzle separates drops of condensed liquid using centrifugal forces, which are formed by two different methods. The swirling (twisting) device can be at the outlet of the supersonic nozzle or the gas flow is swirled in the plenum chamber ahead of the supersonic nozzle.

3.4.4 3S Separator Flow Scheme: The diagram below shows a facility with 3-S separator and the chiller to extract C3+ from natural gas. In this facility, natural gas is supplied to the 3-S separator after cooling in the recuperative heat exchanger and evaporator. Gas from the 3-S separator flows to the recuperative heat exchanger, which cools the feed gas. Two-phase flow from the 3-S separator flows to the secondary separator, the gas phase of which mixes with purified flow from the 3-S separator.

Figure 3.4: 3-S separator Flow Scheme.

3.4.5 3-S Technology Studies: The separation efficiency in the 3-S separator slightly decreases with an increase of heavy components. This is due to the characteristics of thermodynamic expansion of mixtures with high concentrations of heavy components; for these types of mixtures, the appearance of liquid in the separator premix chamber is normal. For certain conditions, especially with small concentrations of heavier hydrocarbons, the 3-S separator can separate liquid components that a Joule-Thomson valve could not.

3.4.6 Comparison among Existing Technologies: At the same differential pressure, the 3-S separator can achieve considerably lower temperatures in the liquid separation section due to adiabatic cooling during expansion in the supersonic nozzle and the Joule-Thomson effect.

Figure 3.5: Comparison between different technologies.

The above figure assumes that the isentropic turbine efficiency is 80% and the isentropic turboexpander compressor efficiency is 75%. Pressure losses, temperature approaches, and pressure losses in the recuperative heat exchanger are the same for all schemes. The 3-S separator results in a higher extraction of C3+ vs. the Joule-Thomson valve and turboexpander. The 3-S separator is simpler to design, operate and maintain.

3.4.7 Advantages in Field Plants: Gas processing plants with the 3-S separator have: • Fewer compressor station power requirements. • Lower pressure loss. • Greater recovery given the same operating parameters. • A simpler plant design. • Fewer moving parts. • Ease of construction and reduction in plant weight. • Lower equipment, operating, and maintenance costs.

3.4.8 Conclusions: Calculations based on experimental data for particular fields show that using the 3-S technology results in a 30% increase in the recovery of heavier gas components for the same power requirements. For the same extraction level, the power requirement could be reduced 50-70%. Using 3-S separators instead of Joule-Thomson valves in existing gas processing and extraction plants increases LPG extraction 10-20% with the same compressor power. For the same extraction level, it is possible to decrease the required compressor power by 10-20%. At gas processing plants equipped with turboexpanders and coolers, using 3-S extractors could lead to a 15-20% reduction in the required compressor power at the same extraction level.

So, From the above study it can easily be concluded that the use of a Supersonic Technology will be more energy saving as well as more effective in separating NGL from natural gas with comparison to TurboExpander and Joule Thompson Technology.

References: 1. 2. 3. 4. 5. 6. 7. 8. 9.

The Process Description Book provided by MSTE Plant. https://www.siirtecnigi.com/design-ngl-lpg-recovery. http://naturalgas.org/naturalgas/processing-ng/ Handbook of Natural Gas Transmission and Processing By Saeid Mokhatab, William A. Poe https://sgfl.org.bd/MSTE Plant.htm https://www.cryogenicsociety.org/resources/defining_cryogenics/turboexpanders/ https://www.cryogenicsociety.org/resources/defining_cryogenics/joulethomson_effect/ https://en.wikipedia.org/wiki/Inversion_temperature https://www.ogj.com/