Project report

ONGC HAZIRA PLANT Page 1 of 64

TRAINING REPORT

ON

OIL AND NATURAL GAS CORPORATION

GAS PROCESSING PLANT

HAZIRA, SURAT (GUJARAT)

Submitted in partial fulfillment of the requirement

For the award of the degree

BACHELOR OF ENGINEERING

In

CHEMICAL ENGINEERING

Duration: 26/05/2014 7/07/2014

Submitted by:

Jay Tailor

B.E Chemical engineering

M.S. University, Baroda


ACKNOWLEDGEMENT

Industrial Training is an integral part of engineering curriculum providing engineers with first hand and

practical aspects of their studies. It gives them the knowledge about the work and circumstances existing in the

company.

It gives me great pleasure to have completed my training at Gas Processing Plant of ONGC at Hazira and am

submitting the training report for the same.

I express my deep sense of gratitude to Mr. S.V.ACHARYA for giving us the permission for visiting and

orientation of the plant.

Our sincere thanks to Mr. N.R.CHAUDHARY, ONGC Hazira for guiding us through the various aspects,

functioning and processes of the plant and their effective coordination and allotting us the appropriate schedule

to undertake the training and last but not the least, we are also thankful to all the officers of plant for their kind

cooperation and valuable guidance throughout the process of work.

Jay Tailor

B.E Chemical engineering

M.S. University, Baroda


PREFACE

In any organization, success or failure of the company depend upon 4 Ms i.e. Materials, Men, Machine and

Method. Today is the age of competition and an organization cannot survive without satisfaction of its

customers. Quality of material is to be maintained in order to stand in the competitive market.

TO be a perfect engineer one must be familiar with individual experience in industrial environment.He must

be aware of basic industrial problems and their remedies.

While undergoing this type of industrial training at ONGC, Hazira Surat (Gujrat), I learned a lot of practical

aspect. My theoretical knowledge is exposed here practically.

In this report I have tried to summarize what I have learned in ONGC plant.

For preparing this report I have visited the plant, asked the process and related doubts to responsible personal,

inferred to manual and process report.

This study has been primarily undertaken by me with a view to evaluate the various process of the plant.


CONTENT

No. TOPIC Page No.

1 Over view of HGPC 05

2 Gas Terminal 09

3 Gas Sweetening unit (GSU) 15

4 Gas Dehydration unit (GDU) 21

5 Dew Point Depression unit (DPDU) 26

6 Condensate Fractionation unit (CFU) 30

7 Kerosene Recovery unit (KRU) 35

8 Caustic Wash unit (CWU) 43

9 Sulphur Recovery Unit (SRU) 45

10 LPG Recovery unit (LPGU) 56

11 Storage 59

12 Product terminal 59

13 Co-GEN, OFFSITE, UTILITIES 60

14 Conclusion 64


Overview of hazira plant Hazira gas processing complex was set-up in September 1985 to receive gas from

Mumbai high initially and subsequently to process sour natural gas from bassein and other offshore fields. Sour along with associated condensate is transfer through two subsea pipeline form bassein offshore platform to hazira plant.

1. 36 diameter pipeline (231 Km) 2. 42 diameter pipeline (244 Km)

Hazira plant is the largest gas processing complex in the country. It is designed

to process 41MMSCMD (Million Standard Cubic Meters per Day) sour gas Sour natural gas and associated condensate. Natural gas containing toxic and corrosive H2S gas is given a special treatment to making it sweet, marketable and safe for domestic and industrial use. The gas and condensate are received at the gas terminal in a slug catcher where gas and slug containing HC condensate, moisture and chemicals (like corrosion inhibitors) are separated. Gas and associated condensate are sent further in separate system for processing. The various processing units are,

1. Gas Receipt Terminal, 2. Gas Sweetening Unit (GSU), 3. Gas Dehydration Unit (GDU), 4. Dew Point Depression Unit (DPDU), 5. Sulphur Recovery Unit (SRU), 6. our Condensate Processing Unit, 7. Gas Based LPG Recovery Unit and 8. Kerosene Recovery Unit (KRU)

The sour gas and condensate are received from offshore in a multiphase flow. They are separated by gravity into two steams, gas and liquid at initial stage. The sour gas separated is taken out from top riser pipes of slug catcher to Gas Sweetening Unit (GSU) and the sour liquid thus collected is routed to Condensate Fractionation Unit (CFU).

The purpose of GSU is to remove lethal H2S from sour gas. Sour gas from slug

catcher is distributed to different GSU trains, which comes in counter current contact with lean amine solution (Methyl Di Ethanol Amine) in absorption column. The sweet gas leaves from the top of the column with 4 ppm H2S which is routed to GDU/LPG units. The rich amine enters the regeneration and re-circulation in the system. Acid gas liberated from top of the regenerator column during recycling of amine forms feed for sulphur recovery unit.

The Gas Dehydration Unit (GDU) aims at removal of water vapors from

sweetened gas from GSU. The sweet gas in counter-current contact with lean Tri-Ethylene Glycol (TEG) solution in absorption column. The dry gas liberated from top of the absorber forms feed for Dew Point Depression Unit. The rich TEG is sent to reboiler to regenerator to remove moisture. The regenerated TEG continuously recycled and reused in the system.


The purpose of DPD unit is to remove hydrocarbon condensate from the

sweetened and dehydrated gas by chilling to avoid hydrate formation in the long distance H-B-J pipeline. The feed gas from GDU trains is chilled to about -5 0C in a chiller with the help of propane refrigerator in closed circulation cycle. The cooled gas condensate is pumped to LPG plant for distillation. The treated gas is then sent to GAIL for onward transmission to H-B-J pipeline and partly to local consumers.

The Condensate Fractionation Unit (CFU) aims at removal of H2S and recovery

of LPG and NGL (Natural Gas Liquid) from the sour hydrocarbon condensate separated in the slug catcher. The liquid from slug catcher is distributed into stripper columns of various CFU trains. H2S is stripper from the condensate along with lighter hydrocarbons and fed to GSU trains for removal of H2S. The liquid from stripper bottom is fed to LPG column for recovery of LPG from the top and NGL from the bottom. The LPG is sent to caustic wash unit for removal of H2S. The LPG is sent to Caustic Wash Unit for removal of H2S. The NGL forms the feed for KRU.

The LPG from CFU contains upto 20 ppm H2S which has to be removed to less

than the permissible limit of 4 ppm in CWU before it is sent for storage in Horton spheres. The LPG is passed through absorber tower containing caustic solution to wash and remove H2S.NGL produced from CFU is given value addition in KRU by way of producing aromatic rich naptha (ARN), superior kerosene oil (SKO), heavy cut (HC) and/or high-speed diesel (HSD). The hot NGL is fed to Naptha Column for distillation from where Naptha is recovered as a top product. The bottom steam is fed to the kerosene column through the gas fired furnace for further fractionation. Kerosene/ATF is recovered from top of the kerosene column and HSD is recovered from the bottom.

A part of sweet gas from outlet of GSU (about 5 MMSCMD) and all the sweet

condensate from DPD are taken as feed to LPG recovery unit. Here cryogenic process is done by turbo-Expander. The feed gas is first dried in molecular sieve dryers and then chilled in a cold box to -300C. The chilled vapor is expanded isentropically in turbo-expander wherein temperature of the gas falls to -570C. In the chilling process heavier hydrocarbons (C3+) get liquefied and separated for fractionation in the LEF and LPG columns. The lean gas liberated is further compressed as per requirement of consumer. The product come out from the LPG unit is naphtha from bottom and LPG from top. A part of the LPG is further distillate to obtain propane, which is used as a refrigeration cycle in LPG and DPD unit.

The purpose of SRU is to convert acid gas liberated from GSU into elemental

sulphur for environment protection. Acid gas comes in contact with catalyst LOCAT solution in absorber. H2S is oxidized to elemental sulphur in presence of the catalyst. Air is introduced into Absorber for regeneration for catalyst. Sulphur is palletized up to 99% purity and sand for disposal in HDPE bags in the market. The catalyst is re circulated in the system and make up chemicals are dosed to maintain the quality. The vent gas from the top of absorber vessel containing CO2, N2, O2 and moisture vented to atm.


Hazira plant also has utility units & offsite facilities for safe and smooth operations. They are as follows,

1.) Cogeneration power 2.) Steam system 3.) Water system 4.) Air system 5.) Inert gas system 6.) Effluent treatment plant 7.) Product storage 8.) Dispatch


Major units of hazira plant

GAS TERMINAL

PROCESS OBJECTIVES:-

Facilities to receive safely pig & two-phase flow of gas and condensate stream through 36 and 42 offshore trunk lines.

Separation of gas and condensate streams and intermediate storage of separated condensate in slug catcher.

Gas distribution and metering.

MAJOR OPERATIONS:-

Separation of gas and condensate streams in slug catcher, Filtration and metering of gas and sent to GSU, Metering condensate and sent to CFU.

HOW IT DONE? Following are the major equipments installed in this unit.

Pig receiver/ blow down Pressure reducing valves Slug catchers Filtering unit Metering unit


Slug catcher:- The sour gas and condensate received from offshore in two phase flow. Here it is

separated into two streams one is gas and other is condensate as in first step. For this, the fluid coming from offshore trunk pipeline is routed through a set of pressure reduction control system (normally set at 70 Kg/cm2). Then through the cyclone separator/filters the fluid are distributed to the slug catchers for separation of gas and liquid. Slug catchers are nothing but the set of parallel pipe figure of 48 diameter and approximately 500 meters in length. These pipe fingers are mounted at slope of 50. The source gas separated is taken out from top riser pipes to go GSU and the sour liquid thus collected is routed to CFU.

Slug catcher-I Slug catcher-II Slug catcher-III No. of fingers 24 24 6 Diameter of fingers 48 48 48

Operating mode Connecting with 36/42

Connecting with 36/42

Idle

Length 498 m 498 m 498 m Design temperature 600C 600C 600C Design pressure 101 Kg/cm3 101 Kg/cm3 101 Kg/cm3 Hold up volume 11000 m3 11000 m3 2750 m3 Slopping in storage area 0.5% 0.5% 0.5% Slopping in separation area 5% 5% 5%


Gas filtering unit:- The gas from slug catcher is sent

for filtration in which any condensate entrained along with the gas is separated. Here filtration is done by centrifugal cyclone separator. Sour gas from Phsae-1slug catcher is sent to existing filtration unit and sweet gas from Phase-2/Phase-3slug catcher is sent to new filtration unit. For normal operation, two filters will be operated to cover the 256MMSCMD of sour gas and one is standby. New filtration unit has three filters. Each filter can treat a maximum of 580.000m3/hr (13.92 MMSCMD). It is designed on 101 Kg/cm3 pressure and 650C temp.

It removes 99% of 10 micron size

particle and 100% of 20 micron size particle. For normal operation, two filters are operated to cover sour gas. Sweet gas which is removed of solid particles goes to metering unit and then goes to DPD.

Each filter is equipped with liquid

automatic discharge, which is controlled by the liquid level inside filter itself. The condensate from sweet and sour gas is metered separately.

Gas filter separates gas from condensate particles with principle of centrifuge.

Gas filter has 20 diameter cyclones.

Feed is injected tangentially into the upper part of the cylindrical section and develops a strong swirling motion with the cyclone. Liquid containing the fine particle fraction is discharged out through the under flow.

Gas filters equipped with differential

pressure gauge to monitor any leakage. The liquid coming out of the filters will be sent to a single collecting line, connected with both the line conveying the condensate to blown down and with the feeding line of the stabilization plant. The condensate from sweet and sour gas is metered separately.


Blow down:-

Blow down is a

process through which water sludge, foreign particle and unwanted material is removed from pipeline. The gas travels a long distance from offshore to Hazira plant through pipelines. During this line take turn and become slant due to gravity. Heavier molecules and foreign solid particle get accumulate there. To remove them from the pipeline a PIG is send from offshore terminal. It travel through pipeline and scraps all the accumulated sludge are received at the pig receiver. The PIG is taken out and the pig receiver cleaned. This process is done once in a year.

PIG (pipeline inspection gauge) is also

use to inspect pipeline. Due to corrosion the thickness of the pipe is reduce so regular inspection is becomes necessary. To do this they just attached sensors on the PIG.

For measurement system have inlet/outlet isolation valves, flow strengtheners, orifice meter, temperature sensor, pressure sensor, flow computer etc.

Pressure reduction system is for maintain pressure inside arrival terminal within rang allow for which the terminal piping is designed.

Operation of MOV (motor operated valve) in 36 and 42 line is meant for by- passing the gas through the pressure reduction system. Pressure reduction valve is operated in between 65 to 70 Kg/cm2g.


GAS SWEETENING UNIT (GSU)


To reduce the H2S content of sour gas to 4 ppm. To limit the CO2 co-absorption to the minimum required and in any case, not more than 32%.

MAJOR OPERATIONS:-

Counter current absorption using aqueous solution of MDEA (Methyl Di-Ethanol Amine).

Regeneration of rich amine solution from lean amine solution in two stages.

I. Stage 1:- Flashing at intermediate pressure in MP flash drum. To generate fuel gas (release of physically absorbed hydrocarbons)

II. Stage 2:- Re-boiling of rich amine in regeneration to generate acid gas which is sent to SRU.

HOW IT DONE?

The purpose is to remove lethal H2S from sour gas. Sour gas from slug catcher is distributed to different GSU trains under the pressure control and flow control. Sour gas in liberated from CFU also joins this stream under flow control. The combined sour gas comes in counter current contact with lean amine solution (Methyl Di-Ethanol Amine of concentration 480 gm/lit) in absorption column having 14 valves type tray at 54-77 kg/cm2 pressure. The sweet gas leaves from the top of the column with 4 ppm H2S, which is cooled and routed to GDU/LPG unit through a knock out drum (KOD).

The rich amine from the bottom of the column flows to medium pressure absorbed/flash drum. The flash gases go to fuel gas header and rich amine (containing H2S) passes through the plate heat exchanger before it enter the regeneration column having 21 valve trays for regeneration of amine. Regenerated lean amine from the bottom goes back to the MDEA tank and re-cycles in the process. Acid gas, which consists of about 98 mole% of CO2 and about 2 mole% of H2S, liberated from top of the regenerator column forms feed for SRU.


Methyl Di-Ethanol Amine Process Principle:-

The selective removal of

HS is made by washing the sour gas with an aqueous solution of Methyl-Di- Ethanol-Amine (MDEA).The process principles are similar to the well known SNPA-DEA process. The only difference is the behavior of the ethanol amine used. Methyl-Di-Ethanol-Amine (MDEA) is tertiary amine, which does

not react easily with CO. The selectivity is so prompted by using the differences in the reaction rates between both HS and CO and tertiary amine. First the case a primary or secondary amine (monoethanolamine or diethanolamine) whose reactions with the acid

components HS and CO are similar is investigated.

HS reacts to give amine hydrosulfide:

HS+RNH HS, RNH .. (1)

CO can react directly with amine to form an amine carbonate:

CO+2RNH RNCOO, RNH .. (2)

But CO can also react with water or hydroxyl ions to form carbonic acid or bicarbonate ions:

CO+HO HCO .. (3)

CO+HO HCO ... (4)


These acids then react with the amine to form amine bicarbonate (HCO, RNH) and amine carbonate (CO, (RNH)). As regards kinetics, three types of reactions can be distinguished

Reaction(1) whose rate is infinite, Reaction(2) whose rate is moderate, depending on amine Reaction(3) and (4), known to be slow

It is known that using MEA or DEA the absorption rate CO in the absorber may be lower than the absorption rate of HS; however CO removal is regarded as complete. The case of tertiary amine is different. As a matter of fact, the

molecular structure of the tertiary amine prevents the direct reaction of CO with carbonate formation (reaction (2)). Reaction rate difference between CO and HS is thus clearly marked since there only remains reaction (1) whose rate is infinite and reaction (3) and (4) whose rates are slow. To perform a selective de-sulfurization using a MDEA solution, it is necessary to provide in the absorber a gas-liquid contact time large enough

to remove HS but short enough to retain CO partially. HS and CO absorption performance control is therefore mainly controlled by the gas-liquid contact time in the absorbers.

Contact time depends on:

The gas flow rate The liquid height above the active plant area The number of plates in the absorber The first two parameters cannot be acted upon. The third parameter (plate

quantity) allows adjusting contact time according to the feeding conditions and required performance.

Absorption Section:- Absorption between sour gas and MDEA is done in absorption column which

contain 14 valve trays. Sour gas comes from the gas terminal is first heated by steam. Then it mix with stream come from CFU and sent to inlet gas KOD. Bottom product of the KOD is sent to CFU. From there sour gas goes to the absorption column where its temperature is around 54 to 77 0C and flow rate is around 175 KNm3/hr. From the top MDEA (lean amine) is enters at 420C and around 180 m3/hr flow. There are five entrances for lean amine at different plates from top to control contacting time.

Top product of the adsorption column is sweet gas. First it is cooled down to

300C from 440C then it is sent to outlet gas KOD and from there it sent to GDU or LPG unit. Bottom of the absorption tower is rich amine and it is sent for amine recovery. Following are the operating parameters and variables that affecting the absorption rate.

.


Gas Flow Rate: - around 223 KNm3/hr (in phase-IIIA 262.5 KNm3/hr) at 76.5 kg/cm2 pressure, turndown ratio 40%.

Less flow may lead to, Under utilization of train capacity; More CO2 absorption.

More floe may lead to, Tendency to foaming; More pressure drop across unit; Inadequate H2S absorption.

Gas Pressure: - 77 Kg/cm2 max system pressure & 54 Kg/cm2 is min system pressure.

Low absorption pressure may lead to, Inadequate H2S absorption; Reduction in overall response time,

as the control valves tend to get fully open.

More absorption pressure may lead to,

Higher hydrocarbon absorption in the amine and subsequent high fuel gas generation.

Feed Gas Temperature: - 25 to 35 0C at absorber inlet

Low temperature may lead to, Hydrate formation during

pressure reduction in high pressure operation.

More temperature may lead to, Inadequate H2S absorption; Fouling of heat exchanger and

affect GDU performance.

Feed Gas Quality: - should be free from dirt, debris, corrosion product and oils etc.

Presence of dirt may lead to, Foaming and subsequent loss in

processing capacity, antifoam loss, Inadequate absorption and other related problems

Lean Amine Flow: - 215 m3/hr in absorption column and 5 m3/hr in regeneration column, in phase-IIIA 226.3 m3/hr in absorption column and 19.4 m3/hr in regeneration column.

Les flow may lead to, Inadequate H2S absorption.

More flow may lead to, Energy loss; MDEA loss due to carry over; More CO2 absorption; Disturb column hydraulics and lead

to foaming.

Lean Amine Temperature: - amine injection temp should be just above feed gas temp (by +5 0C) max temp 43 0C.

Low temperature may lead to, Condensation of HC from gas and

subsequent foaming

More temperature may lead to, Inadequate H2S absorption; Fouling of heat exchanger and

affect GDU performance.

Variation In Column Pressure Drop: - No variation.

Low or no variation may lead to, Column stability and low foaming

tendency High variation may lead to, Foaming


MDEA Regeneration:-

The stream of the rich amine solution is recovered under level control valve from the bottom of the absorber and piped to the rich amine flash drum. In the flash drum pressure is reduce from 60Kg/cm2 to 9.85 kg/cm2. In order to meet the fuel gas

specifications (less than 4 ppm vol. of HS) this sour fuel gas is brought into contact with a small lean MDEA flow in a 6-valve tray absorption tower placed on the top of the rich amine flash drum.

The rich amine solution flows from the flash drum to the rich/lean amine

exchanger. It is a plate type heat exchanger. The rich amine flash drum, level control valve is located downstream of the exchanger in order to minimize the solution by degassing the exchanger plates.

MDEA solution stripping is accomplished in the regenerator by the vapor

generated from the re-boiler. The lean amine collected at the bottom of the regenerator is routed through amine-amine exchanger and cooled at 45C in a lean amine cooler and sent to a large amine storage tank.

The hot acid gas/steam mixture from the overhead of the regenerator is

cooled to 50 in a condenser where water vapor condenses. This condensed vapor is separated in the reflux drum and pumped back to the top section of the regenerator. The trays are provided for washing the acid gas with reflux water in order to minimize amine carryover.

Acid gas is sent to an acid gas header through a pressure control valve,

which maintains a 2.0 kg/cm minimum pressure on top of the reflux drum. From the storage tank, lean amine is pumped back to the absorbers by the main amine charge pump. The discharged amine stream is split into two parts through flow rate control valves: a main stream flows to the high pressure absorber and a smaller one to the fuel gas absorber.


GAS DEHYDRATION UNIT (GDU)


To reduce the water-content of sweet gas coming from GSU for pipeline transport through BHJ pipeline.

MAJOR OPERATIONS:-

Counter current scrubbing using hydroscope TEG (99.7 wt %) (Tri-Ethylene Glycol).

Regeneration of rich glycol solution from lean glycol solution in two stages.

I. Stage 1:- De-gasification at intermediate pressure at 10 Kg/cm2 in to liberate fuel

gas. II. Stage 2:- Re-boiling of rich TEG in regenerator to remove absorbed water and

concentrate the glycol to required level of 99.7%. Absorbed water is vented to atmosphere in the form vapors.

HOW IT DONE?

This unit aims at removal of water of water vapors from sweetened gas from GSU. The sweet gas enters inlet knock out drum of gas dehydration unit where any entrained MDEA is knocking out. The gas then comes in counter current contact with lean TEG solution in absorption column having 9 bubble cap trays at 75 to 52 Kg/cm2 pressure and 38 0C temperature. The dry gas liberated from top of the absorber forms feed for DPDU.

The rich TEG (containing water vapors) coming out of the absorber passes

through a set of cartridge filter, charcoal filter and send to reboiler & regenerator to remove absorbed moisture. The regenerated TEG is continuously recycled and reused in the system.

Absorption Section:-

Absorption between sweet gas and TEG is done in absorption column which contain 9 bubble cap trays. Sweet gas comes from the GSU is first sent to inlet gas KOD. Bottom product of the KOD is rich amine that overcomes with sweet gas which sent to GSU. From there sweet gas goes to the absorption column where its temperature is around 39.9 0C. From the top TEG (lean glycol) is enters at 440C and around 4.8 m3/hr flow.

Top product of the adsorption column is sweet dry gas. From the top of the

absorption column gas goes to scrubber to remove rich glycol comes with gas. After that gas is sent to the DPDU. Rich glycol collected from the both absorption column and scrubber is sent for glycol recovery unit.


Following are the operating parameters and variables that affecting the absorption rate.

Gas Flow Rate: - around 225 KNm3/hr (in phase-IIIA 248.8 KNm3/hr) at 74.9kg/cm2 BL pressure & 51.9 Kg/cm2 in LP case, turndown ratio 40%.

Less flow may lead to, Under utilization of train

capacity; More flow may lead to,

Tendency to foaming; Higher chances of TEG

carryover;

Inadequate H2O absorption.

Feed Gas Quality: - should be free from dirt, debris, corrosion product and oils etc. Presence of dirt may lead to,

Foaming and subsequent loss in processing capacity, TEG carryover, metering error, inadequate absorption and other related problems.

Lean Glycol Flow: - 3.0 to 7.5 m3/hr & In phase-IIIA 3.0 to 8.0 m3/hr

Less flow may lead to, Inadequate H2O absorption.

More flow may lead to, Energy loss; Glycol loss due to carry over; Disturb column hydraulics and

lead to foaming.

Lean Glycol Temperature: - Glycol injection temp should be just above feed gas temp (by +5 0C).

Low temperature may lead to, Condensation of HC from gas

and subsequent foaming

More temperature may lead to, Inadequate H2O absorption;

Fouling of heat exchanger and affect DPDU performance.

Variation In Column Pressure Drop: - No variation.

Low or no variation may lead to, Column stability and low

foaming tendency High variation may lead to,

Foaming .

Lean Glycol pH: - 7 to 7.5. Low pH may lead to,

Corrosion in storage tanks, regenerator and in absorber trays;

High pH may lead to, High dosage of pH boosting

chemicals may lead to degradation of TEG;

Blockage of any part of system.

Lean Glycol Concentration: - 98 to 99.7 wt % of TGE.

Low concentration may lead to, More pumping energy loss; More fuel gas generation; Inadequate H2O absorption.

High concentration may lead to, Higher water adsorption

performance

Reduce the quantity of heat exchanged in PHE, which increase reboiler duty;

Increase steam consumption in

regenerator reboiler.


TEG Filtration Package:- Tri-ethylene glycol will not exhibit a high degree of foaming if it is kept

free of surfactant type materials. These materials may be introduced through compressor oil plug cock lubricant, and corrosion inhibitors used in either the formation or in the gas gathering system. So such products must be chosen carefully. Special attention has been given in the design to foaming and fouling by use of:-

TEG degassing and hydrocarbon condensate removal. Cartridge filter on the full rich glycol stream with a standby unit. Charcoal filter on 30% of the rich glycol stream.

Regeneration Section:- First rich glycol is sent to the degasifier to remove dissolved gas from

the liquid. Before entering the regenerator column; the glycol is preheated in heating coil at the top of the regenerator. The flow of glycol to the heating coil is controlled by a 3 way valve which controls the top temperature of regenerator column. Temperature controller opens to allow cold rich glycol to flow to the heating coil. As the glycol flow through the coil it cools and partially condenses the hot vapors rising up the column thereby reducing the overhead temperature and providing an internal reflux for the column. The glycol which is not required to maintain top temperature flows through the bypass part of temperature valve and rejoins the preheated glycol stream from the heating coil.

The rich glycol stream then flows to the rich/lean glycol plate type

exchanger, where it is heated from 65 0C. to 145 0C by exchange with the regenerated lean glycol, before entering the glycol regenerator column. The regenerator column is an atmospheric column, which contains 4 bubble cap type trays and the previously mentioned heating coil.

The temperature in the regenerator reboiler is controlled at 180 0C by

temperature valve which controls the flow of HP steam. Glycol from the reboiler over flows to the stripper which is end mounted on to the reboiler. The stripper is a packed column and here the glycol is stripped by hot dry fuel gas to achieve a concentration of 99.7% wt. The fuel gas is preheated in a second coil of the reboiler by exchange with the hot liquid glycol before it enters the stripper.


The hot, stripped glycol from the base of stripper flows by gravity

through the rich/lean glycol plat type exchanger, here it is cooled from 185 0C to 80 0C by exchange with the cold rich glycol, before going to the surge drum. The gases from the top of the stripper are piped to the reboiler and the surge drum to maintain a slight positive pressure in these vessels.

The lean glycol collected in the surge drum at 80 0C is pumped by the

lean glycol injection pumps to the trim collar, where it is cooled to 38 0C by exchange with cooling water, in then returns to the absorber.


DEW POINT DEPRESSION UNIT (DPDU)


To reduce the hydrocarbon dew point of sweet dehydrated gas coming from GDU so as to make it suitable for transportation through BHJ pipeline.

The condensate produced during the process is use for extraction of LPG and NGL in LPGU/CFU.

MAJOR OPERATIONS:-

Gas is chilled using propane refrigeration system. Gas liquid separation in separator. Propane refrigeration system consists of single stage, duplex, reciprocating compressor with propane sub-cooling and propane quench.

HOW IT DONE?

The purpose is to remove hydrocarbon condensate from the sweetened and dehydrated gas by chilling to avoid hydrate formation in the long distance H-B-J pipeline. The feed gas comes from GDU trains. It first passes through gas- gas exchanger and cold to 150C. This gas is further cooled to about -50C in the chiller with the help of propane refrigeration in closed circulation cycle. The chilling temperature is controlled by temperature control valve, which regulates the gas flow through chiller and operates at a preset temperature valve in automatic mode. The cooled gas from the gas is exchangers where the chillness of the gas is exchanged with the incoming gas form GDU. This treated gas is then sent to GAIL for onward termination to B-J-P pipeline and partly to local consumers.

This unit can be separated into two major operational parts,

I. Chill down section II. Propane cycle


Chill Down Section:- The feed gas is first cooled by outgoing (Dew Point depressed) product

gas in gas-gas exchangers and it is then finally cooled to 2.5 0C in a Gas Chiller by evaporating refrigerant propane. The gas temperature at the outlet of chiller is controlled by a bypass control valve. Provision is kept to inject tri ethylene glycol at up-stream side of gas-gas exchanger to avoid freezing problems in chill down section which may crop up during malfunctioning of the dehydration unit.

Normally TEG injection shall not be done. The chilled gas is sent to

filter separator to knock out hydrocarbon condensate, traces of water, and glycol (if any) formed. The separated gas from exchanges cold with incoming feed gas in gas-gas exchangers.

The gas is then sent to pipeline compressor station for transportation in

H-B-J pipeline. Hydrocarbon condensate from filter separator is pumped through condensate transfer pumps to LPG plant/or slug catcher condensate header by level control valve. During phase I, when LPG plant is in operation, condensate transfer pumps are by passed, since the filter separator operating pressures are higher than condensate coalesce pressure of LPG plant. However, when the LPG plant is shutdown, then both the pumps are employed in series to transfer the condensate to slug catcher condensate header.


Propane Refrigeration Cycle:- Propane refrigeration system has been provided in the DPD Unit to

supply refrigeration required in gas chiller. Propane refrigeration system is provided as a part of the DPD unit. Once the system is filled with liquid propane it operates in a closed cycle and little make up from external source is required. Single stage refrigeration is provided. Propane from accumulator at 46 0C flows over to sub-cooler where it is sub-cooled by cooling water to 40 0C then it flows over to gas chiller through level control. Refrigerant propane after evaporation in the chiller flows over to suction knock out drum (KOD). Propane vapors are compressed by reciprocating propane compressor driven by electric motor. The resulting vapors are condensed in propane condenser and taken to accumulator for reuse in propane cycle.

Suction pressure of propane compressor is controlled by compressor

discharge to suction bypass control valve. Temperature of the bypassed propane gas is maintained at 0 0C by spraying liquid propane in a quench nozzle via a temperature control valve. In each train two refrigerant propane compressors are provided. While one compressor is in operation, other one is standby.


CONDENSATE FRACTIONATION UNIT (CFU)


To strip the H2S content of the condensate received from offshore through slug catcher.

To fractionation the condensate into stable and commercial petroleum products (LPG and NGL).

MAJOR OPERATIONS:-

To achieve proper separation of lighter and heavier hydrocarbon by maintaining vapor liquid equilibria within column through establishing temperature profile.

HOW IT DONE?

This unit aims at removal of H2S and recovery of LPG and NGL from the sour hydrocarbon condensate separate in the slug catcher. The liquid from slug catcher is distributed into various CFU trains. It is preheated and flash in condensate surge drum for separation of condensate water and gas. Condensate from the bottom of the drum is pumped to a stripper column having 20 to 40 valve trays through coalesce filters under flow control. In stripper column, H2S is stripped from condensate along with lather hydrocarbon and taken out from top of the column. The librated gas from surge drum and stripper column are jointly compressed by of gas compressor by off gas compressor and feed to GSU trains for removal of H2S. the liquid form strippers bottom is re-boiled and fed to LPG column having 60 valve type trays for recovery of LPG from the top and NGL from the bottom. The LPG is sent to CWU for removal f H2S. The NGL forms the feed for KRU or storage tank as per need.


H2S Stripper Column: -

Stripper is designed, to strip off H2S from condensate so that the sweet condensate in the bottom of the column has a maximum content of 4 ppm of H2S and retains maximum propane & butane in the bottom sweet condensate.

Following are the operating parameters and variables that affecting the stripping column.

Feed Rate: - around 30-75 m3/hr More flow may lead to,

Column flooding; Improper stripping of H2S

Feed temperature: - 35 to 38 0C. Lower temperature may lead to,

Incomplete stripping of H2S; Demands increase in re-boiler duty; Possibility of hydrate formation bellow 25 0C

High temperature may lead to, Liquid carryover from surge drum to suction;

Column operating pressure: - 17-24 Kg/cm2

Low pressure may lead to, Liquid carry over; Decrease volumetric efficiency of off gas compressor.

High pressure may lead to, Improper stripping of H2S; Demanding higher re-boiler duty;

Re-boiler outlet vapor temperature: - 125-154 0C. Lower temperature may lead to,

Increase in the H2S content in LPG column feed; Lighter HC will go to LPG column.

High temperature may lead to, Liquid carry over along with increase vapor load.


LPG Column: -

The stripper bottom liquid enters the LPG column at the 19th or 24th tray. This column has 60 trays and designed to separate LPG (Propane and Butanes) from heavier components.

Most of the Hydrogen Sulphide (about 4 ppm) present in the LPG

column feed appears in the LPG product resulting in 5-20 ppm concentration. This LPG is sweetened in a caustic wash unit (Bubbling of LPG liquid in a static bed of 15% caustic soda solution) and sent to storage. Following are the operating parameters and variables that affecting the stripping LPG column.

Reflux Rate: - around 1.5 times of LPG withdrawal High reflux may lead to,

Higher load in re-boiler. Lower reflux may lead to,

Off spec LPG. ,

Top temperature: - 60 0C. Lower temperature may lead to,

Higher RPV of LP; Loss of C4 in NGL; Demanding higher re-boiler duty.

High temperature may lead to, Higher weathering of LPG;

Column operating pressure: - 9.7 Kg/cm2 Low pressure may lead to,

Increase the load on the condenser. High pressure may lead to,

Demanding high operating temperature to maintain LPG spec;

Re-boiler outlet vapor temperature: - 175-185 0C. Higher temperature may lead to,

More heavier in LPG product; Demanding higher condenser duty.

Lower temperature may lead to, C4 in NGL


CONDENSATE OFF-GAS COMPRESSION: -

The stripper overhead vapor passes to the compressor suction knock out drum. The surge drum flashed vapor is also combined with this stream. Two reciprocating compressor (one operating & other standby) are provided to compress the sour gas.

FLARE SYSTEM: -

Common flare headers, Flare knockout drum and flare blow-down pumps are provided within the battery limits. All the Hydrocarbon vapor/liquid collected from vents and pressure relief valves will go to flare knock out drum from there the gas flows to the main flare stack through an offsite flare header, the liquid collected is pumped out to a slop tank located in offsite. Instrument air, Plant air, Service water, Inert gas are received at battery limit and supplied to the unit through headers.


KEROSENE RECOVERY UNIT (KRU)


To extract value added product from NGL produced from CFU. i.e. kerosene (SKO), Aromatic rich naphtha (ARN) and Heavy cut byproduct (HC).

MAJOR OPERATIONS:-

Fractionation of NGL obtained from CFU using two columns. Re-boiled heat is supplied using fuel gas fired, natural craft furnaces. Primary cooling of overhead vapors using finned tube air heat exchangers using forced draft.

HOW IT DONE?

NGL produced from CFU is given value addition in KRU by way of producing aromatic rich naphtha (ARN), superior kerosene oil (SKO), heavy cut (HC) and/or high speed diesel (HSD). The hot NGL at 180 to 190 0C and 10Kg/cm2 from CFU trains is flashed into surge drum through the pressure reduction valve at about 4.5 Kg/cm2. The vapor steam from top is feed to the naphtha column having 20 valve trays for distillation. The liquid stream from bottom is divide into two streams and is pre-heated in two separate heat exchanger before joining the vapor stream for a combined feed to the 12th tray of naphtha column operating at 0.7-0.9 Kg/cm2 pressure and 118-207 0C temperature.

The vapors from the top of the naphtha column are condensed at 55

0C by passing through forced draft air cooler. The ARN thus produced a liquid is taken to reflux drum. A part of this liquid is taken to the refluxed back to the naphtha column under flow control to facilitate distillation process and the balance is sent to ARN floating roof storage tanks. The bottom fluid from the naphtha column are drawn into three steams, of which two are routed through fuel gas fired two pass furnace at 259 0C acting as a re-boiler and the third stream is further fractionated in the second column.

Feed of the second column (kerosene column) is at the bottom tray

almost in complete vapor form. This is done by routing one bottom stream from naphtha column through second fuel gas fired furnace at 280 0C after preheating it in heat exchanger. The kerosene column is operated at 0.9-1.2 Kg/cm2 pressure and


250-273 0C temperature. The top vapors are cooled in air cooled condenser and take to reflux drum as SKO. A part of liquid from reflux drum is reflux back to kerosene column under flow control and balance is pumped to SKO storage tank under level control. The bottom product from kerosene column is withdrawn under level control and pumped to HDS storage tanks after adding a stabilizer chemical for storage stability.

Process Description: -

Kerosene Recovery Unit is designed to fractionate 148 T/hr from seven CFU trains and reprocessing NGL produced during annual shut down of KRU.

The Kerosene Recovery Unit consists of the following sections:

NGL feed receiving

Naphtha column feed preheat

Naphtha fractionation

Kerosene column feed preheat

Kerosene fractionation

NGL reprocessing


NGL Feed Receiving: - NGL from four trains of phase-I & II and three trains of phase-III &

IIIA of CFU is taken through two common 8 headers to Kerosene Recovery Unit. The feed NGL from individual trains is taken upstream of existing NGL coolers. It flows under level control and joins the main headers to KRU. In case of NGL units emergency shutdown, automatic routing of NGL from individual units to storage has been provided. This requires continuous cooling water circulation in existing NGL coolers. NGL feed is received at plant B/L at a

pressure of 9.5 Kg/cm2g and a temperature of 170 C. In order to avoid excessive flashing in the offsite line a back pressure control valve is installed on the feed line. NGL is then led to a surge drum operating at a pressure of 4.6

kg/cm2g and a temperature of 155 C. The vapor generated due to flashing in the surge drum is fed under

back pressure control to the 12th tray of Naphtha column. The liquid from surge drum flows under level to flow cascade control to the Naphtha column feed preheat section. This control ensures steady feed to Naphtha column.

Naphtha Column Feed Preheat: -

The feed to this section enters at pressure of 2.9 kg/cm2g and a

temperature of 141.5c (due to pressure drop across the control valve). It is led into the feed/bottoms exchanger where it exchanges heat with the bottom

product of Naphtha column and is heated to 146.5C. The Naphtha column

bottom product in turn is cooled from 206.5c to 175C. This arrangement has been provided to reduce the load on Naphtha column re-boiler, thereby resulting

in energy optimization. The feed at a temperature of 146.5C is then mixed with vapor liberated from surge drum and led to the Naphtha column.

Naphtha Fractionation Section: -

Naphtha product has an end point of 140C. Naphtha column is designed to separate Naphtha from heavier components. The feed, which is a mixture of liquid and vapor, enters the column at the 12th tray. The column has a total of 20 valve trays. Due to higher vapor load in the top section, the diameter is higher (3350 mm I.D) as compared to the bottom section (3000 mm I.D). The column pressure is maintained at 1.9 kg/cm2g at bottom and 1.7


kg/cm2g at top with the help of inert gas whose flow is regulated through two make up and two flare pressure control valves that operating in split range.

Column top temperature is maintained at around 118.3c. The overhead vapors are condensed in an air-cooled condenser and led to a reflux

drum operating at a temperature of 55C. Reflux drum is provided with a boot to separate out any water flowing along with hydrocarbons. A part of the liquid from Reflux drum is refluxed to the column with the help of pumps under flow control which is regulated by an advanced controller (presently not installed).

The rest of the liquid after being cooled to 43C. in trim cooler is withdrawn under level control as Naphtha product.

Since the bottom temperature of the column is very high (206.5c), steam cannot be used for re-boiling. Hence, a double pass gas fired heater re-boiler has been provided. The liquid to the re-boiler is circulated using pumps.

The outlet temperature from the heater is controlled at 245c by regulating fuel gas flow to the heater. The flow to the individual passes of the heater is maintained same with the help of flow control valves. (Also Pass Balancer part of proposed APC). The bottom product is withdrawn under level control at a

temperature of 206.5c and sent to exchanger.

Kerosene product has an IBP of 140 C and FBP of 290 C. If the

Naphtha column bottom product has an FBP of less than 290c no further fractionation is required. The product after heat exchange is further cooled to 60

C in air cooled exchanger and sent to drum. From here, it is pumped under

level control to storage after being cooled further to 43 C in trim cooler.

However, in case the FBP less than 290 C, the columns can be used in parallel as two separate trains with capacity of 1.5 MMTPA. If however, the Naphtha

column bottom product has an FBP of higher than 290 C; it needs to be further fractionated in Kerosene column.


Kerosene Column Feed Preheat Section:-

The feed to this section is at a pressure of 13.5 kg/cm2g and a

temperature of 149 C. It is led to a feed/tops exchanger where it exchanges

heat with Kerosene column overhead vapor and is heated to 229.5 C. The

column overhead vapors are in turn cooled from 239.5 to 208.5 C.

The feed to kerosene column is then led to a single fired heater

where 98% of it is vaporized and the outlet temperature attained is 250c. The outlet temperature of the heater is controlled by regulating the fuel gas supply to the heater as in case of heater 98% vaporized feed is fed to the Kerosene column.

Kerosene Fractionation Section: -

Kerosene product has an end point of 290-300 C. Kerosene column is designed to separate Kerosene from heavier components. The feed, which is almost total vapor (98 wt %) enters the column at the 21st tray. The column has total 21 valve trays.

The column pressure is maintained at 2.2 Kg/cm2g at bottom and 2.0 kg/cm2g at top with the help of inert gas blanketing in kerosene reflux drum, whose flow is regulated through two makeups and two flare pressure control valves in split range as in.

Column top temperature is maintained at around 246.3 0C. The overhead vapors are first partially condensed in exchanger and then led to air

cooled exchanger where they are cooled and totally condensed at 60 C. The condensed liquid is led to a reflux drum. A part of the liquid from is refluxed to the column with the help of pumps under flow control and is regulated by

advanced controller. The rest of the liquid after being cooled to 43 C in trim cooler is withdrawn under level control as Kerosene product. The bottom

product (Heavy cut) at 273 C is pumped with the help of pumps under level

control to storage after being cooled to 45 C in a cooler.


NGL REPROCESSING:-

During the annual shutdown of KRU, the NGL produced from the CFUs will be diverted to storage. When KRU is restarted, it is proposed to reprocess this stored NGL. The total feed to KRU in such a case is 148 T/hr.

NGL to be reprocessed is received at plant B/L at a pressure of 6.4

kg/cm2g and a temperature of 35 C. It is heated to about 100.5 C in exchanger using Naphtha column bottom stream emerging from Exchanger at about 147

C. This stream in turn gets cooled to 114 C. The preheated feed then flows under flow control to surge drum after mixing with the main feed from CFU.


CAUSTIC WASH UNIT (CWU)


To remove the H2S contains form the product of LPG and CFU.

MAJOR OPERATIONS:-

First feed is washed by caustic solution then remove the adsorbed H2S from caustic solution in caustic flash drum.

Filtration of product (LPG/NGL) by rock salt and charcoal filtration

HOW IT DONE?

The LPG and CFU contains up to 20 ppm H2S which has to removed to less than the permissible limit of 4 ppm in CWU before it is sent to the storage in Horton spheres. The LPG and NGL are passed through absorber tower containing caustic solution to wash and remove H2S. Make-up caustic lye is added for maintain the quality of solution.

First LPG/NGL from CFU is goes to caustic wash drum which is fill

with caustic solution and gas pass from bottom. It is bubble tank type gas-liquid reactor. After achieve certain concentration of H2S it sent to the caustic flash drum where H2S and caustic solution are separated. H2S free gas goes to water wash to remove excess of caustic that comes with gas. Then it is sent to rock-salt and charcoal filters.


SULPHUR RECOVERY UNIT


Production of sulphur from H2S.

MAJOR OPERATIONS:-

Distribution of feed acid gas, Hydrogen Sulphide Absorption and LO-CAT Solution Regeneration LO-CAT solution cooling, Sulphur melting and separation, Sulphur storage and sulphur forming.

HOW IT DONE? The purpose is to convert acid gas liberated from GSU into elemental

sulphur for environmental protection. Acid gas coming from regeneration of GSU trains is taken to Adsorbed/Oxidizer vessel via inlet KOD under flow control, wherein it is comes in contact with catalyst LOCAT solution. H2S is oxidized to elemental sulphur in presence of the catalyst. Air is introduced into Absorber/Oxidizer for regeneration of catalyst

Sulphur slurry from the bottom of the oxidizer is pumped to melter/separator from where the molten sulphur is sent to surge drum and LOCAT catalyst is recycled to the top of the absorber, the vent gases from top of the Absorber/Oxidizer vessel containing CO2, O2, N2 and moisture are vented to atmosphere. The liquid sulphur from surge drum is pumped to preconditioning unit for temperature control and for pellets making in the rotoformer unit. Sulphur pellets (99% pure) are then sent for disposal in DHPE bags in the market.


10

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600

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Acid Gas Feed Distribution:- Acid gas from the Amine Gas Sweetening Unit enters the south battery

limits of the SRU Unit through a 24 pipeline header. The pipeline is sized to handle acid gas for both Phase-I, Phase-II and Phase-III of the Gas Processing Complex, or a total of 35,000 NM3/hr of Acid Gas. An on stream H2S analyzer on the acid gas header maintains a record of the H2S concentration of the acid gas in ppm (V). Acid gas flows from the header to five of the six operating sulphur recovery trains. The trains are numbered 61, 62, 63, 64, 65 and 65. Any combination of five trains may operate at any one time.

The

end of the acid gas header is equipped with a block valve and blind and provides expandability into Phase-II. In the event flow to one of the operating trains is choked, the pressure of the acid gas header will increase and controller will open control valve, sending the appropriate amount of acid gas to the incinerator in order to maintain pressure in the header. Pressure controller is set at a higher pressure than the normal operating pressure of the acid gas sent to the incinerator.

A high flow alarm on the incinerator line warns operators when the

acid gas rate to the incinerator is approaching the design rate of 7000 NM3/hr. This is required since the incinerator is designed to handle up to the equivalent of only one train or 7000 NM3/HR. Spectacle blinds and block off valves are provided at the branch connections of each one of SRU trains.

19

ABSORBER / OXIDIZER

ADDITIVESARI 310 C

ARI 310 M

Surf actant

Biochem

Def oamer

SLURRY

PUMP

SULPHUR

SLURRY

TO MELTERAIR

BLOWER

ACID

GAS

LOCAT


The flow to each train is controlled by a flow controller which is reset by the acid gas header pressure. This allows equal distribution of acid gas to the two operating trains regardless of acid gas pressure fluctuations. Each train is designed to process amine unit off gas at approximately 0.7 kg/sq.cm g and at a rate of 7000 Nm3/hr. The feed gas H2S concentration is to be reduced from a maximum of 5.2 mole % to 10 ppm (V).

The feed gas enters unit 61 through flow control valve and on to the

Feed Gas Knock out Drum, which removes any condensate entering the unit. The condensate is removed on level control and sent off to the MDEA Sump Storage Tank. Low level switch will automatically close level valve to prevent the acid gas from entering MDEA Sump Storage Tank. The scrubbed acid gas continues to the oxidizer/Absorber.

11

Acid Gas

Air

Sulphur Particles

Scraper

Reduced LoCAT

Regenerated LoCAT

Center Well ( 4 Nos. )

Air Spargers

Acid Gas Spargers

Air Blast Line

Auto circulation

Flow path

ABSORBER INTERNALS


Hydrogen Sulphide Absorption And Lo-Cat Solution Regeneration:- Absorption of H2S is accomplished by contacting the sour gas with

basic solution of ARI-310 catalytic regent in the center well of the liquid full Absorber/Oxidizer. The process gas is introduced into each of the four absorber sections through four 8 process gas sparer assemblies. Process gas leaves the absorber section of the vessel through a perforated gas-liquid distributor plate at the top of the center well it is mixed with spent air from the oxidizer section of the vessel and is finally vented to the atmosphere through the cooling tower. An H2S analyzer located in the discharge neck of cooling tower will activate an alarm when the H2S concentration reaches 15 ppm.

Circulating Lo-cat Solution is introduced into the Absorber section of

the vessel by spilling over the centre well wall through the gas liquid distributor plate. The absorption volume required to obtain the design H2S removal is maintained by providing enough liquid in the system to allow circulation. Circulating liquid leaves the absorber section of the main process vessel by under flow the centre wall, through the settler section and into the oxidizer section of the vessel.

The sulphur created by the reaction forms in the absorber section of the

vessel. Since the density of such sulphur is approximately twice that of water, the formed sulphur will settle down into the settler section of the vessel. A small amount of fine sulphur particles will continuously be circulated with the liquid catalyst solution but this will equilibrate at a low enough concentration not to interfere with H2S removal.

The reduced solution from the absorber sections of the vessel under

flow the center well wall and enters to the oxidizer section. As the reduced solution proceeds through the oxidizing section, it is regenerated by contract with air. The injection of air also serves the purpose of providing the driving force necessary to circulate the Lo-Cat solution by lowering the bulk density of the oxidizing section.

The solution is completely regenerated by the time it reaches the top of

the oxidizer section. Regenerated solution passes over the top will of the absorber center wells and proceeds down ward making counter current contact with upward flowing acid gas bubbles, thus completing the oxidation/regeneration cycle. Liquid flow down the center well is evenly distributed by a perforated baffle at the top of the center well section.


It is very important that the oxidizer air flow be maintained at all times. If the air supply is interrupted while the acid gas continues to flow into Absorber/Oxidizer, the most apparent consequence is the breakthrough of H2S to the atmosphere. A less apparent consequence is the over reduction of the Lo-Cat solution.

Excessive over-reduction may result in the change out of the entire

charge since it will reach a point where it will no longer be regenerated. The auto circulation system circulates catalyst solution between the oxidizer, absorber and settler sections of the vessels without the use of a circulating pump.

The driving force for liquid circulation is provided by the difference in

density between the aerated catalyst solution in the absorber and oxidizer sections of the vessel. The density of an aerated solution decrease with increasing acid gas velocity. The superficial gas velocity in the oxidizer section of the vessel is set at about twice that in the center well absorber section of the vessel.

The oxidizer section has been designed with sufficient superficial gas

velocity to assure adequate agitation for mixing gas and liquid in the oxidizer as well as providing a driving force for circulation liquid through the oxidizer and absorber sections of the vessel. The oxidation volume required to regenerate the catalyst solution at design H2S load is provided for with the level controller-water make up system which also takes care of the net loss of water experienced by the process. Dematerialized water on flow control is added either to the Absorber/Oxidizer, to the recalculating sulphur slurry line or a combination of both. DM water is added on flow control which is reset by level control valve.

The system has been designed to provide sufficient catalyst circulation

over the entire expected range of process gas flow rates. Liquid flows in up-flow, co-current direction to the air-flow in the annular oxidizer section and down flow, counter current to the process gas flow in the center well absorber section. Since circulation is accomplished by spilling liquid over the center well baffle, it is critical to the operation of the system that the liquid catalyst level be maintained considerably higher than the top of the center well baffle.


Lo-Cat Solution Cooling:- The reactions occurring in the process are exothermic, resulting in a

net gain of heat by the Lo-Cat solution. During winter months and/or times of low H2S concentration in the feed, the heat gain is more than compensated by the heat losses by evaporation of water into the oxidizer. However, during summer months and/or times of high concentration in the feed, the heat gain will result in Lo-Cat solution temperatures greater than the recommended 50 0C. It is during these times that a heat removal system is necessary.

SULPHUR MELTING AND SEPARATION Sulphur particles produced in the absorber section of surge tank drop

out into the settling section. The sulphur particles are about two times the density of water and rely on gravity to settle out into the cone section of surge tank.

Sulphur will accumulate in the cone section to a concentration of

approximately 10 wt. %. A continuously operating scrapper prevents bridging of sulphur by keeping the sulphur off the inside wall of the cone. An air blast sparger ring directs air jets towards the wall of the cone to prevent sulphur bridging in the lower section of the cone (below the scrapper). An adjustable timer has been incorporated with the air blast valve to provide a series of pulsating air jets.

Sulphur is withdrawn from the bottom cone of the settler section of

surge tank and pumped to the sulphur melter section of the unit by one of the two moyno type progressive cavity positive displacement pumps. De-mineralized water make-up is added to the sulphur slurry upstream of positive displacement pumps. This is done in order to wash the sulphur and produce a better quality sulphur product. As was mentioned earlier, this water make up can either be added directly to the Absorber/oxidizer or just upstream of the Sulphur Slurry pumps. The rate or water added upstream of positive displacement pumps is controlled by manually adjusting the ball valve downstream of flow indicator valve.


Sulphur slurry from positive displacement pumps proceeds to the sulphur Melter. 61-PSH-1203 and 61-PSL-1202 alarm in the control room when the sulphur slurry pressure is either too high (possible restriction problems downstream) or too low (malfunction of pressure valve or positive displacement pumps.) The Sulphur Melter is a vertical exchanger with the sulphur slurry flowing downward in the tube section. Low pressure steam which has been de-superheated is the heat source and is introduced into the shell side of the Sulphur Melter through temperature control valve.

Temperature controller maintains the temperature of the Lo-

Cat/Molten Sulphur leaving the Sulphur Melter at 130 0C. by adjusting temperature control valve. Condensate steam by gravity flows to condensate separator from which it is removed on level control through level control valve. Steam condensate proceeds to the condensate steam header. The Sulphur Melter is fully insulated and is equipped with a melting coil (for start-up and a jacketed bonnet on the discharge sides. The hot molten Sulphur/Lo-Cat solution proceeds through a jacketed line to the molten sulphur separator. Molten Sulphur settles to the bottom of surge tank and is removed on interface level control, through level control valve to the Sulphur Surge tank.

Low level switch will close level control valve when the sulphur level

drops too low. This prevents contamination of the molten sulphur with Lo-Cat solution. A high level switch will shutdown positive displacement pumps in the event the sulphur level approaches the top of the vessel high and low temperature alarms on surge tank will warn operators of possible malfunction of sulphur Melter. Hot Lo-Cat solution leaves the top of surge tank and returns to the cooling tower

12

SE

PA

RA

TO

R

SURGE DRUM

ME

LTE

R

STEAM

MOLTEN

SULPHUR

ROTOFORMER

BAGGING

FROM

ABSORBER

LOCAT RETURN

MELTER / SEPARATOR

4 kg/cm2

140 oC


which is located on top of surge tank. In returning, it goes through pressure control valve which maintains a pressure of 4.5 Kg/cm2g in the melting section.

SULPHUR STORAGE AND SULPHUR FORMING Liquid Sulphur from the sulphur separators flows to the sulphur surge

Tank where it is stored. The storage capacity of these tanks is about 7 days. The sulphur surge Tank is fully jacketed and insulated as elector system is provided to sweep the tank with air and remove sulphur vapour to a safe location. An internal, coil is provided to speed up start-up is the sulphur has been allowed to solidify within the tank.

Liquid sulphur is pumped from sulphur surge Tank by Sulphur

Transfer Pumps, to the sulphur preconditioning system. The Sulphur preconditioning system controls the temperature of the liquid sulphur feeding the sulphur forming system. Liquid sulphur continues to the sulphur forming system (Rotoformers) which produces high quality sulphur pellets. Pressure of the liquid sulphur entering the Rotoformers is maintained by diverting sulphur back to the Sulphur surge Tanks through pressure control valve. High and low pressure alarms warn operators of a possible malfunction of either pressure control valve, Sulphur Transfer Pumps or a plugging problem in Sulphur preconditioning system.

The Liquid sulphur header feeding the preconditioning units is

completely integrated with all five SRU trains. Molten Sulphur may be treated by any three preconditioners and proceed by any three of the sulphur forming trains. The sulphur pre-conditioning system controls the temperature of the molten sulphur to the sulphur forming system. In order for the sulphur forming system to operate efficiently and at the design capacities, the molten sulphur temperature must be in the range of 125 0C. to 135 0C. A high pressure Heat Transfer Fluid (HTF) is circulated through the preconditioning system.

The HTF is pumped by the HTF circulation pumps through the HTF

Heater and then through the HTF cooler. A bypass around the cooler is controlled by the Molten Sulphur temperature the cooler is controlled by the molten sulphur temperature leaving the Sulphur pre-conditioners. The HTF proceeds to Sulphur pre-conditioners where it heats or cools the molten sulphur as is required, the HTF exits Sulphur pre-conditioners and proceeds to HTF circulation pumps, thus closing the cycle. Expansion Vessel takes up any changes in volume in the HFT system due to temperature changes.


Molten Sulphur proceeds to the sulphur Former where it enters in the rotoformer which drops molten sulphur into a rotating stainless steel belt. The belt transports the sulphur pellets across a cooling section where the sulphur solidifies and cools. Cooling water is sprayed to the opposite (bottom) side of the belt providing the heat rink required for solidifying and cooling the sulphur pellets. Cooling water returns to the sewer system and serves as cooling water blow down for the Hazira Cooling Water System. The pastilles proceed to the Sulphur Pellets conveyor which transports them to a Bagging Hopper. The sulphur pellets are automatically fed into 25 kg. Sulphur bags weighted and then transported to a sewing machine which sews shut the sulphur bags. The bags are subsequently transported to a storage area.

CHEMICAL REQUIREMENTS Chemical makeup is normally required in order to maintain the Lo-Cat

solution at its most desirable chemical composition. The Lo-Cat process uses the following make up Chemicals.

ARI - 310M ARI - 300 KOH Surfactant ARI - 600 Biochem ARI - 400 NALCO DEFOAMER

The addition of these chemicals on a regular basis has been provided for

the process design. However, chemical addition should be governed by the chemical composition of the circulating Lo-Cat Solution.

A no-flow switch warns operators when the flow of ARI-310 to the

Chemical supply header is interrupted. The dosing pump rate is manually adjustable to control chemical

addition. A graduated level gauge on 61-T-605 is used to verify the rate of chemical addition.


SURFACTANT The sulphur particles sometimes agglomerate and entrap air bubbles.

Dosage of 10 ppm per day of surfactant is ordinarily sufficient to provide adequate settling if the system is free of hydrocarbons. Larger does are required if oil or other organics are absorbed in the circulating solution. ARI 600 Surfactant, a special low foam composition, is the surfactant used.

Surfactant dosing pumps transfers Surfactant from surfactant Tank to

the Chemical Header at the rate of 0.21 T/hr. Surfactant Tank provides about 7 weeks supply of chemical. A no-flow switch warns operators when the flow of surfactant to the chemical supply header is interrupted. The Dosing pump rate is manually adjustable to control chemical addition. A graduated level gauge on surfactant Tank is used to verify the rate of chemical addition.

BIOCHEM Biochem is required to prevent biological degradation of the catalyst

solution. Very small dosages of 10 ppm per day are usually adequate to suppress biological oxidation. ARI-400 Biochem, which serves as a bacterial growth inhibitor, is the recommended Biochem for this application.

Biochem Dosing Pumps transfers Biochem from Biochem Tank to the

Chemical Header. At the rate of 0.23 liters/hr. Biochem Tank provides about 7 weeks supply of Chemicals.

DEFOAMER Foaming can sometimes occur within the absorber/oxidiser. Both the

surfactant and biochem have a tendency to cause foaming if used in excess as do some organic materials contained in the process stream. In the event foaming occurs, Deformer would be injected directly into the absorber/oxidizer in to 1 liter dosages. The recommended deformer is NALCO 5740 which is air blown into surge tank.


LPG RECOVERY UNIT PROCESS OBJECTIVES:-

Production of LPG, NGL, LP lean gas and Propane from a part of sweet gas from outlet of GSU and all sweet condensate from DPD.

MAJOR OPERATIONS:-

Separation of lean gas and liquid, Production of LP lean gas from LEF column Production of LPG & NGL from LPG column, Production of propane by distillation of a part of LPG.

HOW IT DONE?

A part of sweet gas from outlet of GSU and all sweet condensate from

DPD are taken as feed to LPG recovery unit. It is cryogenic process. First dried in molecular sieve dryers and then chilled in cold Box to -30 0C. The cold box comprise of a number of incoming and outgoing streams exchanging heat with each other. The chilled fluid is then taken to separator-1 for separation of liquid and gas. The chilled vapors from the top of the separator-1 is expand isentropically in turbo expander wherein temperature of fluid is falls to -57 0C. The fluid is again separated in separator-2. The cold lean gas passes through cold box again and feed to gas cooler for precooling of the incoming gas and compressed by the compressor of turbo expander in Compressor system. The lean gas is than further compressed through lean gas compressor as per requirement of downstream consumers. The liquid thus separated in separator-1 and -2 is taken out, level and flow controlled and feed to light and fractionation column operating at about 28 Kg/cm2 pressure and -2 to 110 0C temperatures. DPD condensate is received in surge drum and directly feed to LEF column via liquid dryers. Lighter HCs are fractionated and remove from the top of the LEF column. This low pressure gases expand in LEF overhead turbo-expander and it gets cooled and then being heated by passing through cold box LP. Gas is also used for supplies as LP lean gas under pressure control. The rest of the gas compressors and same are fed back to high pressure lean gas header. Liquid from the bottom of the LEF column is then feed to LPG column operated under level and flow control. It is operated at about 11 Kg/cm2 pressure and 61 to 156 0C temperatures. LPG is taken out from the top and NGL is removed from the bottom. The products coming out from the distillation column are sent to storage under level control. A part of the LPG is further distillate to obtain propane which is used as a refrigerant in LPG and DPD units.


PROCESS DESCRIPTION

LPG Recovery Plant is designed to process 5 MMSCMD of sweet gas. The condensate associated with the gas generated in Dew Point Depression Unit (DPD) is also processed in LPG Recovery Plant.

Feed gas from gas sweetening unit available at a pressure range of 62

kg/cm2 and a temperature of around 360C flows to a Knock-Out Drum where any liquid present in the gas is knocked-off. Bulk of the water is removed from the gas by cooling it up to 250C. Further the gas flows through molecular sieve dryer where the moisture is reduced to 1 ppm level. Next the dried gas is cooled isobarically to -300C in a chiller and the condensed liquid is separated out in Seperator-1. Vapors from this separator are expanded almost isentropically in an expander, as a result of which the temperature falls to -540C. Liquid condensed on expansion cooling is separated out in Seperator-2. The refrigeration of the vapor stream from Seperator-2 is recovered to cool down the feed gas stream. Then this lean gas is compressed by Expander-Compressor to about 37 kg/cm2a and finally to 48.5 kg/cm2 a by the lean gas compressor and supplied to consumers as high pressure lean gas. Condensate from the DPD unit available at 60 kg/cm2 is flashed into surge drum after heating to avoid hydrate formation. The condensate is passed through a coalescer, where most of the free water is separated out. The hydrocarbon liquid from coalescer flows to liquid dryers where the moisture content is brought to 5ppm.

The liquid from separator-1 &2 along with the condensate from liquid

dryer outlet is routed to light end fractionators (LEF) column. The light hydrocarbons (a part of propane and lighters) are removed from top of the column. These light end hydrocarbons are expanded in LEF overhead expander and the refrigeration recovered by cooling the feed gas stream in cold box.

LEF overhead gases from the cold box is compressed to supply to

consumer as low pressure lean gas and also used for internal fuel gas consumption. Excess gas is compressed by residue gas compressor to high pressure lean gas header. Liquid from the bottom of LEF column is routed to LPG Recovery column. LPG is withdrawn from this column as overhead product and sent to storage. The bottom product, ARN is also sent to storage.

Propane, generated by fractionating small part of LPG product in propane column, refrigeration is used to supplement the total refrigeration requirements. A central flare and utility system is provided for the entire complex which will cater to the LPG Recovery Plant also.


STORAGE:

Liquid and gaseous products must be stored during intervals between production,

transportation, refining , blending and marketing. The objective of storage at each of these stages is

firstly to supply a sufficient balance of each stock to ensure continuity of operation and secondly to

ensure that the product is conserved and maintained at an acceptable level of quality.

Various storage equipments are:

1. Horton spheres These are spherical tanks used for storage of gases that are under pressure. It is used to store LPG and Propane.

2. Floating Roof Tank These type of tank are used to store liquids that are volatile in nature e.g. petroleum products

3. Fixed Roof tanks - These are used for storage of non volatile liquids.

The products are sent to the various storage tanks and spheres

Products Capacity Storage

LPG 225000 m3 Horton Spheres (9 nos.)

ARN 66000 m3 Floating Roof Tanks (4 nos.)

NGL 66000 m3 Floating Roof Tanks (4 nos.)

SKO 25000 m3 Floating Roof Tanks (5 nos.)

HSD 1000 m3 Fixed Roof Tanks (2 nos.)

Propane 311 m3 Horton Sphere

PRODUCT TERMINAL:

At product terminal, all the products which are produced within the plant are loaded off to

different consumers, either through rail, road, pipelines or sea routes.

Product Production Specification Mode of transport

Consumers Rail Road Pipeline ships

LPG 3500kL/day Sp.

Density=0.53 IOC,BPCL

Naptha 5500 kL/day Reliance,

UAE,

Singapore

Superior

kerosene oil 600kL/day IOCL

Aviation

turbine fuel 600 kL/day

High speed

diesel 60-75 kL/day ONGC

Propane IOCL,ONGC


CO-GEN, OFFSITE AND UTILITIES:

CO-GEN:

The electricity requirements of the Hazira plant are met through an in-house electricity generation system without depending upon an external source. The Co- generation plant is used for this purpose. Apart from generation of electricity the plant also undertakes the generation and distribution of HP and LP steam throughout the plant wherever required.

The main feed for the generation of electricity is the LP gas generated

within the plant. A gas turbine system has been put in place to utilize this gas, with a daily usage of 0.7- 0.8 MMT. Initially, the gas is compressed and then it is sent to a combustion chamber, after which it is used in gas turbine through which electricity is generated. The exhaust gases coming from the gas turbine are used for heating up water in a boiler. Whenever heating is not required, a special flap is there, which is opened so that the exhaust is released into the atmosphere. Special arrangements are made to ensure continuous flow of water. The steam generated is utilized in the main generator.

The DM plant takes raw water, which is then dematerialized to

generate steam. Exhaust gas is used in two stages - HP and LP, with HP steam generating and then LP steam. Then it goes to economizer and from there it goes to exhaust line and is exhausted into the atmosphere.

The whole system has 3 plants of 20 MW capacities, of which two are

running at present. Of the power generated, 30 MW is utilized by the Hazira plant. Rest 10MW is given to other customers. No steam turbine is there, so whatever the steam is generated; it is supplied to the Hazira plant for further use.

A Combined cycle efficiency of about 55% is achieved by this process.

The whole of co-generation unit is controlled and monitored through the control room where special panels are installed ( mfg.GE industrial and power system) which shows real time operations going on and thus serves ease of use and operation.


OFFSITE:

Apart from the major process units described above, Hazira plant also has offsite facilities spread over a wide area where the various products obtained from the processing facilities are stored temporarily.

Storage of LPG is

done in LPG spheres, which are large spherical storage tanks, divided into two phases, consisting of six and three spheres in first and second phase, respectively. The design capacity of the tanks is 2500 m3, with a safe filling capacity of 2100 m3. Presently, however these tanks are being used for 1200 m3 of storage. A pressure of about 8.5 kg/ cm2 is maintained.

The

LPG from here is transferred to tankers, which are shipped to different locations either through road or rail. Ethyl mercaptane, which is used for the detection of leakages, is mixed with LPG here only, so that any leakage further down line can be identified easily.

LPG is also transported to nearby consumers like IOCL, BPCL etc. Similarly, there are six storage tanks for kerosene, each with a capacity of 50,000 m3, two tanks for ATF, with 5000 m3 storage and three tanks for storing HSD, with the same capacity.


UTILITIES:

Utilities are the services which are essential for the operation of the plant, though these may not contribute directly towards the revenue generated. The major utility systems the plant has included:

Air system Inert gas system Emergency Preparedness Cogeneration and steam systems Effluent treatment and disposal plant Fuel gas network Water system

Raw water treatment plant Fire water pump house Cooling water system DM water system

I/G Plant

Air is used in many places within the plant. Inert gas systems are used for purging to ensure hydrocarbon/air Free State during shutdown and start-up activities. Inert gas is prepared from the

Atmosphere at the inert gas plant through the PSA (pressure swing

adsorption), in which the air is passed through carbon molecular sieves, which have the granules of a special compound which adsorbs N2 at the surface, and relieves O2, when under pressure. The container is then depressurized so that the entrapped nitrogen escapes which is then delivered to appropriate location. Nitrogen is used for regular processes in KRO (as sealing medium in certain pumps)

Two towers work in conjugation, one working under adsorption mode and the

other in regeneration mode. The requirement of nitrogen is approximately 400m3/hr. Instrument air is utilized in automatic plants, for use by instruments, so it has

to be free from any kind of moisture. Plant air, which may have some moisture is used in SRU plant.


RAW WATER TREATMENT PLANT

Another important utility system is the water system. Water is utilized in almost all the units. Tapti River, the source being about 30-40 km from the Plant, through a weir designed to ensure continuous supply of water. The water is then kept into reservoirs at the plant, in which it is allowed to settle, and then is pumped out to various locations. The total consumption of water at the plant is about 20,000 kl/day.

The water is used as service water for plant usage, and as make up water in

cooling towers (to counter evaporation losses etc.) Drinking water is also supplied after adequate treatment, not only to the plant

but also to nearby villages for social obligation and to nearby ONGC residential colony. Cooling water and service water lines are spread throughout the plant as sea

green pipelines. Red lines are for firefighting systems. Raw water systems have an operating capacity of about 2000 m3/hr.(5 pumps

x 750 m3/hr, 2 standby).


Conclusion

The industrial training at ONGC, Hazira has been a very good learning experience for me. The knowledge of theoretical subject I not enough for any engineering stream. One has to have the practical knowledge to remove the gap between the actual and expected performance.

Training helped me to know and develop various technical and communication skills. It also gives us a lot of knowledge about the process, its equipments and operational phases. The training is an important step towards us becoming successful engineers. The most important lesson that I have learned is discipline, management and cooperation

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