traning report on ongc

7/29/2019 traning report on ongc

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Contents

CHAPTER1: INTRODUCTION.............................................................................................. 31.1 Foundation.................................................................................................................. 3

CHAPTER2: ONGC AS PROCESSING INDUSTRY ............................................................ 5

2.1 Process Plant.......................................................................................................... 5

2.1.1 Co-generation Plant......................................................................................... 5

2.1.2 Oil and Gas process plant............................................................................... 5

2.2 Utilities .................................................................................................................... 5

2.3 Environment System.............................................................................................. 62.4 Safety system ......................................................................................................... 6

CHAPTER3: INTRODUCTION TO URAN PLANT ............................................................... 7

3.1 CSU (Crude Stabilization Unit) ............................................................................ 10

3.2 Gas Sweeteing Unit(GSU) .................................................................................... 11

3.3 Ethane Propane Recovery Unit(EPRU) ............................................................... 12

3.4 Condensate Fractionating Unit (CFU)................................................................. 12

3.4.1 PROCESS ....................................................................................................... 13

3.5 Co- Generation (COGEN) ..................................................................................... 13

3.6 Slug Catcher......................................................................................................... 15

3.6.1 Capacity of slug catcher............................................................................... 15

3.6.2 Process Description ...................................................................................... 16

3.7 LPG Unit ................................................................................................................ 16

3.7.1 LPG recovery unit .......................................................................................... 16

3.7.2 LPG-1 Capacity .............................................................................................. 16

3.7.3 Product components of natural gas............................................................. 16

3.7.4 Basic principles ............................................................................................. 17

3.7.5 Refrigeration................................................................................................... 17

3.7.6 Fractionation .................................................................................................. 17

CHAPTER4: COMPRESSORS........................................................................................... 18

4.2 Applications.......................................................................................................... 18

CHAPTER5: CENTRIFUGAL COMPRESSOR................................................................... 19

5.1components of Centrifugal Compressor................................................................. 20


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5.1.1 Casing............................................................................................................. 20

5.1.2 Diaphragms .................................................................................................... 22

5.1.3 Rotor Assembly ............................................................................................. 23

5.2 Advantages And Disadvantages............................................................................. 28

5.3 Working Of Centrifugal Compressor...................................................................... 28

CHAPTER6: LEAN GAS COMPRESSOR (K-1503 A/B).................................................... 30

6.1 Compressor Parameters:..................................................................................... 31

6.2 Gear Box: .............................................................................................................. 31

6.3 Synchronous Motor: ............................................................................................ 31

6.4 Cooling Water System: ........................................................................................ 32

6.5 Sleeve Bearing Lubrication: ................................................................................ 32

6.6 Reading of K-1503 A: ........................................................................................... 33

CHAPTER7: RECIPROCATING COMPRESSORS ............................................................ 34

7. 1 Advantages And Disadvantages:........................................................................ 35

7. 2 Basic Design And Working: ................................................................................ 36

7. 3 The Thermodynamic Cycle:................................................................................. 39

CHAPTER8: OFF-GAS COMPRESSOR (K-2501 A/B) ...................................................... 41

8. 1 Compressor Parameters:..................................................................................... 41

8. 2 Condensing Equipments: .................................................................................... 42

8. 3 Reading of K-2501 A: ........................................................................................... 42

CHAPTER9:DIFFERENCE BETWEEN RECIPROCATING AND CENTRIFUGAL

COMPRESSOR................................................................................................................... 44

CONCLUSION .................................................................................................................... 46


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CHAPTER1:INTRODUCTION

Oil and Natural Gas Corporation Limited (ONGC) is a public sector petroleum

company involved in wide scale 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 governments maharatan companies which

involves most profit making five public sector companies and hence is one of the most

profit making companies in India whose turnover is about 3935.19 billion rupees with an

annual profit of about 938.61 billion rupees.

Bombay High (now Mumbai High) is an offshore oilfield located in the Arabian

Sea around 160km west of the Mumbai coast. Discovered in 1974, the field has been

operated by Oil and Natural Gas Corporation (ONGC). Production at the field started in

1976.

Crude oil produced from Bombay High is of very good quality as compared to

crudes produced in Middle East. Bombay High crude has more than 60% paraffinic

content while light Arabian crude has only 25% paraffin.

1.1 Foundation:

In August 1956, the Oil and Natural Gas Commission was formed. Raised frommere 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 has been ranked 357th in

the Fortune Global 500 list of the world's biggest corporations for the year 2012. It is also

among the Top 250 Global Energy Company. It produces around 77% of India's crude

oil and around 81% of its natural gas. 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 the Asias largest and most active companies involved in

exploration and production of oil and gas. It is involved in exploring for and exploiting

hydrocarbons in 26 sedimentary basins of India, and owns and operates over 11,000

kilometres of pipelines in the country. Headquarter of ONGC is Tel Bhavan which is

situated in Dehradun. Over 33,800 employees are working in this company which make it

largest company in terms of market capital in India.


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Fig:-1 Detail of ONGC on map

Fig: - 2 ONGC Oil Platform (210 km in Arabian Sea)

Fig:- 3 ONGC Mumbai High Oil Platform


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CHAPTER2: ONGC AS PROCESSING INDUSTRY

Any process industry can be solely divided into 4 parts:

Process plant

Utilities

Environmental system

Safety system

2.1 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 stabilised oil to different refineries. In sum to get this purpose

there is overall two plant:

2.1.1 Co-generation Plant:

Co-generation plant can be also sub divided into mainly 3 different

process units:

Gas Turbine

Boilers

Gas fired boilers

2.1.2 Oil and Gas process plant:

Oil and gas process plant can be sub divided into 6 different processing

units:

Slug catcher unit

Condensate fractionation unit

Gas sweeting unit

Crude separation unit

LPG recovery unit

Ethane propane recovery unit

2.2 Utilities:

Utilities plays very important role in any process industry. They provide

support to process plant for the smooth running and continuous production.


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The basic utilities which are very necessary are:

Effluent treatment

Instrument air

Air dryer

Flare system Blow down system

Soft water system

Fuel gas

Inert gas system

2.3 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 aminimum 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 into two parts:

Primary environmental system: related to heath precaution

Secondary environmental system: related to environment

2.4 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

Fire water unit

Gas detection unit

Static charge removal unit


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CHAPTER3: INTRODUCTION TO URAN PLANT

Uran onshore facilities of ONGC is located at Uran in Raigad district, Navi

Mumbai. It is approximately 15 M above mean sea level. The 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 area are located at different elevations.

The Uran Plant is one of the most important installations of entire ONGC. It was

established in the year 1974 and expanded in stages. It receives the entire oil and part of

natural gas produced in mumbaai off shore oil fields. It presently handles 21% of the total

natural gas production of ONGC and 92% of the total oil produced by Mumbai Offshore.

Both the Oil and gas received prom offshore is processed at various units for producing

value added products like LPG,C2-C3, LAN, processing, storage and transportation of oil.

It has been 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 plant has an area of 5.5 km. During last 10 years, the ONGC Plant has

undergone lot of modifications, installation of new units and process control systems.

Timely up gradation and modernization of plant facilities and control system have

enabled ONGC to improve profitability, reduce cost of operation and optimize resource

utilization.

Fig.- 4 Layout of pipelines


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Fig. 5 Western off-shore


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Fig. - 6 Layout diagram for Uran plant

Fig. 7 Overall schematic of Uran complex


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The Uran plant has several units. These are as follows:

3.1 CSU (Crude Stabilization Unit)

3.2 GSU (Gas Sweetening Unit)

3.3 EPRU (Ethane, Propane Recovery Unit)

3.4 CFU (Condensate Fractionation Unit)3.5 Co-generation plant

3.6 Slug Catcher

3.7 LPG unit

3.1 CSU (Crude Stabilization Unit):

The CSU 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. This unit includes provision for dehydration and desalting crude oil.

Basically CSU is used to separate gases from oil and then compressed in

reciprocating compressors. And from there it is send to GSU unit for sweeting and other

process. In case LPG units are operating on sour gas CSU off gas can be taken directly

to LPG-I/II.

Fig. - 8 Flowchart of working process of CSU unit


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3.2 Gas Sweetening Unit(GSU):

Sweetening of a gas refers to the removal of hydrogen sulphate from the

gas. The Gas Sweetening Plant focuses on the removal of acid gases, hydrogen

sulphide (H2S) and carbon di oxide (CO2) from the feed gas. The feed gas consists of

slug catcher gas, CFU off-gas and SU off-gas.

For the sweetening of the sour gas, there are two identical trains. Each train

are designed for mixed sour gas feed of 5 MMNCM/day and a total capacity of 10

MMNCM/day. Usually only 50% of the designed capacity is used.

Fig. 9 Layout of process in GSU unit

The main two stages in this 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.

Firstly 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 Unit (CFU). Then

the gas is fed into the absorber column where CO2 and H2S are removed by countercurrent with lean sulfinol solution to meet the product specification.


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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 attachedboiler. The acid gas which is separated is released into sulphur recovery plant or directly

into the atmosphere.

3.3 Ethane Propane Recovery Unit(EPRU):

Ethane and Propane recovery are among the phase-3 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.

Fig. 10 Layout of EPRU process

3.4 Condensate Fractionating Unit (CFU):

The CFU has been designed and constructed for the stripping pf acid

components, H2S andCO2, from the condensate mainly supplied from slug catcher


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(Phase II and Phase III) and IHI & HP compressors. 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.

3.4.1 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 coalesce (X-1101)

operating at 48-52 kg/cm2g where water is removed and the condensate is fed to

the stripper column (C-1101). The Stripper column operates at 23-25 kg/cm2g andhere 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 reboiler (E-1101). The stripper bottom liquid is supplied to the

reboiler via stripper bottom pump and filter (X-1102). The vapour generated in the

reboiler is returned to the stripped for stripping and the stripping liquid in the reboiler

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 under standard pressure. Thecompressed gas goes to the cooler and then to the off-gas compressor discharge

K.O.D and from the gas is sent to GSU.

3.5 Co- Generation (COGEN):

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 fulfils the

requirement of both electrical power and steam at a very low cost and high efficiency and

reliability.

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/HRWaste heat recovery boilers


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Plant demand for power and steam:Power average - 41.0 MW/HRPower (peak) - 50.0 MW/HR

Steam - 150 TON/HR

Export (with 3 GTS) - 5.0 MW/HRImport (with 3 GTS) 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 Co-generation plant is always connected to the power grid MSEB in the case offailure of one of the turbines. Thus undisturbed power supply continues

Fig.- 11 Block Diagram of Co-generation plant


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3.6 Slug Catcher:

Bombay high gas is transported from offshore platforms to Uran Terminal via

26subsea lines about 210 km length (BUT lines) and the length of26 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 throughSHS-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 to consumers.

Slug catcher facilities are to serve the following objectives:

To separate the continuously coming condensate from the saturated gas by reducing

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/cm to 50kg/cm.

The retrograde condensation taking place and accumulation of liquid at the low points of

sea-bed.

3.6.1 Capacity of slug catcher

Phase 2:

Design capacity : 8 mm nm/day

Volume : 3100 m (this hold up is for 2 days)

Sea bed temp : 20C minimum

Phase-3:

Design capacity : 5mm nm/day

Volume : 450 m(this holds up for 2 days


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3.6.2 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 gasenters 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.

3.7 LPG Unit:

3.7.1 LPG recovery unit:

Two units of 5.65 MMSCMD capacities each receive 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

3.7.2 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).

3.7.3 Product components of natural gas:

Methane No. of carbon atoms 1 Lean gas to consumers

Ethane No. of carbon atoms 2 C2C3 to IPCL for further

processingPropane No. of carbon atoms 3 LPG at 8kg/cm2 to BPCL &


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HPCL

Butane No. of carbon atoms 4

Pentane No. of carbon atoms 5 Naphtha to IOTL for further

dispatch

Hexane+- No. of carbon atoms 6 To petrochemical plantsBasic principles

3.7.4 Basic principles:

LPG recover from natural Gas is made on the two principles:

Refrigeration

Fractionation

3.7.5 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.

3.7.6 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 vapours, so that a pure

component with maximum recovery can be achieved.


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CHAPTER4: COMPRESSORS

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.

4.1 Types Of Compressor:

Fig. - 12 Classification of Compressors

4.2 Applications:


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Gas compressors are used in various applications where either higher pressures

or lower volumes of gas are needed:

In pipeline transport of purified natural gas to move the gas from the production

site to the consumer. Often, the compressor in this application is driven by a gas

turbine which is fuelled by gas bled from the pipeline. Thus, no external power

source is necessary.

In petroleum refineries, natural gas processing plants, petrochemical and

chemical plants, and similar large industrial plants for compressing intermediate

and end product gases.

In refrigeration and air conditioner equipment to move heat from one place to

another in refrigerant cycles: E.g. Vapour-compression refrigeration.

In gas turbine systems to compress the intake combustion air

In storing purified or manufactured gases in a small volume, high pressure

cylinders formedical, welding and other uses.

In many various industrial, manufacturing and building processes to power all

types ofpneumatic tools.

In some types of jet engines (such as turbojets and turbofans) to provide the airrequired for combustion of the engine fuel. The power to drive the combustion air

compressor comes from the jet's own turbines.

CHAPTER5: CENTRIFUGAL COMPRESSOR
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Centrifugal compressors use the rotating action of an impeller wheel to exert

centrifugal force on refrigerant inside a round chamber (volute). Refrigerant is sucked intothe impeller wheel through a large circular intake and flows between the impellers. 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 chillier 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. 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.

5.1components of Centrifugal Compressor

A simple centrifugal compressor has three components:

Casing

Diaphragm

Rotor assembly

5.1.1 Casing:

For high pressure compressor, it need outer and inner casing to support its

pressure. Commonly, the nozzles are at the outer casing and inner parts such as

diaphragm, impeller and shaft are at the inner casing. Inner casing can be opened

as top inner casing and bottom inner casing in order to install the parts.

Outer Casing:

Most compressor manufacturers have standard castings or forgings of

their various housings and impellers from which they make up a compressor for a

particular set of operating conditions.

Inner Casing:

The inner casing have the parts been installed. During final fabrication,

the inner casing will be inserted into the outer casing (housing) which connect all

the inlet/outlet nozzles.

The casing size limits the flow, which can be passed through it while theimpeller castings limit the maximum and minimum head.
http://en.wikipedia.org/wiki/Bernoulli%27s_principlehttp://en.wikipedia.org/wiki/Bernoulli%27s_principlehttp://en.wikipedia.org/wiki/Bernoulli%27s_principlehttp://en.wikipedia.org/wiki/Bernoulli%27s_principle


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The construction features of the two models in use are:

Horizontally split casing design:

The horizontal plane in the middle and consists of an upper and lower

part. All necessary connections, such as suction and discharge nozzles,intermediate suction and discharge nozzles, wherever required, and lube

oil inlet and drain connections are integral with the lower half. Internal parts

can be accessed just by lifting the upper part which needs no major

dismantling of piping. For inspection of bearings, there is no need to remove

the upper half. Only bearing cover removal is adequate.

Fig. 13 horizontally split casing

Vertically split casing design:

These are used when the working pressure and type of gas demandsuch an arrangement. All internal parts are similar to the horizontally split type

casing, but the diaphragm seals and the rotor bundle are inserted axially in a

forged steel barrel casing. Ends are closed with end covers; the lower half of

the bearing housing is integral with the end cover. By removing the end cover,

it is possible to withdraw the complete internal assembly and have access to

the internals like seals, diaphragms and rotor, without disturbing the outer

casing.

There is no need to remove end covers for bearing inspection.


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Fig. - 14 vertically split casing

5.1.2 Diaphragms:

The diaphragm is generally made of cast steel. However, based on

operating conditions, alloyed cast iron, forged steel or stainless steel materials are

also used. In small and medium size casings, the diaphragms are fabricated from

plates.

FUNCTION:

The function of the diaphragm is:

To form the dynamic flow path of the gas inside the compressor.

To form the separation wall between one Compressor stage and the

subsequent one.

To convert the kinetic energy of the gas leaving the impeller into

pressure energy.

TYPES OF DIAPHRAGM:

They are of three types:

I. Suction diaphragm

II. intermediate diaphragm

III. Discharge diaphragm


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Fig. 15 interstage Seals Diaphragm

5.1.3 Rotor Assembly:

The basic function of the centrifugal compressor rotor is to impart the

required compression energy to the gas.The rotor forms the heart of the centrifugal compressor, consisting of the

shaft, Impellers, spacers, bushes, Balancing drum, thrust collar, Coupling hub and

thrust bearing.

The impellers are hot shrunk and keyed. The shrinking of impeller and

balancing piston is necessary to ensure that the impeller does not get slackened

due to the centrifugal forces during start up and normal running of the compressor.

This would otherwise result in vibrations on the rotor system. Rotor must perform its

function with a deflection less than the minimum clearance between rotating and

stationary parts. The loads involved are the torques, the weight of the parts, and

axial gas forces. The rotor, during assembly is balanced stage wise.

Fig. 16 rotor assembly


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The components of rotor assembly are as follows:

Impellers:

An impeller in centrifugal compressor imparts energy to a fluid.

The impeller consists of two basic components:I. An inducer such as an axial-flow rotor

II. The blades in the radial direction where energy is imparted by

centrifugal force

There are three types of impeller:

Types ofImpeller

Advantages Disadvantages

Radial blades 1. High absolute outlet

velocity2. No complex bending3. Ease in

manufacturing

Surge margin is narrow

Backward curvedblades

1. Low outlet kineticenergy

2. Low diffuser inletMach no.

3. Surge margin iswidest

1. Low energytransfer

2. Complexbending stress

3. Difficulty inmanufacturing

Forward curvedblades

High energy transfer 1. High outletkinetic energy

2. High diffuserMach no.

3. Complexbending stress

Fig. 17 semi open impeller


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Fig.- 18 centrifugal impeller

Shafts:

The shaft is made out of forged alloy steel and the impellers, spacers

and the balancing drum are shrunk fitted on it. Spacers of stainless steel

material are used to protect the shaft against gas erosion and corrosion.

The shaft is made by turning and grinding operations. Journal bearing

zones of the shaft is ground and burnished with the diamond burnishing

technique to improve the surface finish and to keep the total run outs within

the permissible limits.

Fig. 19 rotor shaft

Bearings:

The bearings in turbo machinery provide support and positioning for

the rotating components. Radial support is generally provided by journal or

roller bearings, and axial positioning is provided by thrust bearings.


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Radial bearings:

The heavy frame type gas turbines use journal bearings. Journal

bearing may be either full round or split; the lining may be heavy, as in

large-size bearings for heavy machinery, or thin, as used in precision insert-type bearings in internal combustion engines.

Fig. 20 radial bearing

Thrust bearings:

The most important function of a thrust bearing is to resist the

unbalanced force in a machines working fluid and to maintain the rotor

in its position (within prescribed limits).

Fig. 21 thrust bearing

Fig. 22 components of thrust bearing


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Seals:

Seals are very important and often critical components in turbo

machinery, because they spin at very high speed. In order to prevent frictionsand wears, seals play the most important roles for these matters.

Labyrinth seals:

The labyrinth is one of the simplest of sealing devices. It consists of

a series of circumferential strips of metal extending from the shaft or from

the bore of the shaft housing to form a cascade or annular orifices.

The major advantages of labyrinth seals are their simplicity,

reliability, tolerance to dirt, system adaptability, very low shaft power

consumption, material selection flexibility, minimal effect on rotor dynamic,back diffusion reduction, integration of pressure, lack of pressure limitations,

simple to manufacture and tolerance to gross thermal variations.

Mechanical seals:

A typical mechanical seal has two major elements. They are the oil-

pressure-gas sea land breakdown bushing.

This seal normally have buffering via a single ported labyrinth

located inboard of the seal and a positive shutdown device which will

attempt to maintain gas pressure in the casting when the compressor

pressure is at rest and the seal oil is not being applied.

Dry gas seals:

The use of dry gas seals in process gas centrifugal compressors

has increased over the last thirty years, replacing traditional oil film

(mechanical) seals in most applications. Dry gas seals are basically

mechanical seals consisting of a mating ring, which rotates, and a primary

ring, which is stationary. As gas enters, it is sheared towards the gap to act

as seals. During normal operation, the running gap is approximately 3

microns.


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5.2 Advantages and Disadvantages:

5.3 Working of Centrifugal Compressor:

The centrifugal compressor, originally built to handle only large volumes of low

pressure gas and air (maximum of 40psig), has been developed to enable it to move

large volumes of gas with discharge pressures up to 3,500 psig. However, centrifugal

compressors are now most frequently used for medium volume and medium pressure airdelivery. One advantage of a centrifugal pump is the smooth discharge of the

compressed air. The centrifugal force utilized by the centrifugal compressor is the same

force utilized by the centrifugal pump. The air particles enter the eye of the impeller,

designated D in Figure 23. As the impeller rotates, air is thrown against the casing of the

compressor. The air becomes compressed as more and more air is thrown out to the

casing by the impeller blades. The air is pushed along the path designated A, B, and C in

Figure 23. The pressure of the air is increased as it is pushed along this path. Note in

Figure 6 that the impeller blades curve forward, which is opposite to the backward curve

used in typical centrifugal liquid pumps. Centrifugal compressors can use a variety ofblade orientation including both forward and backward curves as well as other designs.


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There may be several stages to a centrifugal air compressor; a higher pressure would be

produced. The air compressor is used to create compressed or high pressure air for a

variety of uses. Some of its uses are pneumatic control devices, pneumatic sensors,

pneumatic valve operators, pneumatic motors, and starting air for diesel engines.

Fig. - 23 working principle of centrifugal compressor


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CHAPTER6:LEAN GAS COMPRESSOR (K-1503 A/B)

Centrifugal compressor is two stage compressors in which there are total 6impeller. 4 impeller are in 1st stage whereas in second stage 2 impeller are present. In

this compressor lean gas is compressed. The suction of gas is axially.

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/cm2g. Then lean gas is

compressed to about 40kg/cm2g by lean gas compressor. The compressor gas after

cooling to about 40C is supplied at battery limit for gas consumers.

Fig.- 24 lean gas compressor


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6.1 Compressor Parameters:

Compressor type: 2BCL606 Speed: 8610 rpm

Capacity: 106210 kg/hr wt Maximum constant speed: 9964 rpm

Gas handled: Lean gas Discharge temperature: 85C

Molecular weight: 16.40 First critical speed: 3970 rpm

Suction pressure: 12.5 kg/cm A Casing design pressure: 80 kg/cm G

Discharge pressure: 45.2 kg/cm A Maximum allowable temperature: 180 C

Suction temperature: 20.5 C Maximum casing working pressure: 80kg/cm2G

6.2 Gear Box:

Power: 10650 KW Speed input: 1800 min-

Speed output: 9116 min-

Oil required: 265 l/min (approx.: 10%) Oil pressure: 1-2 bar

Gear ratio: 5065 List of lubricant: D177

Service factor: API 1,4 Viscosity class: D/N 51519 ISOVG46

Lubricant: D/N 515102 L-TD

6.3 Synchronous Motor:

Type: SAT 95.1226, 5-4 Output: 10650 KW

Voltage: 1946 Volts Current: 1767 amp (AC)


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Frequency: 36 to 65.56 Phase: 2 3

Speed (1080 to 1967 rpm) range: 1800 Over speed rpm: 2160

Power factor: 0.92 Excitation voltage: 8.6 volt

Excitation current: 552 amperes Standard: IEC

Moment of inertia (WR ): 573 kg m Motor weight: 27100 kg

Kinetic energy constant (S): 1.146 Maximum inlet temperature (air): 43 C

Maximum inlet temperature (water): 33 C Temperature rise (stator k): 77

Temperature rise (rotor k): 87

6.4 Cooling Water System:

Flow: 0.38 m /hr. Pressure drop: 0.2 bar

Maximum operating pressure: 6 bar Test pressure: 10 bar

Maximum temperature (inlet): 33 C Maximum temperature (outlet): 40 C

Weight of water: 100 kg Weight of cooler empty: 1740 kg

6.5 Sleeve Bearing Lubrication:

Kinematic oil viscosity: 46 mm2/sec at 40C Oil flow per bearing (main shaft extensionend): 13 l/min

Oil flow per bearing (opposite end): 13l/min


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6.6 Reading of K-1503 A:

Is Stage Suction

Temperature (15-TI-605) (C)

Is Stage Discharge


IIn Stage Suction


IIn stage Discharge


-20 115 55 85

Is Stage Suction

Pressure (15-PI-607) (kg f/cm2G)

Is Stage Discharge


IIn Stage Suction


IIn Stage Discharge


12.5 28.2 29.8 45.2


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CHAPTER7: RECIPROCATING COMPRESSORS

A reciprocating compressor uses the reciprocating action of a piston inside a

cylinder to compress refrigerant. As the piston moves downward, a vacuum is created

inside the cylinder. Because the pressure above the intake valve is greater than the

pressure below it, the intake valve is forced open and refrigerant is sucked into the

cylinder. After the piston reaches its bottom position it begins to move upward. The intake

valve closes, trapping the refrigerant inside the cylinder. As the piston continues to move

upward it compresses the refrigerant, increasing its pressure. At a certain point the

pressure exerted by the refrigerant forces the exhaust valve to open and the compressed

refrigerant flows out of the cylinder. Once the piston reaches it top-most position, it starts

moving downward again and the cycle is repeated.

Fig. 25 Movement of Piston during compression

Reciprocating compressors are often some of the most critical and expensive

systems at a production facility, and deserve special attention. Gas transmission

pipelines, petrochemical plants, refineries and many other industries all depend on this

type of equipment. Due to many factors, including but not limited to the quality of the

initial specification/design, adequacy of maintenance practices and operational factors,

industrial facilities can expect widely varying lifecycle costs and reliability from their own

installations.

Various compressors are found in almost every industrial facility. Types of gasescompressed include the following:


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Air for compressed tool and instrument air systems

Hydrogen, oxygen, etc. for chemical processing

Light hydrocarbon fractions in refining

Various gases for storage or transmission

Other applications

There are two primary classifications of industrial compressors: intermittent flow

(positive displacement), including reciprocating and rotary types; and continuous flow,

including centrifugal and axial flow types.

Reciprocating compressors are typically used where high compression ratios

(ratio of discharge to suction pressures) are required per stage without high flow rates,

and the process fluid is relatively dry. Wet gas compressors tend to be centrifugal types.

High flow, low compression ratio applications are best served by axial flow compressors.

Rotary types are primarily specified in compressed air applications, though other types of

compressors are also found in air service.

7. 1 Advantages And Disadvantages:


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7. 2 Basic Design And Working:

The primary components of a typical reciprocating compressor system can be

seen in Figures 26, 27 & 28.

The compression cylinders (Figure 27), also known as stages, of which aparticular design may have from one to six or more, provide confinement for the process

gas during compression. A piston is driven in a reciprocating action to compress the gas.

Arrangements may be of single-or dual-acting design. (In the dual-acting design,

compression occurs on both sides of the piston during both the advancing and retreating

stroke.) Some dual-acting cylinders in high-pressure applications will have a piston rod

on both sides of the piston to provide equal surface area and balance loads. Tandem

cylinders arrangements help minimize dynamic loads by locating cylinders in pairs,

connected to a common crankshaft, so that the movements of the pistons oppose each

other. Gas pressure is sealed and wear of expensive components is minimized throughthe use of disposable piston rings and rider bands respectively. These are formed from

comparatively soft metals relative to piston and cylinder/liner metallurgy or materials such

as poly-tetra-fluoro-ethylene (PTFE).

Fig. 26 Reciprocating Compressor Cylinder Assembly

Most equipment designs incorporate block-type, force-feed lubrication systems;

however when there is zero process tolerance for oil carryover, non-lubricated designs

are employed. Cylinders for larger applications (typical cut off is 300 hp) are equipped

with coolant passages for thermo-syphon or circulating liquid coolant-type systems,

whereas some smaller home and shop compressors are typically air-cooled. Large

application cylinders are generally fitted with replaceable liners that are press-fitted into

the bore, and may include an anti-rotation pin.


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Fig.- 27 Two-throw HSE Frame and Running Gear

Process gas is drawn into the cylinder, squeezed, contained and then released

by mechanical valves that typically operate automatically by differential pressures.

Depending on system design, cylinders may have one or multiple suction and discharge

valves. Unloaders and clearance pockets are special valves that control the per cent of

full load carried by the compressor at a given rotational speed of its driver. Unloaders

manipulate the suction valves action to allow the gas to recycle. Clearance pocket valves

alter the cylinder head space (clearance volume). They may be fixed or variable volume.


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Fig.- 28 Two-throw HSE Frame and Running Gear

The distance piece (sometimes called the doghouse) is a structural member

connecting the compressor frame to the cylinder. Intermixing of fluids between the

cylinder and the distance piece must be avoided. Packing rings contain gas pressurewithin the cylinder, and they keep oil from entering the cylinder by wiping oil from the

piston rod along its travel. The distance piece is typically vented according to the most

hazardous material in the system, which is often the gas compressed in the cylinder. The

packing rings are designed to contain the gas within the cylinder, but with the high

pressure it is possible that some of the compressed gas will leak past the packing rings.

The running gear, housed within the compressor frame (Figure 26), consists of

the crosshead and connecting rod which connect the piston rod to the crankshaft,

converting its rotary motion into a reciprocating linear motion. The crankshaft is fitted with

counterweights to balance dynamic forces created by the movement of the heavypistons. It is supported within the frame of the compressor by plain bearings at several


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journals. A flywheel is also provided to store rotational inertia and provide mechanical

advantage for manual rotation of the assembly.

Some compressors will lubricate their frame running gear with an integral, shaft-

driven oil pump, while others are provided with more extensive, skid-mounted lubrication

systems. All properly designed systems will provide not only for oil circulation to thecritical surfaces of the equipment, but also for lubricant temperature control, filtration and

some measure of instrumentation and redundancy.

Suction gases are generally passed through suction strainers and separators to

remove entrained particulates, moisture and liquid phase process fluid that could cause

severe damage to the compressor valves and other critical components, and even

threatens cylinder integrity with disastrous consequences. Gas may also be preheated to

coax liquid process gas into the vapour phase. Intercoolers provide an opportunity for

heat removal from the process gas between compression stages. These heat

exchangers may be part of the compressors oil and/or cylinder cooling system(s), or they

may be connected to the plants cooling water system. On the discharge side, pressure

vessels serve as pulsation dampeners, providing system capacitance to equalize the flow

and pressure pulsations corresponding to the pistons compression strokes.

Typically, reciprocating compressors are relatively low-speed devices, and are

direct- or belt-driven by an electric motor, either with or without a variable speed drive

controller. Often the motor is manufactured to be integral to the compressor, and the

motor shaft and compressor crankshaft are one-piece, eliminating the need for a

coupling. Gearbox-type speed reducers are used in various installations. Sometimes,though less commonly, they are driven by steam turbines or other sources of power such

as natural gas or diesel engines. The overall design of the system and the type of driver

selected will influence lubrication of these peripheral systems.

7. 3 The Thermodynamic Cycle:

An explanation of a few basic thermodynamic principles is necessary to

understand the science of reciprocating compressors. Compression occurs within the

cylinder as a four-part cycle that occurs with each advance and retreat of the piston (two

strokes per cycle). The four parts of the cycle are compression, discharge, expansion

and intake. They are shown graphically with pressure vs. volume plotted in what is known

as a P-V diagram (Figure 29).


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Fig.- 29. Intake

At the conclusion of a prior cycle, the piston is fully retreated within the cylinder at

V1, the volume of which is filled with process gas at suction conditions (pressure, P1 and

temperature, T1), and the suction and discharge valves are all closed. This is

represented by point 1 (zero) in the P-V diagram. As the piston advances, the volume

within the cylinder is reduced. This causes the pressure and temperature of the gas to

rise until the pressure within the cylinder reaches the pressure of the discharge header.

At this time, the discharge valves begin to open, noted on the diagram by point 2.

With the discharge valves opening, pressure remains fixed at P2 for the

remainder of the advancing stroke as volume continues to decrease for the discharge

portion of the cycle. The piston comes to a momentary stop at V2 before reversingdirection. Note that some minimal volume remains, known as the clearance volume. It is

the space remaining within the cylinder when the piston is at the most advanced position

in its travel. Some minimum clearance volume is necessary to prevent piston/head

contact, and the manipulation of this volume is a major compressor performance

parameter. The cycle is now at point 3.

Expansion occurs next as the small volume of gas in the clearance pocket is

expanded to slightly below suction pressure, facilitated by the closing of the discharge

valves and the retreat of the piston. This is point 4.

When P1 is reached, the intake valves open allowing fresh charge to enter the

cylinder for the intake and last stage of the cycle. Once again, pressure is held constant

as the volume is changed. This marks the return to point 1.

Comprehending this cycle is key to diagnosing compressor problems, and to

understanding compressor efficiency, power requirements, valve operation, etc. This

knowledge can be gained by trending process information and monitoring the effect

these items have on the cycle.


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CHAPTER8: OFF-GAS COMPRESSOR (K-2501 A/B)

Fig.-30 off- gas reciprocating compressor

8. 1 Compressor Parameters:

Cylinder type: 2HHE-FB

Bore: 7.75

Stroke: 10.00

Normal discharge pressure: 746 PSIG

Rated discharge pressure: 965 PSIG

Maximum allowable working pressure: 1177 PSIG

Hydrostatic test pressure: 2950 PSIG

Maximum allowable cooling water pressure: 75 PSIG

RPM FRAME OUTER TOTAL AVERAGE

Disp.C.F.M at

422 105.5 115.2 220.7

% StdCylinder 11.50 10.60 11.05


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Clearance

Addedclearancevol.cu.in

NIL 13.82

Discharge valves: 49 K2 NEC.IM

Inlet valves: 48 K1 NEC.IM

8. 2 Condensing Equipment:

Design pressure: 55.0 kg/cm g Design temperature: 150C

Capacity: 183 litres Operating fluid: Off gas

Total weight empty: 361 kg Test pressure: 80.5 kg/cm G

Corrosion allow: Nil Radiography: 100%

8. 3 Reading of K-2501 A:

MAIN MOTOR WINDING / BEARING TEMPERATURE SCANNER (25-TJI-

371/A):

LOAD: 75%

1) Motor winding: 68.9C 2) Motor winding: 65.3C




9) Compressor mainbearing:55.6C

10) Compressor bearing:55.3C


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Suction pressure (25-PI-302): 22.3kg/cm

2g

Discharge pressure (25-PI-303): 51.0kg/cm

2g

Suction temperature (25-TI-302): 30C Discharge temperature (25-TI-304):79C

Current: 55 amperes


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CHAPTER9: DIFFERENCE BETWEEN RECIPROCATING ANDCENTRIFUGAL COMPRESSOR

Reciprocating compressors and centrifugal compressors have different operating

characteristics and use different efficiency definitions. The compression equipment used

for pipelines involves either reciprocating compressors or centrifugal compressors.

Centrifugal compressors are driven by gas turbines, or by electric motors. Reciprocating

compressors are either low speed integral units, which combine the gas engine and the

compressor in one crank casing, or separable high-speed units. The latter units operate

in the 750-1,200 rpm range (1,800 rpm for smaller units) and are generally driven by

electric motors, or four-stroke gas engines.

In centrifugal compressors there is no safety valve present as it is not a positivedisplacement compressor. Whereas, reciprocating compressors, being a positive

displacement compressor, are compiled with a safety valve in the discharge line.

S.No TopicReciprocatingCompressor

CentrifugalCompressor

1. Design Simple Complex

2. Initial cost Lower High

3. Moving parts Many less

4. FoundationMay required

depends on sizeDoes not requiredspecial foundation

1.Minimum suction

inlet pressure

Can be applied with

suction pressure atatmospheric oreven a slight

vacuum.

Inlet pressure toatmospheric or

below

2.Maximum

discharge outletpressure

Pressure up to 828bar

Pressure up to100 bar


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3.Maximum

discharge outlettemperature

Dischargetemperature limitsdepends on sealelement selected.

The temperature is

about 175 C

The temperatureis 204 to 232C

4.Minimum suctioninlet temperature

The inlettemperature can be

as low as -162C

Temperatureranges from -19

to -46C

5. Maximum flow

These are positivedisplacement

compressor. Themaximum flowdepends upon

cylinder size, the

number of throwand on the driver

speed.

These can besized for an inletflow of 680,000

m3/hr.

6. Minimum flowDepends on

cylinder size. Strokeand speed.

These can besized for flow as

low as 170 m3/hr.

7. Efficiency Less High

8.Volumetricefficiency

High Less

9. Sealing device Weather seal Mechanical seal10. Safety valve Present Not present

11. Materials

These compressorsare made of greyiron, ductile iron,and carbon steel.Piston and coversmay be made of

aluminium

Major componentsuch as casings,

nozzle and shafts,impeller are

primarily carbon,alloy or stainless

steel.

12. Manufacturing cost Less High

13. Maintenance cost

High due to wear

and tear of parts.

Less due to less

wear and tear.14. Installation time More Less


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CONCLUSION

Working with Oil AND Natural Gas Corporation Limited (ONGC) as a summer

training was a very nice experience. The whole training period was very interesting,

instructive and challenging. I learnt a lot about company and the real industry working

condition and practice. I also learnt about the centrifugal and reciprocating compressor. I

also practiced what I learnt in the university and applied it on field. I gained a good

experience in term of self-confidence, real life working situation, interactions among

people in the same field and working with others with different professional background. I

had an interest in understanding basic engineering work and practicing what has been

learnt in the class. Also, the training was an opportunity for me to increase my human

relation both socially and professionally.

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