Uran plant, ONGC
Mumbai A CASE STUDY ON
“A brief study of process and equipments at ONGC Uran Plant”
Submitted at Oil and Natural Gas Corporation Limited Uran, Raigad, Maharashtra
Submitted by
Mechanical Engineering Final Year GLOBAL INSTITUTE OF TECHNOLOGY
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Introduction: Oil and Natural Gas Corporation is a public sector petroleum company involved in widescale exploitation of oil as well as natural gas from the Indian mainland as well as from Arabian Sea and Indian Ocean. ONGC is one among the Indian Government’s Navarathna Companies which involves the most profit making nine public sector companies and hence is one of the most profit making companies in India.
Foundation: In August 1956, the Oil and Natural Gas commission was formed. Raised from mere directorate status to commission, it had enhanced powers. In 1959, these powers were further enhanced by converting the commission into a statutory body by an act of Indian Parliament. Oil and Natural Gas Corporation Limited (ONGC) (incorporated on June 23, 1993) is an Indian Public Sector Petroleum Company. It is a fortune global 500 companies ranked 335th, and contributes 51% of India’s crude oil production and 67% of India’s natural gas production in India. It was set up as a commission on August 14, 1956. Indian government holds 74.14 % equity stake in this company. ONGC is one of Asia’s largest and most active companies involved in exploration and production of oil .It is involved in exploring for and exploiting hydrocarbons in 26 sedimentary basins of India. It produces 30% of India’s crude oil requirement. It owns and operates more than 11,000 kilometers of pipelines in India. In 2010, it was ranked 18th in the Platts Top 250 Global Energy Company Rankings and is ranked 413st in the 2012 Fortune Global 500 list. It is the largest company in terms of market cap in India.
ONGC Represents India’s Energy Security ONGC has single-handedly scripted India’s hydrocarbon saga by:
Establishing 7.38 billion tonnes of In-place hydrocarbon reserves with more than 300 discoveries of oil and gas; in fact, 6 out of the 7 producing basins have been discovered by ONGC: out of these In-place hydrocarbons in domestic acreages, Ultimate Reserves are 2.60 Billion Metric tonnes (BMT) of Oil Plus Oil Equivalent Gas (O+OEG).
Cumulatively produced 851 Million Metric Tonnes (MMT) of crude and 532 Billion Cubic Meters (BCM) of Natural Gas, from 111 fields.
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ONGC has bagged 121 of the 235 Blocks (more than 50%) awarded in the 8 rounds of bidding, under the New Exploration Licensing Policy (NELP) of the Indian Government.
ONGC’s wholly-owned subsidiary ONGC Videsh Ltd. (OVL) is the biggest Indian multinational, with 33 Oil & Gas projects (9 of them producing) in 15 countries, i.e. Vietnam, Sudan, South Sudan, Russia, Iraq, Iran, Myanmar, Libya, Cuba, Colombia, Nigeria, Brazil, Syria, Venezuela and Kazakhstan.
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ONGC as Processing Industry: Any process industry can be solely divided into 4 parts: 1. 2. 3. 4.
Process plant Utilities Environmental system Safety system
1. Process Plant: This part consist the basic purpose of that process industry for which it has been established. ONGC Uran plant basically produces LPG and other value added products and pumps the stabilized oil to different refineries. In sum to get this purpose there is overall two plant: a) Co-generation Plant b) Oil and Gas process Plant
Co-generation plant can be also sub divided into mainly 3 different process units: Gas Turbine Boilers(heat recovery steam generation) Gas fired boilers
Oil and gas process plant can be sub divided into 6 different processing units:
Slug catcher unit Condensate fractionation unit Gas sweetening unit Crude separation unit LPG recovery unit Ethane propane recovery unit
2. Utilities: Utilities plays very important role in any process industry. They provide support to process plant for the smooth running and continuous production as in our case. The basic utilities which are very necessary in our case are: Effluent treatment Instrument air Air dryer Flare system GIT-12
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Blow down system Soft water system Fuel gas Inert gas system
3. Environment System: This system monitors the effect of plant on environment by continuous monitoring inside and outside surrounding of plant and always tries to maintain a minimum national standard of different environmental parameters. If this minimum standard is not achieved by the plant then government has to shut that industry as per environmental law. It can be also categorized in two parts: Primary environmental system: It is directly related to the health precaution and keeps on check on severe affect on environment like the surrounding temperature, H2S gas concentration in the atmosphere, suspended particles and carbon concentration etc. as these changes affect the people and works health working or living in the surrounding of the planet. Secondary environmental system: This system is not related to health but works for the sake of environmental protection and welfare. Plantation, nitrogen’s oxide removal system comes under this system category.
4. Safety system: This system maintains the safe working condition in this plant is very much prone to fire as the air in the surrounding contains lots of hydrocarbon and oil vapours. So any small spark can produce large scale destruction. This system consist of Firewater unit Gas detection unit Static charge removal unit
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Uran plant, ONGC
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Introduction to Uran plant: Uran onshore facilities of ONGC is located at longitudinal 720 55’35” and latitude 180 51’40” (N) approximately 15 M above mean sea level. The site is about 12 km east of Mumbai. Western Side of the site faces sea and the east side is surrounded by hills. The site is not on a level land and processing areas are located at different elevations. Site is approachable by allweather motor able roads. The Uran Plant is one of the most important installations not only of the entire ONGC, but also of the entire nation. It was established in the year 1974 and expanded in stages. It receives the entire oil and part of natural gas produced in Mumbai offshore oil fields. Both the oil and gas received from offshore is processed at various units for producing value added products like LPG, C2-C3, LAN, apart from processing, storage and transportation of oil. It has been also awarded as the best processing plant in India. It is situated at the outskirts of Mumbai city, and has an excellent location with mountains on one side and the sea on the other side. The huge pipelines from the offshore come directly in the Uran plant. The Uran plant has an area of 5.5sq.km.
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Layout diagram of Uran plant:
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SAFETY MANAGEMENT IN URAN PLANT, URAN Uran plant accepts safe accident-free and pollution-free environment in & around all our location at all times and instilling of safety awareness in our employees. To ensure safety of the locations, risk analysis and safety audits are carried out. Uran plant has safety committee with participation from senior officers and workers and meetings are conducted regularly.
A. INBUILT SAFETY Facilities at LPG/CSU plant, ONGC Uran are designed and constructed with three level of Inbuilt Safety. 1. Pre-alarms : - To alert 2. Trip-alarms : - In case no action is taken on (1) above the system is tripped automatically. 3. Safety Valves : - In case of failures even at (2) Safety valves release the content in the closed system. Safety Valves are tested & calibrated once in a year while realarm are tested once in four months and two months respectively.
B. SAFETY SYSTEM The plant has dedicated safety system with the following salient features. 1. Gas detectors :Possible gas leakage point has been identified and provided with gas detectors (250 Nos.) along with facilities of audio-visual alarm in the control room. 2. Fire Alarm :Elaborate fire communicating system spread all over the plant with 147 fire alarms which give indication of fire & its location to control room & fire station for quickest response. 3. Smoke detectors/UV detectors :These have been provided with turbines, computer room, control rooms, cable vaults etc. for detecting fire in these places. 4. MOVs & ROVs :Motor operated vales & Remote operated valves have been provided at critical locations with facility for remote operation from control rooms. This shall facilitate prompt & remote closure of valves in case of emergency. 5. Water Sprinklers :Elaborate water sprinklers and drancher systems have been provided for all critical storage and vulnerable area. All the Crude tanks have been provided with dedicated foam pourer system. GIT-12
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C. RISK ANALYSIS A comprehensive Risk Analysis study of Uran On-shore facilities was done by M/s EIL in 1997. The job involved hazard and operability study (HAZOP), HAZAN, Quantitative Risk Analysis (QRA), Evacuation, Escape and Rescue Analysis (EER). The following facilities at Uran Complex were included in the scope of work. GAS PROCESSING I. II. III. IV. V. VI. VII. VIII.
Pig receivers & launchers, valve pits. Slug catchers & condensate handling units. Gas sweetening units (GSU). Condensate Fractionation Unit (CFU). LPG recovery plants. Ethane-Propane (C2-C3) recovery units (EPRU). Flare and blow-down system. Storage and handling of NGL, LPG & C2-C3.
OIL PROCESSING I. II. III. IV. V. VI.
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Crude Oil inlet lines, valve pits, pig receiver & launcher. Crude Stabilization unit (CSU). Surge tank and internal pumping system. Bulk crude storage and pumping system. Effluent handling system. CSU off-gas compressors.
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CRUDE STABILISATION UNIT INTRODUCTION: The Crude Stabilization Unit at Uran, Mumbai is designed to stabilize pressurized crude oil from the Mumbai off-shore oil fields. It is designed to produce 20,000,000 tons of stock tank crude oil per annum. Besides stabilization, the unit includes provision for dehydration and desalting crude oil whenever required.
CRUDE OIL FROM OFF SHORE
CRUDE CRUDE HEATER HEATE R
CRUDE EXCHANGER
HIGH PRESSURE SEPERATOR
CRUDE HEATER
TO ETP OFF GAS 3RD STAGE OF COMPRESSOR
2ND STAGE OF COMPRESSOR
1ST STAGE OF COMPRESSOR
DE-GASER
OFF GAS TO GSU DE-HYDRATOR
TO ETP
STABILIZED OIL TO TROMBAY
MAIN STORAGE TANK
SURGE TANK
CRUDE COOLER
TO TO ETP
PRODUCED WATER CRUDE OIL GIT-12
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ETP
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SOURCE: The crude oil received from offshore platform is in the unstabilized form. This crude oil reaches the Uran Plant through 3 oil trunk lines. The 30" MUT oil pipeline from Mumbai High and 24" HUT oil pipeline from satellite offshore platform are the principal feed stock to plant. In addition, provision is kept to process the slug catcher liquid and reprocessing oil from tank area and recovered oil from the existing facilities at Uran. Provision is also kept to process the low aromatic naphtha (LAN) in the LPG recovery units, Condensate Fractionate Units and liquid condensate from associated gas compressors.
PROCESS DESCRIPTION: There are five identical trains each consisting of high pressure separator (HP), Dehydrator, pre-heater and low pressure separator. Each train has a processing capacity of 5 MMTPA. The Pressurized crude oil received from BUT and HUT oil trunk lines into five streams and preheated by steam upto 45C before entering into High Pressure Separator V201/A/B/C/D/V-601/613 operating at pressure of 3.5 kg/cm^2g.The oil flows out under level control and can either be directly sent to low pressure separator or can be pumped to the Dehydrator system. High pressure gas leaves the HP separators under pressure control and is sent for compression. Before entering the Dehydrators oil is preheated first by heat exchange with dehydrated oil and then in the crude heaters upto 65C. The Dehydrators remove water and salt from oil. The dehydration is accomplished by the injection of demulsified, heating or by the application of high voltage electro-static field in the oil-water emulsion. The dehydrated oil flows under level control, exchange heat with feed to dehydrator and is then sent to low Pressure Separators. The water produced by dehydration is sent to EPTP (Effluent Pre-Treatment Plant) for predisposal treatment. The stabilized oil is pumped to five Main Storage Tanks T-202A/B/C/D/E, T-601/A/B/C/D. The gases from the HP separators, Degassers and LP separators are compressed in the Multi Service Gas Compressors and sent to LPG unit combining with associated gas from the trunk line. These are done by 3 stages reciprocating Compressors, operating at suction pressures of 0.05 kg/cm^2g and 14.0 kg/cm^2g. The Degassers are connected to compressors 1 and HP separator gases are connected to 2 stage suction. GIT-12
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COMPONENTS: FEED SUPPLY : The offshore crude oil is received at Uran through 3 oil trunk lines - 30" BUT oil pipeline (presently isolated). - 30" MUT oil pipeline. - 24" HUT oil pipeline. MUT oil pipelines are provided with three turbine flow meters and one bypass with strainers up streams of interconnection. At CSU end the MUT oil feed line is provided with two out of three turbine type flow meters in parallel and the HUT oil feed line is provided one out of two turbines types flow meters which measures and integrates flow to the CSU unit. Two strainers in MUT as well as in HUT oil line have been upstream of flow meters.
HP SEPARATORS: The feed to each High Pressures Separator (HP Separator) is taken from the existing 24" header through a 16" line with isolation motor operated valve MOV-201/202/203/101/1101, one shut down valve SDV - 201/202/203/101/1101 and one hand control valve HCV 201/202/203/101/1101. The feed is heated to 40C before entering the HP separator, in crude Pre-heater using MP steam. The HP Separator are three phase horizontal separation vessels, capable of separation oil, free water and gas, having a hold up time of 3 minutes with 50% filling. They are 12.2m long and has an outer diameter of 2.74m designed for pressure of 5.5 kg/cm^2g and a temperature of 55C. Each HP Separator is provided with two relief valves, one operating and other on standby. The gas from the separator flows on pressure control, through PCV-1010/1020/1030/101/1101 to the compressors. The produced water flows on interface level control through ILCV1101/1020/1030/101/1101.The flow of oil from HP Separator is indicated by flow indicators FI1101/1021/1031/102 /1102.
LP SEPARATORS:
The stabilized crude oil from the LP Separator flows by gravity into the Intermediate Surge tanks. These are come roof atmospheric storage tanks of 24m diameter and 12.6m height having a nominal capacity of 5000m^3 each. Heating coils are provided in these tanks, with MP steam as the heating medium. The tanks are provided with one low level alarm and one high level alarm. The separated gas is continuously vented to safe location through flame arrestor. GIT-12
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INTERMEDIATE TRANSFER PUMPS : These intermediate Transfer Pumps two operating and one standby, of capacity 750 m^3/hr and 54m differential head are provided to transfer stabilized crude oil from intermediate surge tanks to storage tanks. These pumps are provided with emergency power in order to continue crude stabilizing plant operations even on main power failure. Pumps are provided with motor operated isolation valves at the suction and discharge.
MAIN STORAGE:
Eight main storage tanks each of nominal capacity of 60000m^3 are provided for crude oil buffer storage. These are floating roof tanks of 79m diameter and 15.6m height. Each tank except T-601A is provided with mixers in order to prevent settling of sludge. The tanks are provided with one each level indicators and temperature indicators in control room. They are also provided with one low level alarm and high level alarms. The tanks are provided with motor operating isolation valves in the inlet and main outlet lines.
BOOSTER PUMPS AND TRANSFER PUMPS:
Two parallel pumping trains (OBPH, NBPH) are providing for pumping requirement of oil. Old booster pump house pumping train consisting of P-203 A/B/C/D/E/F, take suction from the main storage tanks and deliver into the 26" crude oil main transfer line. These pumps are of capacity 750m^3/hr and 54m differential head each. The pumps are provided with motor operated isolation valves at the suction and discharge. Three crude oil transfer pumps P - 204 A/B/C are connected to above 26" crude oil main transfer line, series arrangement. In order to take care of increased pumping requirement a new parallel pumping train, consisting of four Booster Pumps P - 603 A/B/C/D and four transfer pumps P - 604 A/B/C/D has been added. The crude oil booster pumps take suction outlet from line branching from existing 36" main storage tank outlet header and deliver into the new 26" crude oil main transfer line. The pumps are of capacity 500m^3/ hr and 87m differential head each. The pumps are provided with motor operated isolation valves at the suction and discharge.
CRUDE OIL DISPATCH:
Stabilized crude oil is dispatched from the plant to various refineries in India through tankers from Jawahar Deep (Butcher Island) and BPCL, HPCL refineries at Trombay through pipeline. In addition to above, facilities are also created for loading and oil through tankers at JNPT.
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GAS SWEETENING UNIT (G.S.U) Sweetening of a gas refers to the removal of hydrogen sulphide from the gas. The Gas Sweetening Plant focuses on the removal of Acid gases, hydrogen sulphide (H2S) and carbon di oxide (C02) from the feed gas. The feed gas consists of slug catcher Gas, CFU offgas and SU offgas. The process employed for the separation of the gases is Sulfinol R-D process. For the sweetening of the sour gas, there are two identical trains. Each of the trains are designed for a mixed sour gas feed of 5 MMNCM/ day and hence a total capacity of 10 MMNCM/ day. The two trains are operating with a third train used as a standby. Usually only 50% of the designed capacity is used.
LAY OUT DIAGRAM:
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The main two stages in the process are: 1: Inside the absorber column C-1201 the acidic components and the sulphur compounds present are absorbed from the feed gas at the feed gas pressure level. 2: The Sulfinol solution is regenerated by stripping to remove the absorbed gases from the solvent in the Regenerated column C-2102 at low pressure and elevated temperature. - Initially the sour gas is sent to the sour gas knock out drum V-1202 where the contained liquids are separated and sent to condensate Fractionation Units. Then the gas is fed into the absorber column where CO2 and H2S are removed by counter current with lean sulfinol solution to meet the product specification. The sweet gas from the absorber is sent to sweet gas header via sweet gas knockout drum. The rich solution from the absorber bottom is flashed into the flash scrubber where it is scrubbed with the lean solution. The rich solution from this is sent to regenerator column. The rich solution is regenerated by reboiled vapours generated the attached boiler. The acid gas which is separated is released into sulphur recovery plant or directly into the atmosphere.
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ETHANE PROPANE RECOVERY UNIT (EPRU): Ethane and Propane recovery are among the phase-III process in the ONGC Uran Plant, Uran, and Bombay. C2-C3 Recovery Unit (EPRU) is supplied with two feed streams from the LPG-I & II Units. These are the high pressure Second Stage Vapour (SSV) and low pressure feed from the Light Ends Fractionators (LEF). These streams are partially cooled to condense them. The refrigeration is provided by passing the high pressure feed streams through an expander and by a propane refrigeration system. The partially condensed feed streams are fed to the Demethaniser to separate the methane vapours from C2-C3 liquid. The overhead gas from the Demethaniser is fed to a second expander to provide cooling to the reflux condenser. The lean gas is then warmed to ambient temperature by the lean gas Compressors. Refrigeration gas is provided to LPG I & II as an inter-stage product. The C2-C3 is pumped to Area 16 for storage as pressurized liquid.
The Ethane Propane Recovery unit can be divided into several subsections: - SSV Pre-Compression. - SSV Chill-down. - SSV Expansion. - De-methanization. - Lean Gas Compression. - Propane Refrigeration.
SSV COMPRESSION:
The feed gas is taken to feed gas compressor suction knock-out drum. The gas from knockout drum is taken to the compressor of the demethanizer overhead expander compressor. The compressed gas is directly taken to the suction of the compressor of the feed gas expander compressor. The compressed gas at 52.5 kg/cm^2g is cooled to 40C & taken to chill down suction for further chilling.
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SSV CHILLDOWN:
The compressed feed gas is then cooled through the heat exchangers from 40C to shunt 25C. Further feed gas is taken to Demethanizer bottom reboiler where it cooled down to 2.5C. Then feed gas is taken to Chiller-I & Chiller-II for further chilling when it receives cold by propane refrigeration & chilled down from 2.5C to- 17C to- 27C to -55C. Then it is fed to separator-I to separate out condensate. The vapour from separator-I is taken to Chiller-III where it is chilled further to -67C by exchanger of heat with outgoing cold lean gas. The partially condensed feed gas at -670C is taken to separator-II to separate out the condensate. The condensate from separator-I & separator-II is directly fed to Demethanizer column at tray No.16. The vapour from separator-II at -67C is taken to feed gas expander for expansion. The LEF vapour received as feed to EPRU is available at 35C is taken to LEF Vapour/ lean gas exchanger where it is cooled down to 5C. Then it is further chilled down to -7C & -20C at Chiller-I and Chiller-II respectively by use of propane refrigeration. Then it is taken to Demethanizer side reboiler & chilled down to about -33C. Further it is taken to Chiller-III & chilled down to -37C & directly taken to Demethanizer column as feed at tray No.27.
SSV EXPANSION:
Feed gas, after 2nd stage separation at -67C from separator -II is taken to feed gas expander compressor for expansion. The majority of the refrigeration need is made available from this entropic expansion of gas from about 49.6 kg/cm^2g, the gas is further chilled down to about -100C and is taken directly to Demethanizer column at tray No.10 for fractionation.
DEMETHANIZER: The function of the Demethanizer column is to recover C2-C3 product from the condensed liquids at various stages in chill down and expansion sections and remove all undesirable methane from it. Feed to the column is taken as follows:- Feed gas expander outlet (vapour liquid) at tray No.10 at about -100C. - Mixture of separator-I & separator-II liquid at tray No.16 at about -67C. - Partially condensate LEF vapour at tray No.25 or tray No.27 at about -37C. - Of-spec C2-C3 product, if any, storage at tray No.40. The vapour from Demethanizer reflux drum is taken to Demethanizer overhead expander compressor, where it is expanded to about 14 kg/cm^2g. Due to this expansion, gas is further GIT-12
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chilled down to about -111C. This cold methane rich vapour is utilized for refrigeration then it is taken to lean gas compressor.
SSV FEED
PRE COMPRESSION OF FEED THROUGH EXPANDER DRIVEN COMPRESSORS
1ST STAGE VAPOURS TO 2ND STAGE CHILL DOWN
LEF O/H VAPOURS LEF ON VAPOURS
1ST STAGE VAPOURS LIQUID SEPARATI ON
1ST STAGE CHILL DOWN
1ST STAGE VAPOUR LIQUID SEPARATION
LEAN GAS ND
2 STAGE VAPOURS LIQUID SEPARATI ON
DEMETHAISER COLUMN
C2C3 PRODUCT
CHILL DOWN BY PROPANE REFRIDGERATION
FEED TO DEMETHANIS ER COLUMN
LEAN GAS COMPRESSION: After the recovery of Ethane and Propane, the lean gas is received in the lean gas compressor knock-out drum at about 20C & 12.7 kg/cm^2g. Then lean gas is compressed to about 40 kg/cm^2g by lean gas compressor. The compressor gas after cooling to about 40C is supplied at battery limit for gas consumers.
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PROPANE REFRIGERATION SYSTEM: To supplement the refrigeration requirement, EPRU is provided with Propane Refrigeration System. The feed gas is chilled down upto -67C with the help of propane refrigeration system followed by further heat exchange. BASIC PRINCIPLES: There are two basic principles for LPG recovery from natural gas. They are 1. REFRIGERATION 2. FRACTIONATION REFRIGERATION: 1. By using the relation between temperature and pressure a refrigeration system is designed. 2. A refrigerant is a fluid which picks up heat from process system, by boiling at low temperature and pressure which is done by compressor. In LPG plant propane is used as refrigeration and it picks up heat from feed gas. FRACTIONATION: Fractionation is a unit operation in which a multi-component liquid mixture is separated into individual components with condensate purity. It is a continuous process of vaporization and condensation and there by separation of pure individual components is achieved. Relatively more vaporization takes place for lighter component and more condensation takes place for heavier component. A continuous heat input is given through reboiler at the bottom to accomplish stripping of the feed. An external reflux is given form the top of the column through the reflux drum to cool and wash the top vapours so that the pure components with maximum recovery can be achieved.
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Turbo-Expander of Uran Turbo-expander is a centrifugal turbine through which a high pressure gas is expanded to produce work that is often used to drive a compressor. Turbo-expanders are widely used in cryogenic and energy recovery applications. These machines operate under extreme conditions of high speed, high pressures and very low temperatures. But at the same time, due to the above reasons, problems encountered in these machines are very unique in nature. Gas in
Gas out
Expander Shaft
Expander Wheel
Compressor Gas Out
Compressor Wheel
Gas In
PROCESS FLOW DIAGRAM FEED GAS
EXPANDER DRIVEN COMPRESSOR CONSUMER
FEED GAS COOLER E-1501
CHILLING SECTION
LEAN GAS
DEMETHANIZER COLUMN
EXPANDER
LIQUID ETHANEPROPANE TO STORAGE PIPES GIT-12
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CONDENSATE FRACTIONATING UNIT (CFU-1): The CFU has been designed and constructed for the stripping pf acid components, H2S and CO2, from the condensate mainly supplied from slug catcher (Phase II and Phase III) and IHI & HP compressors; in addition, the condensate is intermittently supplied from K.O. drum installed in Gas Sweetening Unit (GSU). CFU is composed of the following sections: - Feed condensate treatment section. - Condensate stripping section. - Off gas compressor section. - Flare section.
PROCESS: The condensate from the slug catcher, CSU, LPG and GSU act as the feed to the Condensation Fractionation Unit. The feed enters the feed coalescer (X-1101) operating at 4852 kg/cm^2g where water is removed and the condensate is fed to the stripper column (C1101). The Stripper column operates at 23-25 kg/cm^2g and here the H2S and CO2 gases are removed. This stripped vapour goes to the knock out drum (K.O.D V-1101). The heat requirement to the stripper column is given by the stripper bottom re boiler (E-1101). The stripper bottom liquid is supplied to the re boiler via stripper bottom pump and filter (X1102). The vapour generated in the re boiler is returned to the stripped for stripping and the stripping liquid in the re boiler is sent to the stripper bottom re boiler surge drum. The stripped liquid can be sent as a reflux to stripper Column or sent to CFU-II or LPG column. The stripped vapour containing H2S and CO2 is sent to the reciprocating type gas compressor where the gas pressure is built up to available sour gas U/S pressure. The compressed gas goes to the cooler and then to the off-gas compressor discharge K.O.D and from the gas is sent to GSU.
DESCRIPTION: - FEED SUPPLY: The feed to the condensate Fractionating Unit (CFU-II) is the condensate at 63 t/h which is obtained as follows: - 30.5 t/h slug catcher condensate corresponding to 8-9 MMNM3/ day pipeline gas. GIT-12
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- 16.0 t/h compressor 3rd stage condensate for 20 MMTPA crude processing (with HSVR modification.) The slug catcher condensate is pumped from the surge drum located near the slug catcher by transfer pumps through filter and a flow control valve. Any free water present in the condensate will separate out in the drum and collect in the water boot. The condensate under level cascaded with flow control will be pumped to CFU-II by CSU second stage condensate transfer pumps. The pump is provided to give sufficient head to avoid any hydrocarbon flashing in the feed coalesce. In case the condensate is received at a pressure greater than 50 kg/ cm^2g an no flashing is reported, provision has kept to bypass the transfer pumps and take the condensate directly to feed coalescer. -H2S STRIPPER: Feed to the H2S stripper is a mixture of liquid and vapour. The column has 60 valve trays. The top section has single pass trays (5 trays) and the bottom has double pass trays (55 trays). A dry tray and a demister has been provided at column top to remove any liquid entrained along with the vapour. The Stripper bottom liquid is pumped through bottom filter pumps to re boiler through filters. The heat supply to the re boiler is from the MP Steam. provision has been kept to divert the bottom product from the re boiler to the LPG columns of LPG-I and LPG-II in case LPG column of CFU-II is shut down. -LPG COLUMN: The bottom liquid from both the CFU-I and CFU-II stripper is taken to LPG column on the 21st tray, provision is also there to put the feed on the 16th tray. This column has 50 valve trays and is designed to separate LPG (propane and butane) from heavier components. The column operates at a pressure of 10 kg/cm^2. The pressure is maintained by a hot vapour bypass type control scheme. The column bottom temperature is maintained at 153.5C and the column top is maintained at 70C using medium pressure steam. LPG is taken as overhead liquid product through LPG reflux and transfer pumps. -CONDENSATE OFF-GAS COMPRESSION: The stripper overhead vapour is taken to off gas compressor suction K.O. drum. The surge drum flashed vapour if any is also combined with this stream before it enters the suction K.O. drum. Two reciprocating compressors are provided to compress this sour gas to enable it to flow to the gas sweetening units. The compressed gas is cooled to 45C in discharge cooler which uses cooling water on shell side. The cooled gas flows to gas sweetening unit via compressor discharge K.O. Drum. The condensate formed flows under level control to stripper column. GIT-12
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CO-GENERATION (COGEN) INTRODUCTION: Cogeneration means simultaneous generation both electrical and thermal energy by raising a single primary heat source, thereby increasing the overall efficiency of the plant. Cogeneration is one of the most powerful and effective energy conservation techniques. In industries like refineries, petrochemical, fertilizer, sugar etc, there is a requirement of both power and steam. LPG/CSU plant at Uran needs power and steam. To meet this requirement a cogeneration plant was setup. Hence this plant fulfills the requirement of both electrical power and steam at a very low cost and high efficiency and reliability. Cogeneration is of two types namely Copping up cycle Bottom up cycle Copping cycle is one of in which heat requirement is attained by externally firing the fuel. Whereas in bottom up cycle the heat requirement is fulfilled by internal chemical reactions this cycle is used in medicine production. Cogeneration plant at ONGC Uran is based on copping up cycle. The principle of this plant is mentioned below: PRINCIPLE: Air from atmosphere is taken through an air filter and compressed in axial flow compressor driven by the turbine. The compressor air enters into combustion chamber where it is mixed with fuel (lean gas). During combustion its temperature increases at constant pressure (process B to C) then it expands mechanical energy by rotating the turbine. A major part of this energy is available for the generator. Hence the thermal efficiency of the generator is very low. Diesel engine is used for initial cranking of the system. Once the turbine attains the speed the contact is broken. However only 30% of the compressed air is used for combustion and energy conversion and the rest of the air is used for cooling and sealing of the net bas path (Turbine blades nozzles etc). The efficiency of the turbine can be increased if the metallurgical part of the nozzle and blades are improved so that the size of the compressor can be reduced for the same turbine.
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Layout Diagram of the C0-Generation Plant
Fuel
Combustion Chamber
Gear box
Hot Gas
Power
Starting Diesel Engine
19.6 MW Compressor [17 STAGES] [AXIAL FLOW] Air Filter Air filter unit
Turbine
Fuel
By pass
Duct Burner
Supplementary Firing Fuel [9 MW]
Alternator 3000 RPM
Steam HRSG Heat recovery steam generator
Air [40 ˚ C]
Exhaust flue gases from the turbine has got sufficient heat energy (512˚C at full load), is passed through a vertical water tube boiler duct converting heat energy into useful steam. These boilers are known as HRSG (Heat recovery steam generator). This steam is used for LPG/CUS process plant. The amount of steam which is generated in this condition requires Zero or very small fuel input (if supplementary firing is dine to increase the steam production), so the overall efficiency of the plant is increased.
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Power capacity of the gas turbine (GT): Power- 3*19.6 MW GE frame- 5 gas turbines
Steam capacity of the waste heat recovery boilers (HRSG): Steam- 2*75+1*90 TON/HR Waste heat recovery boilers
Plant demand for power and steam: Power average
-
41.0 MW/HR
Power (peak)
-
50.0 MW/HR
Steam
-
150 TON/HR
Export (with 3 GTS) Import (with 3 GTS)
-
5.0 MW/HR -
NIL
This power and steam demand is easily met by the Co-generation plant as the power turbines produce 3*19.6 MW= 58.8 MW. The steam produced by the HRSG is 2*75+1*90 TON/HR = 240 TON/HR But sometimes one of the gas turbine may not be operational as mechanical failure may occur, fuel gas line may leak, seizure of the compressor of the turbine etc. The Cogeneration plant is always connected to the power grid MSEB in the case of failure of one of the turbines. Thus undisturbed power supply continues.
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EFFLUENT TREATMENT PLANT: (MINAS) EFFLUENT FROM TANK FARM
EFFLUENT FROM CSU
EFFLUENT FROM OTHER SOURCES
POLYELECTROLYTE DOSING UNIT
EFFLUENT PRETREATMENT (EPTP)
SURGE POND
CPI SEPERATOR
BIO-TOWER I
CLARIFIER
BIO-TOWER II
SAND FILTER
CLARIFIER II
GUARD POND
DISPOSAL PUMP
Discharge to sea through closed conduit disposal system
RECYCLE PUMPS
LAYOUT OF MINAS PLANT
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Effluent received from CSU is routed back to EPTP, where oil & water are separated using gravity separation. Oil is sent back to CSU & water is further routed to surge pond where it gets mixed with effluents of other plants like LPG, GSU, and EPRU. This effluent is sent to ETP (MINAS) Plant for further treatment before final discharge into sea through close conduit disposal system. The process description of ETP (MINAS) having a capacity of 350 M3 /Hrs (dry weather) and 700 M3 /Hrs (wet weather) is as given below.
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Pre-weather treatment by gravity separation using corrugated plate interceptors (CPI) to reduce gross separable oil contamination. Primary treatment by sand filtration with in line polyelectrolyte addition to remove suspended solids and flocculated oil. Secondary treatment using biological filtration with random packed plastic media as the substrate for the biomass. Di-ammonium phosphate addition in upstream of Biotowers. Secondary treatment is meant for removing soluble pollutants (BOD). Tertiary treatment is provided in the form of conventional gravity clarifications to remove any humus sludge from Bio-tower effluent. Polishing of treated effluent by means of sub surface aerators in the guard pond. Disposal by pumping through closed conduit disposal system to low tide level into the sea.
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SLUG CATCHER Bombay high gas is transported from offshore platforms to Uran Terminal via 26” subsea lines about 210 km length BUT lines and the length of 26” gas pipelines from Satellite field to offshore be about 91 km (HUT line). The operational flexibility of diverting Bombay High gas to Heera is provided through ICP-Heera Trunk Line and also through SHS-Heera Trunk line. A total combined (BUT & HUT) 16.5 MMSCM/D of gas handling facilities has been created at Uran Terminal in the Slug-Catcher Unit of which 11.3 MMSCM/D gas processing capacities has been created at GSU. LPG and ethane-propane recovery units to extract value added products like LPG/LAN/C2-C3 and the remaining rich gas will be sent through plant bypass loop to consumer, GAIL for extracting value added products at their LPG recovery plant USAR and to the fertilizer unit of RCF and power sectors. There are two Slug Catchers provided in two phases (Phase-II and Phase-III), to handle sweet gas coming from BH field and sour gas from Satellite fields to knock out the condensate from the incoming gas before gas processing and diverting the gas consumers. Slug catcher facilities are to serve the following objectives: To separate the continuously coming condensate from the saturated gas by reducing of the fluid velocity and subsequent gravity separation. To hold the slug fluid coming at Uran at the time of pigging of gas pipe lines. To continuously send the hydrocarbon liquid to CFU-1 /2 units for further processing. To partially stabilize the liquid from phase 2 sweet liquid condensate and inject into crude inlet to CSU in case of CFU-1/2 are down. To supply gas (after condensate separation) to GSU-12/13 plants. The formation of condensate is due to pressure reduction from 90 kg/cm² to 50 kg/cm². The retrograde condensation taking place and accumulation of liquid at the low points of sea-bed. Capacity of slug catcher Phase 2: o Design capacity o Volume o Sea bed temp
: : :
8 mm nm³/day 3100 m³(this hold up is for 2 days) 20ºC minimum
: :
5mm nm³/day 450 m³(this holds up for 2 days)
Phase-3: o Design capacity o Volume GIT-12
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Process Description: Gas from offshore coming to Uran terminal by 26” submarine gas pipeline shall enter the expanded slug catcher. In case of balanced gas supply from offshore to consumer, the offshore gas straightaway enters the slug catcher but if there is an excess of gas from offshore compared to consumption, the offshore gas enters the slug catcher through a pressure control valve to maintain normal operating pressure at GSU Inlet. In such cases excess gas, if desired =, can be routed to Hazira from the offshore itself. From slug catcher the separated gas takes its normal route to GSU. The liquid slug catcher sump flows into a slug liquid drum where gas & liquid can take two routes. Either it can be pumped via filters to CFU – I/II or LPG II liquid driers for further processing in CFU I/II or it can be partially stabilized in slug liquid stabilizer after heating in Slug Heater. The flashed gases go to flare while partially stabilized condensate is routed to CSU – I/II. This route becomes necessary when either CFU I or II or both units are down and are not in position to accept condensate and during pigging operation of gas trunk lines.
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LPG-1 LPG recovery unit: Two units of 5.65 MMSCMD capacities each receives the sweet gas from GSU. The combined capacities of LPG units are as follows:Sweet gas throughput: 11.3 MMSCMD LPG production: 3, 17,000 MTPA LAN production: 1, 87,000 MTPA
LPG-1 Capacity: Design: Feed-sweet gas: 5.65 MMSCMD Product LPG: 1, 58.500 MTPA LAN: 93,500 MTPA In case of GSU and EPRU Shutdown LPG plant can directly run on sour gas(the gas from slug catcher). Product components of natural gas: Methane Ethane
No. of carbon atoms 1 2
Propane
3
Butane Pentane
4 5
Hexane+-
6
Lean gas to consumers C2-c3 to IPCL for further processing LPG at 8kg/cm2 to BPCL & HPCL Naphtha to IOTL for further dispatch To petrochemical plants
Basic principles: LPG recover from natural Gas is made on the two principles: GIT-12
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Fractionation
Refrigeration: By using the relation between temperature and a pressure a refrigeration system designed. A refrigerant is a fluid which picks up heat from process system, by boiling at low temp and pressure and gives up heat by condensing at a high temperature and pressure which is done by compressor. In LPG plant propane is used as Refrigerant and it picks up the heat from feed gas. Fractionation: Fractionation is a unit operation in which a multi-component liquid mixture is separated into individual components with considerable purity. It is a continuous process of vaporization and condensation and there by separation of a pure individual component is achieved. Relatively more vaporization takes place for lighter component and more condensation takes place for heavier component. A continuous heat input is given through re-boiler at the bottom to accomplish stripping of the feed. An external reflux is given from the top of the column through the reflux drum to cool and, wash the top vapors, so that a pure component with maximum recovery can be achieved. There are 3 columns used in LPG-1 plant.
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LEF & LPG columns: Separated liquid from V-103 & V-104 passed through E-103, E-101, and E-118 and sent to LEF column at around 20oC to remove the lighter fractions which mainly contain C2C3. The gas coming out from the top of the column goes to reflex drum V-105 after getting cooled in E-105. Liquid is knocked out from V-105 and remaining gas called LEF Top is sent to C2-C3 recovery unit. The bottom liquid goes to LPG column. If C2-C3 recovery unit is under shut down LEF top can be sent to consumer line after compressing through residue gas compressor K-102A/B. The liquid from LEF column enters either 9th or 12th or 15th tray of LPG column. The top product of column is propane and butane (called LPG or Liquefied petroleum Gas) and the bottom product is called Naphtha (LAN-Light Aromatic Naphtha). Propane column: The propane is used as a refrigerant in the refrigeration system. The propane losses which occur during refrigeration of feed gas require make-up. Therefore a propane column is designed in LPG plant to recover propane taking the LPG as a feed to the column. It consists of 37 trays and LPG as feed enters 25th tray. Propane product is withdrawn from 5th tray as side out product to remove the lighter impurities. 33 | P a g e
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RUSTON GAS TURBINE (RGT) Gas based LPG Extraction Plant is based on cryogenic process. The purpose of cooling of feed gas accomplished by heat exchange with refrigerant, liquid propane. The liquid propane, in turn, vaporizes after gaining heat in the exchange process. A centrifugal compressor compresses this propane vapour for liquefaction to complete the refrigeration cycle. The drive to propane compressor Ebara is a Gas Turbine, supplied by Ruston, U.K. the turbine is coupled to the compressor by a compressor by a gear box at its power turbine end.
LPG-2 Process Description: Sweetened gas from GSU flows to knock out drum where any liquid present is separated out, and then the gas is pre cooled to 250oC. The pre cooled gas is sent to knockout drum where Liquefied hydrocarbon and water are separated out. The gas then flows to the molecular sieve drier where the moisture is reduced to less than 4 ppm level. The dried gas is cooled to -220 degree C in the first stage chiller; condensed liquid is separated out. Vapor is further cooled to -370 degree C and condensed liquid is again separated out. Remaining non-condensate gas called SSV is sent to C2-C3 plant. Cooling of gas is achieved by exchanging heat against external refrigeration. External refrigeration is supplied in three stages at -70˚ C, -270˚ C & -400˚ C. The SSV (second stage vapor) after separation of liquid condensate are delivered as feed stock to C22-C3 recovery unit, alternatively the SSV can be delivered to consumer trunk line if C2-C3 unit is under shut down. A propane column is provided in LPG-I to recover liquid propane from LPG streams. Propane is used as refrigerant for LPG-I & II, C2 C3 plant to maintain desired operating temperatures. Propane column will be in service intermittently as per requirement to make up refrigerant losses. For external refrigeration propane compressor K-501 is driven by electric motor with constant speed.
For the operation point of view, the entire plant may be divided into following subsection: o o o o o o o o GIT-12
Feed gas supply/ pre-cooling Feed gas drying Feed gas chill down Light ends fractionate column(LEF) LPG column Refrigeration system Fuel gas system Flare and blow down system 34 | P a g e
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o Methanol system
Start – up procedure: The various steps leading to a safe and smooth start-up of LPG unit are as follows: o o o o o o o o o
Purging the unit Refrigeration of molecular sieve Drying of the unit Commissioning of Methanol system Charging and establishing refrigeration cycle Establishing flow through chill down section Commissioning of light ends fractionators Commissioning of LPG column Stabilizing the unit
DRYERS
FILTERS
REFRIGERATION UNIT
SSV TO EPRU
LEF O/HTO EPRU CONDENSATE FROM CFU-I LPG PRODUCT NGL/NAPTHA
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SEPERATORS
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Propane Recovery Unit: FUEL GAS
LPG
Propane column
PROPANE TO STORAGE
To LPG Storage Propane is produced from LPG in LPG-1 plant. Propane column (10C-103) takes LPG feed from the discharge of LPG reflux pump of LPG-1 plant/ LPG-2 plant. The column operates at about 15 kg/cm2 top-pressure and about 85 degree Celsius bottom and 40˚C top temperature. Its top product is propane and bottom which is butane goes to LPG spheres. This is a small column and intended to meet the internal requirement of propane, which is used as refrigerant in LPG and C2-C3 plants.
Flare System: In case of process upset gas is flared through two numbers of elevated flares for lighter hydrocarbon and one box flare for heavier hydrocarbon, which are kept alive with the help of purge gas for safety. If needed, low temperature liquids are diverted to blow down drums, where it is converted into gas with help of low-pressure steam and then diverted to the flare header. Condensate formed, if any, is collected in flare knockout drum and pumped back to process unit.
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Study of Compressor: A gas compressor is a mechanical device that increases the pressure of a gas by reducing its volume. Compressors are similar to pumps: both increase the pressure on a fluid and both can transport the fluid through a pipe. As gases are compressible, the compressor also reduces the volume of a gas. Liquids are relatively incompressible; while some can be compressed, the main action of a pump is to pressurize and transport liquids. o Types of compressor
Fig: Different types of compressors
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Centrifugal compressor Centrifugal compressors, sometimes termed radial compressors, are a sub-class of dynamic axisymmetric work-absorbing turbo machinery.
Fig: Inner look of centrifugal compressor The idealized compressive dynamic turbo-machine achieves a pressure rise by adding kinetic energy/velocity to a continuous flow of fluid through the rotor or impeller. This kinetic energy is then converted to an increase in potential energy/static pressure by slowing the flow through a diffuser. Imagine a simple case where flow passes through a straight pipe to enter centrifugal compressor. The simple flow is straight, uniform and has no swirl. As the flow continues to pass into and through the centrifugal impeller, the impeller forces the flow to spin faster and faster. According to a form of Euler's fluid dynamics equation, known as "pump and turbine equation," the energy input to the fluid is proportional to the flow's local spinning velocity multiplied by the local impeller tangential velocity. In many cases the flow leaving centrifugal impeller is near or above 1000 ft./s or approximately 300 m/s. It is at this point, in the simple case according to Bernoulli's principle, where the flow passes into the stationary diffuser for the purpose of converting this velocity energy into pressure energy. Components of centrifugal compressor A simple centrifugal compressor has four components: GIT-12
Inlet Impeller/rotor Diffuser Collector 38 | P a g e
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Inlet: The inlet to a centrifugal compressor is typically a simple pipe. It may include features such as a valve, stationary vanes/airfoils (used to help swirl the flow) and both pressure and temperature instrumentation. All of these additional devices have important uses in the control of the centrifugal compressor.
Centrifugal impeller: The key component that makes a compressor centrifugal is the centrifugal impeller; it is the impeller's rotating set of vanes (or blades) that gradually raises the energy of the working gas. This is identical to an axial compressor with the exception that the gases can reach higher velocities and energy levels through the impeller's increasing radius. In many modern high-efficiency centrifugal compressors the gas exiting the impeller is traveling near the speed of sound. Impellers are designed in many configurations including "open" (visible blades), "covered or shrouded", "with splitters" (every other inducer removed) and "w/o splitters" (all full blades).
Fig: centrifugal Impeller
Diffuser: The next key component to the simple centrifugal compressor is the diffuser. Downstream of the impeller in the flow path, it is the diffuser's responsibility to convert the kinetic energy (high velocity) of the gas into pressure by gradually slowing (diffusing) the gas velocity. Diffusers can be vaneless, vaned or an alternating combination.
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. Fig: Diffuser
High efficiency vaned diffusers are also designed over a wide range of solidities from less than 1 to over 4. Hybrid versions of vaned diffusers include: wedge, channel, and pipe diffusers. There are turbocharger applications that benefit by incorporating no diffuser. Bernoulli's fluid dynamic principal plays an important role in understanding diffuser performance.
Collector: The collector of a centrifugal compressor can take many shapes and forms. When the diffuser discharges into a large empty chamber, the collector may be termed a Plenum. When the diffuser discharges into a device that looks somewhat like a snail shell, bull's horn or a French horn, the collector is likely to be termed a volute or scroll.
As the name implies, a collector’s purpose is to gather the flow from the diffuser discharge annulus and deliver this flow to a downstream pipe. Either the collector or GIT-12
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the pipe may also contain valves and instrumentation to control the compressor. For example, a turbocharger blow-off valve. Working Centrifugal compressors use the rotating action of an impeller wheel to exert centrifugal force on refrigerant inside a round chamber (volute). Refrigerant is sucked into the impeller wheel through a large circular intake and flows between the impeller. The impellers force the refrigerant outward, exerting centrifugal force on the refrigerant. The Refrigerant is pressurized as it is forced against the sides of the volute. Centrifugal compressors are well suited to compressing large volumes of refrigerant to relatively low pressures. The compressive force generated by an impeller wheel is small, so chillers that use centrifugal compressors usually employ more than one impeller wheel, arranged in series. Centrifugal compressors are desirable for their simple design and few moving parts. Applications
In gas turbines and auxiliary power units. In their simple form, modern gas turbines operate on the Brayton cycle. Either or both axial and centrifugal compressors are used to provide compression. The types of gas turbines that most often include centrifugal compressors include turbo shaft, turboprop, auxiliary power units, and micro-turbines. The industry standards applied to all of the centrifugal compressors used in aircraft applications are set by the FAA and the military to maximize both safety and durability under severe conditions.
In automotive engine and diesel engine turbochargers and superchargers. Centrifugal compressors used in conjunction with reciprocating internal combustion engines are known as turbochargers if driven by the engine’s exhaust gas and turbo-superchargers if mechanically driven by the engine. Standards set by the industry for turbochargers may have been established by SAE. Ideal gas properties often work well for the design, test and analysis of turbocharger centrifugal compressor performance.
In pipeline compressors of natural gas to move the gas from the production site to the consumer. Centrifugal compressors for such uses may be one- or multi-stage and driven by large gas turbines. Standards set by the industry (ANSI/API, ASME) result in large thick casings to maximize safety. The impellers are often if not always of the covered style which makes them look much like pump impellers. This type of compressor is also
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often termed an API-style. The power needed to drive these compressors is most often in the thousands of horsepower (HP). Use of real gas properties is needed to properly design, test and analyze the performance of natural gas pipeline centrifugal compressors.
In oil refineries, natural gas processing, petrochemical and chemical plants. Centrifugal compressors for such uses are often one-shaft multi-stage and driven by large steam or gas turbines. Their casings are often termed horizontally split or barrel. Standards set by the industry (ANSI/API, ASME) for these compressors result in large thick casings to maximize safety. The impellers are often if not always of the covered style which makes them look much like pump impellers. This type of compressor is also often termed API-style. The power needed to drive these compressors is most often in the thousands of HP. Use of real gas properties is needed to properly design, test and analyze their performance.
Air-conditioning and refrigeration and HVAC: Centrifugal compressors quite often supply the compression in water chillers cycles. Because of the wide variety of vapor compression cycles (thermodynamic cycle, thermodynamics) and the wide variety of workings gases (refrigerants), centrifugal compressors are used in a wide range of sizes and configurations. Use of real gas properties is needed to properly design, test and analyze the performance of these machines. Standards set by the industry for these compressors include ASHRAE, ASME & API.
Reciprocating compressor A reciprocating compressor or piston compressor is a positive-displacement compressor that uses pistons driven by a crankshaft to deliver gases at high pressure. The intake gas enters the suction manifold, then flows into the compression cylinder where it gets compressed by a piston driven in a reciprocating motion via a crankshaft, and is then discharged. Applications include oil refineries, gas pipelines, chemical plants, natural gas processing plants and refrigeration plants. One specialty application is the blowing of plastic bottles made of Polyethylene Terephthalate (PET).
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Fig: Reciprocating compressor function
Fig: A motor-driven six-cylinder reciprocating compressor that can operate with two, four or six cylinders.
Applications:
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Reciprocating compressors utilize crankshaft driven pistons to compress gases for use in various processes. Much like internal combustion engines, an offset crankshaft causes rotary motion of a piston rod which is converted to linear motion via a crosshead. The crosshead can only move in a linear motion so that the rotary motion of the crankshaft is transformed into linear motion of the piston. As the piston moves to and fro, it takes in low pressure gas and increases its pressure. Unlike an internal combustion engine, the gas is not ignited. It is allowed to leave the compressor cylinder at a higher level of pressure than when it went in. The majority of applications for reciprocating compressors are in the oil and gas industries. Oil refineries use these compressors for processes that require high pressure delivery of essential gases. The natural gas industry also utilizes reciprocating compressors to transport gas via cross country pipelines. These compressors can also be found in chemical plants, refrigeration plants, air compressors for tooling, etc. 43 | P a g e
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Reciprocating compressors are unique pieces of equipment as they contain active components that are moving in rotary as well as linear directions. They also play a vital role in any process that they are employed in. Therefore, a reciprocating compressor’s health must be monitored, but in order to do so, you must do more than follow the usual vibration monitoring rules.
Axial Compressor: Axial compressors are rotating, airfoil-based compressors in which the working fluid principally flows parallel to the axis of rotation. This is in contrast with other rotating compressors such as centrifugal, axis-centrifugal and mixed-flow compressors where the air may enter axially but will have a significant radial component on exit. Axial flow compressors produce a continuous flow of compressed gas, and have the benefits of high efficiencies and large mass flow capacity, particularly in relation to their cross-section. They do, however, require several rows of airfoils to achieve large pressure rises making them complex and expensive relative to other designs (e.g. centrifugal compressor). Axial compressors are widely used in gas turbines, such as jet engines, high speed ship engines, and small scale power stations. They are also used in industrial applications such as large volume air separation plants, blast furnace air, fluid catalytic cracking air, and propane dehydrogenation. Axial compressors, known as superchargers, have also been used to boost the power of automotive reciprocating engines by compressing the intake air, though these are very rare.
Fig: Axial flow compressor
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Working: A compressor in which the fluid enters and leaves in the axial direction is called axial flow compressor. So, the centrifugal component in the energy equation does not come into play. Here the compression is fully based on diffusing action of the passages. The main parts include a stationary (stator) part and a moving (rotor) part. The diffusing action in stator converts absolute kinetic head of the fluid into rise in pressure. The relative kinetic head in the energy equation is a term that exists only because of the rotation of the rotor. The rotor reduces the relative kinetic head of the fluid and adds it to the absolute kinetic head of the fluid i.e., the impact of the rotor on the fluid particles increases its velocity (absolute) and thereby reduces the relative velocity between the fluid and the rotor. In short, the rotor increases the absolute velocity of the fluid and the stator converts this into pressure rise. Designing the rotor passage with a diffusing capability can produce a pressure rise in addition to its normal functioning. This produces greater pressure rise per stage which constitutes a stator and a rotor together. This is the reaction principle in turbo-machines. If 50% of the pressure rise in a stage is obtained at the rotor section, it is said to have a 50% reaction.
Rotary screw compressor: A rotary screw compressor is a type of gas compressor which uses a rotary type positive displacement mechanism. They are commonly used to replace piston compressors where large volumes of high pressure air are needed, either for large industrial applications or to operate high-power air tools such as jackhammers. The gas compression process of a rotary screw is a continuous sweeping motion, so there is very little pulsation or surging of flow, as occurs with piston compressors.
Operation: Rotary screw compressors use two meshing helical screws, known as rotors, to compress the gas. In a dry running rotary screw compressor, timing gears ensure that the male and female rotors maintain precise alignment. In an oil-flooded rotary screw compressor, lubricating oil bridges the space between the rotors, both providing a hydraulic seal and transferring mechanical energy between the driving and driven rotor. Gas enters at the suction side and moves through the threads as the screws rotate. The meshing rotors force the gas through the compressor, and the gas exits at the end of the screws.
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Fig: Rotary screw compressor
The effectiveness of this mechanism is dependent on precisely fitting clearances between the helical rotors, and between the rotors and the chamber for sealing of the compression cavities.
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Gas turbine A gas turbine, also called a combustion turbine, is a type of internal combustion engine. It has an upstream rotating compressor coupled to a downstream turbine, and a combustion chamber in-between. Energy is added to the gas stream in the combustor, where fuel is mixed with air and ignited. In the high pressure environment of the combustor, combustion of the fuel increases the temperature. The products of the combustion are forced into the turbine section. There, the high velocity and volume of the gas flow is directed through a nozzle over the turbine's blades, spinning the turbine which powers the compressor and, for some turbines, drives their mechanical output. The energy given up to the turbine comes from the reduction in the temperature and pressure of the exhaust gas. Energy can be extracted in the form of shaft power, compressed air or thrust or any combination of these and used to power aircraft, trains, ships, generators, or even tanks.
Fig: A typical axial-flow gas turbine turbojet
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Operation: Gases passing through an ideal gas turbine have three thermodynamic processes. These are isentropic compression, isobaric (constant pressure) combustion and isentropic expansion. Together these make up the Brayton cycle. In a practical gas turbine, gases are first accelerated in either a centrifugal or axial compressor. These gases are then slowed using a diverging nozzle known as a diffuser; these processes increase the pressure and temperature of the flow. In an ideal system this is isentropic. However, in practice energy is lost to heat, due to friction and turbulence.
Fig: Brayton Cycle
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Gases then pass from the diffuser to a combustion chamber, or similar device, where heat is added. In an ideal system this occurs at constant pressure (isobaric heat addition). As there is no change in pressure the specific of the gases increases. In practical situations this process is usually accompanied by a slight loss in pressure, due to friction. Finally, this larger volume of gases is expanded and accelerated by nozzle guide vanes before energy is extracted by a turbine. In an ideal system these are gases expanded isentropically and leave the turbine at their original pressure. In practice this process is not isentropic as energy is once again lost to friction and turbulence.
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INTRODUCTION TO HEAT EXCHANGER: Heat exchanger is equipment, which effects the transfer of heat from one fluid to another. Types of heat exchanger: • • • •
Based on heat transfer process Based on service Based on construction Based on Flow Arrangements Types based on Heat Transfer Process
• – –
Direct Contact Type Fluids are not separated. Example is Cooling Tower
• – – –
Indirect Contact Type Fluid Streams separated by an impervious wall Examples are Tubular Exchangers, Plate Heat Exchangers Types of Exchangers Based on Service
Heater: • It is a unit that exchanges heat between two process streams without phase change; i.e. liquids are neither evaporated nor condensed. Cooler: •
Cools the process fluids without phase change.
Condenser: • •
Condenses process vapour stream. Examples: Some of the Fin fan Cooler
Re-boiler: • Provides latent heat of vaporization to bottom of distillation / fractionation column. Pre-heater:
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•
Mumbai
Uses steam or hot process stream to heat & or vaporize the feed to processing unit.
Types of Exchangers Based on Construction: Tubular heat exchanger: – – – – –
U tube type heat exchanger Fixed tube sheet heat exchanger Floating head type heat exchanger Pipe in pipe heat exchanger Fin fan type exchanger
Plate type heat exchanger Spiral plate type heat exchanger Types of Exchangers Based on Flow Arrangements
• – – – • – – • – •
Co-current flow Both Fluid Streams flow in same direction High Thermal Stresses at inlet as large variation in inlet temp. of two streams Least effective Counter-current flow Fluids flow in opposite directions True counter current flow not easily achievable Cross Flow Fluids flow normal to each other Shell and Tube Heat Exchangers
Fig: Shell and Tube Heat Exchanger GIT-12
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Functions of S&T exchangers • • • •
Heating ( gas or liquid) Cooling without condensing ( gas or liquid) Condensing of vapors ( partial condensing OR full condensing) Evaporating liquid (partial or full)
Basic Components of S&T Exchangers – – –
Tubes
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Tube sheets Holds the tubes in place Tubes expanded or welded on the tube-sheets
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Tube Side Nozzles & Channel Controls the flow of the tube side fluid Normally of same material as that of tube & tube-sheet or are cladded.
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Channel Covers Round plates bolted to the Channels and can be removed for tube side inspection
– – – –
Shell & Shell Side Nozzles Shell is a container for shell side fluid Shell side nozzles are inlet and outlet for shell side fluid. Shell is normally circular in cross section. Shell is made by rolling of plates or of pipes (upto 24 inch dia)
Provides the heat transfer area Bare Tubes or Finned Tubes Seamless or welded
Impingement plate – Provided at shell inlet nozzle to avoid impact of fluid on the top row of the tubes Basic Components of S&T Exchangers – GIT-12
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Baffles – Provide support to the tubes during assembly and operation and prevent vibration of the tubes. – Guide the shell side fluid flow resulting in increased turbulence and heat transfer coefficient – For liquid flows baffle cut is approx 20 to 25% of shell dia – For gaseous flow baffle cut is 40 to 45% of shell dia Refrigerant, compressor, expansion valve (flow control device), evaporator, condenser, pipes and tubes.
COMPRESSION REFRIGERATION SYSTEM
Schematic of Compression Refrigeration System GIT-12
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EXPLANATION OF HOW IT WORKS/ IS USED:
Refrigerant flows through the compressor, which raises the pressure of the refrigerant. Next the refrigerant flows through the condenser, where it condenses from vapor form to liquid form, giving off heat in the process. The heat given off is what makes the condenser "hot to the touch." After the condenser, the refrigerant goes through the expansion valve, where it experiences a pressure drop. Finally, the refrigerant goes to the evaporator. The refrigerant draws heat from the evaporator which causes the refrigerant to vaporize. The evaporator draws heat from the region that is to be cooled. The vaporized refrigerant goes back to the compressor to restart the cycle. COMPONENT: Compressor: Of the reciprocating, rotary, and centrifugal compressors, the most popular among domestic or smaller power commercial refrigeration is the reciprocating. The reciprocating compressor is similar to an automobile engine. A piston is driven by a motor to "suck in" and compress the refrigerant in a cylinder. As the piston moves down into the cylinder (increasing the volume of the cylinder), it "sucks" the refrigerant from the evaporator. The intake valve closes when the refrigerant pressure inside the cylinder reaches that of the pressure in the evaporator. When the piston hits the point of maximum downard displacement, it compresses the refrigerant on the upstroke. The refrigerant is pushed through the exhaust valve into the condenser. Both the intake and exhaust valves are designed so that the flow of the refrigerant only travels in one direction through the system.
Diagram of Compressor (Belt Driven In This Instance)
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Detail of Compressor Valve Function
Components of Compression Refrigeration In A Dorm Refrigerator
Condenser: The condenser removes heat given off during the liquefaction of vaporized refrigerant. Heat is given off as the temperature drops to condensation temperature. Then, more heat (specifically the latent heat of condensation) is released as the refrigerant liquefies. There are air-cooled and water-cooled condensers, named for their condensing medium. The more popular is the air-cooled condenser. The condensers consist of tubes with external fins. The refrigerant is forced through the condenser. In order to remove as much heat as possible, the tubes are arranged to maximize surface area. Fans are often used to increase air flow by forcing air over the surfaces, thus increasing the condenser capability to give off heat.
Evaporator:
This is the part of the refrigeration system that is doing the actual cooling. Because its function is to absorb heat into the refrigeration system (from where you don't want it), the evaporator is placed in the area to be cooled. The refrigerant is let into and measured by a flow control device, GIT-12
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and eventually released to the compressor. The evaporator consists of finned tubes, which absorbs heat from the air blown through a coil by a fan. Fins and tubes are made of metals with high thermal conductivity to maximize heat transfer. The refrigerant vaporizes from the heat it absorbs heat in the evaporator.
Flow control device (expansion valve):
This controls the flow of the liquid refrigerant into the evaporator. Control devices usually are thermostatic, meaning that they are responsive to the temperature of the refrigerant.
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