abdul hadi chara internship report

INTERNSHIP

REPORT SUBMITTED BY: ABDUL HADI CHARA

MOL PAKISTAN OIL & S Co. B.V.

MANZALAI CPF

SUMMER INTERNSHIP REPORT 2016

1 MOL PAKISTAN OIL & GAS Co. B.V. MANZALAI CPF

Contents 1. ACKNOWLEDGEMENT ........................................................................................................................... 6

2. ABSTRACT .............................................................................................................................................. 7

3. INTRODUCTION ..................................................................................................................................... 8

4. HEALTH AND SAFETY INDUCTION ......................................................................................................... 9

4.1 PPE: ............................................................................................................................................... 9

4.2 WORK PERMIT POLICY: ................................................................................................................. 9

4.3 FIRE PROTECTION SYSTEMS .......................................................................................................... 9

5. WELL HEADS AND VALVE ASSEMBLIES ............................................................................................... 10

5.1 CHRISTMAS TREE: ....................................................................................................................... 10

5.1.1 SUB SURFACE SAFETY VALVE (SSSV) ................................................................................... 10

5.1.2 SURFACE SAFETY VALVE ...................................................................................................... 10

5.1.3 MASTER VALVES .................................................................................................................. 11

5.1.4 KILL VALVE ........................................................................................................................... 11

5.1.5 SWAB VALVE ....................................................................................................................... 11

5.1.6 PRODUCTION VALVE ........................................................................................................... 11

5.2 CHOKE MANIFOLD ...................................................................................................................... 11

5.3 CORROSION INHIBITOR INJECTION ............................................................................................. 11

5.4 METHANOL INJECTION PACKAGE: .............................................................................................. 12

5.5 GAS SCRUBBER: ........................................................................................................................... 12

5.6 HIPPS (HIGH INTEGRATED PRESSURE PROTECTION SYSTEM) .................................................... 12

5.7 PIPE INSTALLATION GAUGE (PIG) LAUNCHER ............................................................................. 12

6. CPF PROCESS ....................................................................................................................................... 13

6.1 PIG RECEIVER .............................................................................................................................. 14

6.2 SLUG CATCHER ............................................................................................................................ 14

6.3 GAS PROCESSING ........................................................................................................................ 15

6.3.1 SEPARATION ........................................................................................................................ 17

6.3.1.1 INLET SEPARATOR ........................................................................................................... 17

6.3.1.2 MERCURY REMOVAL UNIT .............................................................................................. 17

6.3.2 DEHYDRATION ..................................................................................................................... 18

6.3.2.1 REASONS FOR DEHYDRATION OF GAS ............................................................................ 18

6.3.2.2 WHY USING TEG FOR DEHYDRATION? ............................................................................ 18

6.3.2.3 TEG CONTACTOR ............................................................................................................. 18



6.3.2.4 TEG REGENRATION UNIT ................................................................................................ 18

6.3.2.5 GLYCOL FLASH TANK ....................................................................................................... 19

6.3.2.6 PARTICULATE FILTER ....................................................................................................... 19

6.3.2.7 CHARCOAL FILTER ........................................................................................................... 20

6.3.2.8 GLYCOL/GLYCOL EXCHANGER ......................................................................................... 20

6.3.2.9 STILL COLUMN................................................................................................................. 20

6.3.2.10 GLYCOL REBOILER ....................................................................................................... 20

6.3.2.11 STRIPPING COLUMN.................................................................................................... 20

6.3.2.12 ACCUMULATOR ........................................................................................................... 21

6.3.2.13 TEG RECIRCULATION PUMPS ...................................................................................... 21

6.3.2.14 COALESCING FILTER .................................................................................................... 21

6.3.3 HYDROCARBON DEW POINT CONTROL UNIT ..................................................................... 21

6.3.3.1 BRAZED ALUMINIUM HEAT EXCHANGER (BAHE): .......................................................... 22

6.3.3.2 COLD SEPARATOR ........................................................................................................... 23

6.3.3.3 JOULE THOMPSON VALVE ............................................................................................... 23

6.3.3.4 LOW TEMPERATURE SEPARATOR ................................................................................... 23

6.3.3.5 BTAX UNIT ....................................................................................................................... 24

6.3.3.6 SALES GAS BOOSTER COMPRESSORS .............................................................................. 24

6.3.3.7 SALE GAS METERING SKID ............................................................................................... 25

6.3.3.8 MOISTURE ANALYSER ..................................................................................................... 25

6.3.3.9 GAS CHROMATOGRAPH (GC) .......................................................................................... 25

6.3.3.10 METERING PCV ............................................................................................................ 25

6.3.3.11 SHUT DOWN VALVE (SDV) .......................................................................................... 26

6.4 CONDENSATE PROCESSING ......................................................................................................... 26

6.4.1 CONDENSATE STABILIZATION UNIT: .................................................................................. 26

6.4.2 FLASH SEPARATOR .............................................................................................................. 27

6.4.3 FLASH GAS COMPRESSOR (FGC) ......................................................................................... 27

6.4.4 FEED BOTTOM HEAT EXCHANGER (FBHE) .......................................................................... 28

6.4.5 CONDENSATE STABILIZATION TOWER ................................................................................ 28

6.4.6 CONDENSATE STABILIZED OVERHEAD (CSO) COMPRESSORS............................................. 28

6.4.7 STABILIZER REBOILER .......................................................................................................... 29

6.4.8 PRODUCT COOLER .............................................................................................................. 29

6.4.9 STORAGE TANKS ................................................................................................................. 29



6.5 PRODUCED WATER PROCESSING ............................................................................................... 30

6.5.1 WATER DEGASSING BOOT .................................................................................................. 31

6.5.2 CORRUGATE PLATE INTERPHASE (CPI) SEPARATORS ......................................................... 31

6.5.3 EVAPORATION PONDS ....................................................................................................... 32

7. MGPF PROCESS ................................................................................................................................... 32

7.1 SEPARATION OF FLUIDS .............................................................................................................. 32

7.1.1 INLET OIL TRUNK LINE HEATER ........................................................................................... 33

7.1.2 INLET SLUG CATCHER (OIL) ................................................................................................. 33

7.1.3 INLET SLUG CATCHER (GAS) ................................................................................................ 33

7.1.4 RAW GAS HEATER ............................................................................................................... 34

7.2 GAS PROCESSING ........................................................................................................................ 35

7.2.1 PRESSURE REDUCTION SECTION ......................................................................................... 35

7.2.2 INLET GAS SEPARATOR ........................................................................................................ 35

7.2.3 FEED/SALES GAS HEAT EXCHANGER ................................................................................... 35

7.2.4 MERCURY REMOVAL VESSEL .............................................................................................. 35

7.2.5 DEHYDRATION COALESCER: ................................................................................................ 36

7.2.6 DEHYDRATION PACKAGE: ................................................................................................... 36

7.2.7 HCDP CONTROL UNIT J-T VALVE / TURBO EXPANDER & DE-ETHANIZER ........................... 37

7.2.8 GAS/GAS HEAT EXCHANGER ............................................................................................... 37

7.2.9 COLD SEPARATOR ............................................................................................................... 37

7.2.10 TURBO EXPANDER / COMPRESSOR .................................................................................... 37

7.2.11 JT VALVE .............................................................................................................................. 38

7.2.12 SALES GAS HEATER .............................................................................................................. 38

7.2.13 SALES METERING SKID ........................................................................................................ 38

7.3 LPG PROCESSING ......................................................................................................................... 38

7.3.1 DE-ETHANIZER TOWER........................................................................................................ 38

7.3.2 REFLUX CONDENSER ........................................................................................................... 39

7.3.3 SIDE RE-BOILER ................................................................................................................... 39

7.3.4 TRIM RE-BOILER .................................................................................................................. 39

7.3.5 METHANOL INJECTION PUMP ............................................................................................. 39

7.3.6 DE-BUTANIZER .................................................................................................................... 39

7.4 OIL PROCESSING .......................................................................................................................... 40

7.4.1 OIL STABILIZATION UNIT ..................................................................................................... 40



7.4.2 OIL FILTERS .......................................................................................................................... 40

7.4.3 OIL FEED DRUM OF TRAIN-1 ............................................................................................... 41

7.4.4 OIL STABILIZATION FEED/PRODUCT EXCHANGER .............................................................. 41

7.4.5 OIL STABILIZATION HOT OIL EXCHANGER ........................................................................... 41

7.4.6 OIL STABILIZATION LOW PRESSURE SEPARATOR ................................................................ 41

7.4.7 OIL STABILIZATION OVERHEAD COMPRESSORS ................................................................. 42

7.4.8 OIL STABILIZATION OVERHEAD COMPRESSOR LIQUID VESSEL ........................................... 42

7.4.9 OIL STABILIZATION OVERHEAD COMPRESSOR LIQUID PUMPS .......................................... 42

7.5 CONDENSATE PROCESSING ........................................................................................................ 42

7.5.1 CONDENSATE STABILIZATION UNIT .................................................................................... 42

7.5.2 CONDENSATE FILTERS ......................................................................................................... 42

7.5.3 CONDENSATE STABILIZER FEED DRUM ............................................................................... 43

7.5.4 LIQUID-LIQUID COALESCER ................................................................................................. 43

7.5.5 CONDENSATE STABILIZER ................................................................................................... 43

7.6.6 CONDENSATE STABILIZER REBOILER ................................................................................... 43

7.7.7 STABILIZATION GAS COMPRESSORS ................................................................................... 44

8. UTILITIES .............................................................................................................................................. 44

8.1 FIRE WATER SYSTEM ................................................................................................................... 44

8.2 SLOP VESSEL ................................................................................................................................ 44

8.3 DECANTING VESSEL ..................................................................................................................... 44

8.4 FUEL GAS SYSTEM ....................................................................................................................... 44

8.5 HOT OIL SETUP ................................................................................................................................ 45

8.6 INSTRUMENT AIR SYSTEM ......................................................................................................... 45

8.7 NITROGEN GENERATION UNIT: ................................................................................................... 46

8.8 FLARE SYSTEM ............................................................................................................................. 47

8.9 FIRE AND GAS SYSTEM ................................................................................................................ 47

9. LOADING POINT .................................................................................................................................. 47

9.1 STABILIZED OIL STORAGE & LOADING SYSTEM .......................................................................... 47

9.2 LPG STORAGE LOADING SYSTEM ................................................................................................ 48

10. REVERSE OSMOSIS PLANT ............................................................................................................... 48

10.1 INTRODUCTION ........................................................................................................................... 48

10.2.1 AERATION BASIN ................................................................................................................. 49

10.2.2 ANTHRACITE FILTERS .......................................................................................................... 49



10.2.3 ACTIVATED CARBON FILTER ................................................................................................ 49

10.2.4 ULTRA FILTRATION .............................................................................................................. 50

10.3 POST TREATMENT ....................................................................................................................... 50

10.3.1 CARTRIDGE FILTER .............................................................................................................. 50

10.3.2 REVERSE OSMOSIS .............................................................................................................. 50

10.3.3 RO MEMBRANES ................................................................................................................. 50

11. PLANT SHUTDOWN LEVELS ............................................................................................................. 52

11.1 LEVEL I OVERALL SHUTDOWN OF FACILITY WITH BLOWDOWN ................................................ 52

11.2 PLANT SHUTDOWN (PSD) WITHOUT BLOWDOWN ........................................................................ 52

12. ASSIGNMENTS DURING INTERNSHIP .............................................................................................. 52

12.1 DIFFERENCE BETWEEN CENTRIFUGAL COMPRESSORS AND PD COMPRESSORS ....................... 52

12.2 DIFFERENCE BETWEEN CENTRIFUGAL COMPRESSORS AND CENTRIFUGAL PUMPS ................. 53

12.3 RICH BURN AND LEAN BURN ENGINES ....................................................................................... 54

12.3.1 LEAN BURN ENGINES .......................................................................................................... 54

12.3.2 RICH BURN ENGINES .......................................................................................................... 55

12.4 A COMPLETE ANALYSIS OF THE HVAC SYSTEM ............................................................................... 55

12.4.1 WATER-LITHIUM BROMIDE VAPOR ABSORPTION REFRIGERATION SYSTEM ......................... 55

12.4.2 SPECIAL FEATURES OF WATER-LITHIUM BROMIDE SOLUTION .............................................. 56

12.1.3 COMPONENTS ......................................................................................................................... 56

12.4.3.1 GENERATOR ................................................................................................................ 56

12.4.3.2 CONDENSER ................................................................................................................ 56

12.4.3.3 EVAPORATOR .............................................................................................................. 57

12.4.3.4 ABSORBER ................................................................................................................... 57

12.4.3.5 BOILERS ....................................................................................................................... 57

12.4.3.6 COOLING TOWER ........................................................................................................ 57

12.4.3.7 INTERMEDIATE SOLUTION PUMP ............................................................................... 59



1. ACKNOWLEDGEMENT

At first I would like to thank the Almighty for giving me the opportunity to work at a reputable

multinational company like MOL Pakistan, under the guidance of highly talented and

knowledgeable individuals.

I would like to thank the entire process department who have made my stay at the Central

Processing Facility a learning treat. It would not have been possible without the constant help

and supervision of Mr Asif Rasheed, Mr Bilal Khan and Ms Rida Altaf to name a few. Not to

forget the technicians, who despite of their hectic schedule never refused for an onsite visit and

were always willing to deal with my constant question and answer sessions. The knowledge

that the respected engineers and operators have showered, has given my career motivation a

kick start.

All in all, it has been a once in a life time experience; Wherever I go, I can proudly claim that I

was a part of Mol Pakistan.

Thankyou.

Abdul Hadi Chara

Process Intern



2. ABSTRACT

The aim of this report is to state the activities that I performed during my 30-day internship at

Mol Pakistan Karak Facility. This report is a compilation of the information that I have managed

to gather during my stay. It covers an extensive description of the process facilities at CPF and

MGPF and a brief overview of our short stay at the Warehouse, Health and Safety Department

and the Work Permit Office.

This report also has an analysis on the Reverse Osmosis plant installed at the facility. Internship

at MGP has really helped me to apply my theory to the practical applications and this report will

try to cover all the experience which I gained here at the facility.



3. INTRODUCTION

MOL, the leading Hungarian Oil and Gas Exploration and Production Company has been

working in Pakistan through its subsidiary MOL Pakistan Oil and gas Company B.V. in different

joint ventures since April 1999. TAL is a joint venture of MOL, PPL, OGDCL, POL and GHPL, MOL

is the operator in this joint venture. There are three plant of MOL Pakistan working, At Karak,

Makori (not operational) and Gurguri.

There are four reservoirs of MOL Pakistan from where feed is coming Makori East, Maramzai,

Manzalai, and Mamikhel. MOL Pakistan is blessed with sweet gas i.e. free from H2S and

mercury, which removes many complications and makes the process extremely easy. The three

phases i.e Gas, Water and Condensate are separated by passing them through various vessels.

Most of the separation here in Karak plant is density based separation. The gas is sold to Sui

Northern Gas Private Limited (SNGPL), condensate to Attock Oil Refinery (ARL) and water is

evaporated in the evaporation ponds. Different numbers of wells are operating in each

reservoir. The feed from all reservoirs is assembled in valve assemblies. This feed from valve

assemblies is forwarded to the processing facilities.

MGPF (Makori Gas Processing facility) is slightly different from CPF. There are two products

other than gas, condensate, and water. These products are LPG (Liquefied petroleum Gas)

and crude oil. LPG is stored in the LPG bullets and sold in tons for consumer use. While

crude oil is stored in the storage tanks and sold in barrels to refineries for further processing.



4. HEALTH AND SAFETY INDUCTION

HSE abbreviates for Health, Safety and Environment. Safety should be our first priority while

working on the field. MOL Pakistan really cares about its employees and it has established some

safety rules and regulations, which must be followed by every employee while doing their jobs.

MOL Pakistan has an HSE department, which make sure that every activity on the field do not

jeopardize anybody’s health and do not pollute the environment. Every now and then, HSE

team holds various training sessions about safety and behavior

Whenever an employee joins the field, the HSE officer gives a brief presentation about the rules

and regulations on the field. The HSE orientation shown to us, consisted of various safety

policies and equipment. I was familiarized with PPE policy, work permit policy, smoking policy,

fire hazards and drugs policy etc. We also watched a video, in which importance of work permit

was emphasized. This video was related to an incident that occurred in Sharjah. Following are

the brief explanations of the important safety equipment:

4.1 PPE: PPE i.e. Personal Protective Equipment. PPE includes hard cover-all, helmets, ear

plugs, gloves, goggles, safety shoes, masks. HSE has strict policy about this equipment. The

Coverall, helmet and safety shoes are essential, while other equipment may be used as per

requirement.

4.2 WORK PERMIT POLICY: It is simply, a permit that allow an employee to perform any

job on field. Before performing any activity e.g. preventive maintenance, corrective

maintenance etc. on plant area, work permit must be issued. This makes sure, it is safe to

perform the job

4.3 FIRE PROTECTION SYSTEMS: The main hazard in any oil and gas company is that of

fire and explosions. Measures have been taken for prevention. Fire protection includes hand

portable fire extinguishers, wheeled extinguishers, fire water and fire hydrant systems, fire

pumps, sprinkler systems and foam application systems. Foam protection system is provided to

all atmospheric storage tanks containing flammable or combustible liquids e.g. condensate

storage tank is covered with foam



5. WELL HEADS AND VALVE ASSEMBLIES

Well head has a large valve assembly that is used for controlling the natural pressure of gas that

is being extracted. The primary purpose of the wellheads is to provide the suspension point and

pressure seal for the casing strings that run from the bottom of the whole section to the surface

through pressure controlled equipment.

5.1 CHRISTMAS TREE:

Christmas tree has tree type structure with valves

arranged on it. Those valves are:

1. Sub Surface Safety Valve (SSSV)

2. Surface safety Valve (SSV)

3. Master valve

4. Kill wing valve

5. Swab valve

6. Production Valve

5.1.1 SUB SURFACE SAFETY VALVE (SSSV)

It is located underground in the gas pipe line below the Christmas tree Surface safety valve

(SSV). It is a hydraulically actuated fail-safe gate valve for producing or testing oil and gas

wells with high flow rates, high pressures, or the presence of H2S. The SSSV is used to

quickly shut down the well choke manifold upstream in the event of overpressure, failure, a

leak in downstream equipment, or any other well emergency requiring an immediate shut

down. SSV is remotely operated by an emergency shutdown device (ESD), which can be

triggered automatically by high or low pressure pilot actuators.

5.1.2 SURFACE SAFETY VALVE

Surface safety valve (SSV) is a hydraulically actuated fail-safe gate valve for producing or

testing oil and gas wells with high flow rates, high pressures, or the presence of H2S. The

SSV is used to quickly shut down the well choke manifold upstream in the event of

overpressure, failure, a leak in downstream equipment, or any other well emergency

requiring an immediate shut down.



5.1.3 MASTER VALVES

They are used to control flow of gas from the well. It is a manual valve having same

purpose of SSV. There are two master valves on a tree. The upper master valve is used on

a routine basis, with the lower master valve providing backup or contingency function in the

event that the normal service valve is leaking and needs replacement. Typically, the lower

master valve is manually operated type and upper master valve is actuated type.

5.1.4 KILL VALVE

It is present on the wing of Christmas tree. It is used to kill the well for different purposes: To

stop a well from flowing or having the ability to flow into the wellbore.

5.1.5 SWAB VALVE

Swab valve located at the top of the tree and is used for sub surface jobs of the wells.

5.1.6 PRODUCTION VALVE:

It is used to supply gas from well to the choke manifold and hence to the gas plant.

5.2 CHOKE MANIFOLD

Gas from the production valve of Christmas tree comes choke manifold. Choke manifold is

used to drop the pressure of the gas and condensate coming from the well. Choke manifold

consists of two types of choke valves:

Fixed choke keeps a constant flow across it and is isolated by ball valves while an auto

choke can be adjusted according to requirement and it is isolated by pressure safety valves

which are operated from central control room (CCR).

5.3 CORROSION INHIBITOR INJECTION

Corrosion inhibitors have to be injected in the upstream choke valves in order to prevent

corrosion in the flow pipelines. The equipment required for the injection includes a corrosion

inhibitor storage tank, sufficient control instrumentation and a corrosion inhibitor injection

pump driven on gas.



5.4 METHANOL INJECTION PACKAGE:

Due to a great pressure drop in the choke manifold, hydrates are formed in the lines.

Hydrate crystals restrict gas flow. Hydrates can plug valves, meters, instruments, and flow

lines upsetting or even shutting down processes. Therefore, Methanol is injected upstream of

choke valves and is circulated in the gas lines to inhibit hydrate formation. Methanol

decreases the freezing temperature of hydrates hence the crystal structure is broken and the

hydrates are removed from the gas lines.

5.5 GAS SCRUBBER:

Gas scrubber is used to produce the instrument gas that is required to operate different

instruments located at well head. Gas is scrubbed from the same gas line that is transferred

from choke manifold to the plant area.

5.6 HIPPS (HIGH INTEGRATED PRESSURE PROTECTION SYSTEM)

This system consists of three PITs (Pressure Indicator & Transmitter) on the downstream of

the production and serves as a safety precaution tripping and shutting the wellhead in case

the downstream pressure changes. They are operated in a ratio of 2:3. This means that if

pressure in any two PITs is above or below the set point pressure, then HIPPS will trip that

line.

5.7 PIPE INSTALLATION GAUGE (PIG) LAUNCHER:

Pig launcher is used to launch pig in the gas line coming to plant. Purpose of pig is to flush

off materials from the entire line. A pig is introduced into the line via a pig launcher and is

received by a pig launcher at the other end of line. Purpose of the pig is to remove all the

materials from the pipe line. The pipe may contain dust or other substances which are taken

away by pig and are received in the pig receiver.



6. CPF PROCESS

First of all phase separation of feed takes place in which gas, condensate and water are

separated on the basis of density differences between them in the slug catcher. After that gas is

routed to the Inlet separator and then to Gas Dehydration Unit where the moisture contents

are reduced from gas as per requirements of SNGPL. This dehydrated gas is then routed to

HCDP Unit where the hydrocarbon contents of Gas are controlled as per requirements of

SNGPL. This gas is then routed to Sales Gas Booster Compressor and Metering Skid and is then

finally dispatched to SNGPL.

The condensate after phase separation is introduced to the condensate stabilization unit where

the RVP of condensate is maintained and the condensate is stabilized. This stabilized

condensate then flows to the storage tanks. The condensate loading department then

dispatches this condensate in bowsers to ARL.

SALES GAS SPECIFICATIONS

WATER CONTENT Not more than 7 llb/MMSCFD

DEW POINT 32 F

CALORFIC VALUE Not less than 1000 BTU

PRESSURE More than SNGPL line

OXYGEN Not more than 1 %

NITROGEN Not more than 5 %

The produced water after phase separation is then introduced to Water Treatment Unit where

degassing of water and corrugated plate interception occurs and the produced water is then

introduced to Evaporation Ponds via centrifugal pumps.



6.1 PIG RECEIVER

The pig receiver is an enlarged part of the trunk

line at the plant area. Both, the MMK & Manzalai

trunk lines have the Pig receiver connected to

them at CPF. Pig receiver is used to take out the

pig, launched from wellheads by means of pig

launcher, to scrap any hydrates etc in the flow

lines. Piping and valve adjustment is made so that,

the pig cannot enter the slug catcher, and is

directed to pig receiver. The pig receiver is then

isolated from running line through valves and is depressurized to flare. The pig is taken out by

opening the end cover of the receiver. Now again the receiver is ready to receive another pig.

6.2 SLUG CATCHER

Feed (consisting gas, condensate, water) from wellheads and valve gathering assemblies are

introduced to a finger type 3 phase Slug Catcher which is basically a 3-phase separation unit.

It has two main purposes:

To store the slug/ raw material, maintain. Constant down flow and be able to hold the

high pressure flow

To separate the different components in the raw products, on basis of specific

gravity/density.

In slug catcher, the separation of the feed occurs on the basis of density difference between

water, condensate and gas. The specific gravity of water is 1 while that of condensate is 0.76.

Water being the heaviest among the three settles down at bottom followed by condensate

while gas being the lightest rises above.

Slug catcher has 5 manifolds:

1. Distribution manifold

2. Gas Manifold

3. Condensate Manifold



4. Water Manifold

5. Inter-phase Manifold

Slug is a multicomponent mixture

with varying velocity.

There are 3 types of slugs:

Pigging Slug

Terrain Slug

Hydrodynamic Slug

Here it meets a deflector plate,

which changes its direction and

momentum. Some of the separation takes place due to change in direction. It consists of mist

extractors to remove any mists and a vortex breaker to prevent formation of low pressure at

the bottom. Level adjustment and control is regulated by the LCVs, present at each train of

condensate and produced water. Slug catcher provides enough settling time for effective

separation. The primary function of the dry gas risers is to deliver dry gas back into the system.

As some secondary separation occurs here, their sizing is important. The storage harps hold the

liquids and secondary separation occurs here. The liquid and sludge manifolds provide

separation of the water, oil and debris. The oil and water are then removed from the storage

end for further processing (oil) or reinjection (water).

The debris is cleaned out on an as needed basis. To equalize the pressure on both ends of Slug

Cather, a pressure balancing line is provided along the top side. This connects the high pressure

gas boot with the low pressure side, the liquid phase side, from top. Designed pressure of CPF

slug catcher is 1785 psi. However, the slug enters the slug catcher at a pressure of 1500psi and

almost about 115F. All three streams, gas, condensate & water have dual trains, which are run

as per flow requirement. Each gas processing train has capacity of 150 MMSCFD.

6.3 GAS PROCESSING

The three basics steps in Gas processing are

Fine Separation

Moisture Control

HCDP (Hydrocarbon Dew Point)



6.3.1 SEPARATION

6.3.1.1 INLET SEPARATOR

Produced gas from slug catcher having

moisture and condensate contaminates

is introduced in a vertical type Inlet

separator vessel for the purpose to

remove Liquid hydrocarbons which may

form hydrates and can choke flow lines.

Rich gas is directed at the inlet of vessel

from the middle having momentum

breaker, strikes with the inside deflector

plate at the inlet which break up its

momentum and liquid hydrocarbons

deposit on the plate, coalesce and fell

down to the bottom of the vessel due to

sudden change in flow direction and in this way separation occurs. The gas having moisture

goes upward in a vessel and come out at the top after being passes through demister pad at the

top. Due to greater mass, liquid hydrocarbons droplets cannot flow with the gas and are catch

up there at the demister pad and fell down at the bottom due to gravity. The condensate from

bottom is injected in a main condensate line through Level control valve LCV. And the gas from

the top is routed towards Cold Box through Emergency shutdown valve (ESDV) and Flow control

valve (FCV). The important parts of inlet separator are deflector plate, wear plate, vertex

breaker and mist eliminator. Deflector plates break the momentum of the effluent, weir plate

act as a partition between water and condensate, vertex breaker control that no gas goes in to

condensate pipe and the mist eliminator removes impurity from gas

6.3.1.2 MERCURY REMOVAL UNIT

This unit is bypassed, however when in service, gas from the inlet separator will be directed to

MRU unit for the removal of mercury contaminates. Gas from the inlet separator will be first

passed through coalescer filter for the removal and coalescing of condensate and then the gas

will be entered into the filter elements/cartridge to catch very fine particles of size 10 microns,

at the outlet of which a demister pad will be installed. The gas will be then introduced from the

top of the MRU bed to form initial cake, then passing through the ceramic bowls having john

methyl catalyst to absorb mercury contaminates from gas. Then gas will be passed through the



dust filter to remove 99.9% of all solid particles of 5-micron size and greater through filter

cartridges. Then the gas will be passed to BAHE for further processing.

6.3.2 DEHYDRATION

6.3.2.1 REASONS FOR DEHYDRATION OF GAS

One of the reasons for dehydration is to prevent hydrate formation. Free liquid water in the

natural gas can lead to a problem known as hydrate formation. A hydrate is an ice-like crystal

formed when methane, ethane, propane, and butane molecules embed inside a lattice of water

molecules. Hydrate crystals restrict gas flow. Hydrates can plug valves, meters, instruments,

and flow lines upsetting or even shutting down processes.

6.3.2.2 WHY USING TEG FOR DEHYDRATION?

TEG is used in dehydration process because compared to other glycols:

TEG has a relatively high thermal stability as its heat decomposition begins at a

theoretical temperature of 404 °F.

It is efficiently regenerated because of the wide boiling point difference between TEG

and water.

It has low vaporization losses because of its high boiling points.

6.3.2.3 TEG CONTACTOR

The gas streams from inlet separator and flash separator are combined and introduced to the

TEG Contactor which is basically a vertical packed column. Gas entering the bottom of TEG

Contactor is slightly cooled at the 1st pass of BAHE. The TEG tower comprises of one chimney

tray and two structured packing sections enhancing turbulence and thus providing sufficient

contact time and area to countercurrent flowing gas and glycol. It helps in the absorption of the

moisture in TEG. At the bottom of the contactor an internal scrubber is provided to remove

condensate oil from the entering gas as it causes foaming and may clog the tower. Cooled gas is

introduced from the bottom of tower while Lean TEG is showered from the top causing a

counter current contacting flow with the rising hydrocarbon thus causing the absorption of

moisture from hydrocarbon gas. At the top of the tower there is a demister pad whose function

is to catch all the liquid droplets moving on with gas and hence liquid free gas is delivered. The

rich TEG is passed through the regeneration process so that it can be utilized again. The gas is

then passed to the Coalescing filter.

6.3.2.4 TEG REGENRATION UNIT

The regeneration process is used to convert Rich TEG to Lean TEG so that it can be utilized again

for dehydration of gas. This unit consists of:



6.3.2.5 GLYCOL FLASH TANK

The rich TEG containing absorbed gas from TEG Contactor is introduced to Glycol Flash Tank

which is a horizontal 2 phase separator. It is used for flashing the absorbed gases out of the

Rich TEG before the TEG is regenerated to lean form. It consists of a wire mesh mist extractor

which removes any entrapped glycol from gas. The flashed gas is then sent to the flare.

Operating Conditions:

Inlet pressure = 1000 psi

Outlet pressure = 65 psi

6.3.2.6 PARTICULATE FILTER

The rich glycol from flash tank is then passed through particulate filters for removal of solid and

dust particulates from glycol. This filtration is done to avoid foaming, wear of glycol pumps and

minimizing the deposition of solid particles in pipes and equipments. Particulates filters have

filters of specific mesh size inside. Two particulate filters are installed in which one is on

standby

& the other is in running condition. When differential pressure of filter increases to around 15-

17 psig, then this filter is isolated and depressurized while the stand by filter is taken in service

to ensure smooth operation. The rich glycol enters from the bottom of the filters during which

the solid particles are catched up by the filters while TEG exits at the top.



6.3.2.7 CHARCOAL FILTER

The rich TEG from particulate filter is then introduced to the bottom of another filter called

charcoal filter for the removal of dissolved/absorbed hydrocarbon. It consists of carbon porous

bed to absorb the hydrocarbons. The hydrocarbon free Rich TEG then exits from top of this

filter. A manual bypass is also installed which is utilized during replacement of these filters.

6.3.2.8 GLYCOL/GLYCOL EXCHANGER

The rich TEG from charcoal filter is then passed through Glycol/Glycol exchanger which is a

plate and frame type heat exchanger. Heat transfer takes place between cool rich glycol from

charcoal filter and hot lean glycol from stripping column. This preheating of rich glycol reduces

heat load on glycol re-boiler.

The temperature of entering glycol rises from 95 °F to 215 °F and the temperature of exiting

stream drops from 365 °F to 225 °F.

6.3.2.9 STILL COLUMN

Rich TEG from the heat exchanger enters the still column of re-boiler.

The hot Rich TEG from the Glycol/Glycol exchanger is introduced to TEG Re-boiler Still Column

where the TEG starts its regeneration cycle. Still column is a vertical column having a reflux coil.

It is mounted on horizontal re-boiler shell and provides contact between the down flowing rich

glycol and up flowing re-boiled steam vapors. The rising vapors reach the top of the Still Column

where the cool reflux coil condenses glycol vapors and the refluxed liquid flows back down into

the still column, minimizing glycol losses while the overhead steam is vented to atmosphere.

6.3.2.10 GLYCOL REBOILER

It is a horizontal heat exchanger having tube coiling at one end and weir plate at the other. In

this re-boiler glycol which is rich in water is heated via heat exchange with hot oil (Texatherm

46). This re-boiler is actually a shell and tube heat exchanger. The glycol passes through the

shell side of re-boiler and hot oil circulating in a tube side. The hot glycol overflows into the

Stripping Column through a weir plate at shell side. In the re-boiler more of the absorbed water

is turned into steam.

Operating Conditions:

Inlet temperature = 215 °F

Outlet temperature = 385 °F

6.3.2.11 STRIPPING COLUMN

TEG from Glycol Re-boiler then flows to the TEG Stripping Column where dry stripping gas is

injected. Heated dry fuel gas is utilized as stripping gas. Dry stripping gas absorbs more water



from the TEG. The stripping gas and steam flow out the top of the TEG Still Column to the still

column vent. (Enhancing partial vaporization)

6.3.2.12 ACCUMULATOR

The hot lean TEG then flows through the Glycol/Glycol Heat Exchanger where it exchanges heat

with Rich TEG and cools down. This cool Lean TEG is then introduced to the TEG Accumulator.

The level of accumulator is maintained at round about 40-50 %.

6.3.2.13 TEG RECIRCULATION PUMPS

The lean TEG from TEG Accumulator then flows to the TEG Recirculation Pumps. These pumps

are 100% duty positive displacement plunger pumps and are driven with the help of electric

motors. There are two pumps per train. One pump is in service while the other is on stand-by.

These pumps pump the TEG to high pressure. Drop-wise leakage is allowed in these pumps to

avoid overheating and wear of packing of these pumps.

Discharge pressure = 1000 psi

6.3.2.14 COALESCING FILTER

Dry Gas from the TEG Contactor is then routed to Coalescing Filter which is a vertical separator.

It is used to trap and remove any liquid mist from the gas. It has 2 compartments. Gas enters

the lower compartment where a deflector plate is located just ahead of the inlet nozzle to take

advantage of an abrupt change of direction to separate the major portion of the Hydrocarbon

liquid from the gas stream. The gas rises to the upper compartment where it is passed through

filter riser and filter cartridge which separated the coalesced liquid droplets from gas. The liquid

separated is then discharged to Glycol Flash Tank. The dry and liquid-free gas is then routed to

the Hydrocarbon Dew Point Control Unit.

6.3.3 HYDROCARBON DEW POINT CONTROL UNIT

Hydrocarbon dew point is the temperature at which the Natural Gas Liquids start to condense.

In this unit the gas is cooled down and condensate is extracted from the gas so that it meets the

hydrocarbon and moisture requirements of SNGPL.

The HCDP unit consists of:

Brazed Aluminium Heat Exchanger (BAHE)

Cold Separator

JT-Valve



Low temperature Separator (LTS)

6.3.3.1 BRAZED ALUMINIUM HEAT EXCHANGER (BAHE):

The BAHE also called cold box is a multi-pass exchanger. Brazing is a process in which two

metals are joined with each other by using third molten metal that is called filler metal. BAHE is

a plate-fin heat exchanger consisting of a block (core) of alternating layers (passages) of

corrugated fins. The layers are separated from each other by parting sheets and sealed along

the edges by means of side bars, and are provided with inlet and outlet ports for the streams. It

has 5 passes out of which three are gas passes while two are condensate passes.

1st pass:

In this pass, the hot gas from inlet separator (MRU if in service) is passed and cooled and is then

routed to the bottom of the TEG Contactor. The temperature drop is relatively small.

Temperature is dropped from 89 °F to 86.6 °F.

2nd pass:

In this pass, the dry gas from Coalescing Filter is passed and it also cools down and then enters

the Cold Separator. Temperature is dropped by a large amount i.e. from 89 °F to 12 °F.

3rd pass:

In this pass, the cooled gas from Low Temperature Separator (LTS) is passed and it exchanges

heat and becomes hot. its temperature is increased by a large amount. Its temperature

increases from 12 °F to 89 °F.

4th Pass:

In this pass the cold condensate from the Cold Separator enters and exchanges heat and

becomes hot and heads towards the flash separator for further processing. Its temperature is

raised from 12 °F to 89 °F.

5th Pass:

In this pass, the cold condensate from LTS enters and exchanges heat and becomes hot and

heads towards the flash separator for further processing. Its temperature is raised from 12 °F to

88 °F.



6.3.3.2 COLD SEPARATOR

Cooled gas from 2nd pass of BAHE is then

introduced to a cold separator which is a 2

phase horizontal separator. It consists of an inlet

deflector and a high efficiency demister pad. As

the gas enters the separator at the inlet

deflector, due to sudden change of momentum,

the heavier hydrocarbons (condensate) settle

down. At the exit of cold separator there is

demister pad and its function is to trap the liquid

droplets exiting the cold separator and settles it

down. This separated condensate is then routed

to the 4th pass of BAHE where its temperature increases while the separated gas heads

towards JT-valve.

6.3.3.3 JOULE THOMPSON VALVE

JT Valves are the expansion valves, working upon the principle of Joule Thomson Effect. The

pressure is dropped, suddenly, across this valve as a result of expansion. Then temperature gets

reduced to the point so that the dew point of C3 is reached. This valve works on the principle of

joule Thomson effect. When a non-ideal gas suddenly expands from a high pressure to a low

pressure there is often a temperature change. Temperature of the gas is increased or

decreased depending upon initial state. The ratio of ΔT/ΔP is known as the Joule-Thomson

coefficient. The sudden change in pressure decreases the temperature to -20 degrees

Fahrenheit. This decrease in temperature helps heavier hydrocarbons to condense and

collected in Low temperature separator. The gas from Cold separator is passed through JT valve

where its Pressure and temperature reduces due to sudden expansion of gas volume cause

decreasing in pressure and indirectly temperature. Thus, flow across a JT valve is usually

considered an isenthalpic process. Isenthalpic Process is a thermodynamic process (also called a

throttling process) in which enthalpy is conserved.

6.3.3.4 LOW TEMPERATURE SEPARATOR

At LTS inlet line a deflector plate and at the outlet line a mist eliminator is installed like cold

separator unit for the same purpose. The Gas enters to the Low Temperature Separator at the

pressure of 850 psi and at the temperature of -20 degreeF. The heavier hydrocarbons are

condensed due to very low temperature of -20degreeF. From the bottom of the Separator,

these liquid hydrocarbons are also sending to the Condensate Flash Separator after passing

through Heat exchanger at fifth phase. Where its temperature rises to 92oF and finally



combined with the Cold Separator liquid. Both combined hydrocarbons liquids are then passed

into the Flash Separator through a level control valve (LCV).

The gas leaves out at the top from LTS is passed through heat exchanger at the 3rdpass where it

is warmed up to 880degreeF to meet the sale gas specification

6.3.3.5 BTAX UNIT

The steam generated in still column contains toxic gases

(Benzene, Toluene, Aromatics and Xylene) which are

harmful for our nervous system. So its treatment must

be done before vent to atmosphere.

6.3.3.6 SALES GAS BOOSTER COMPRESSORS

These compressors are engine driven

double acting single stage reciprocating

compressors.

Booster compressors are installed after

HCDP unit. Three booster compressors are

installed at CPF. The purpose of booster

compressor is to compress the sales gas to

the pressure of the SNGPL line.

The design capacity of booster compressor

is 100 MMscFD gas each. So the total

capacity of three booster compressor is 300

MMscFD. The Gas Re-Compressor is equipped with a Shut down Valve which shuts in the

compressor unit, a Blow down Valve for de-pressuring the compressor, and a bypass Valve for

start-up flow control.

Pressure parameters:

Inlet pressure = 700 psi

Outlet pressure = 1000 psi

Gas from booster compressor goes to metering skid.



6.3.3.7 SALE GAS METERING SKID

Dry gas from Booster Compressor passes through the Sales Gas metering System. The main gas

stream is divided into three streams.

Moisture analyzer

Gas chromatograph

Orifice meter

6.3.3.8 MOISTURE ANALYSER

The maximum moisture allowable is defined by gas receiving company i.e. 7 lbm/ MMscFD. The

moisture content is controlled in dehydration unit by TEG absorption. Moisture analyzer

measures the amount of moisture present in the gas stream in units of pounds of water per

MMSCF of gas. It intakes a sample of water every three minutes and analyzes it, calculating the

water content in the gas and indicating and transmitting it to the PLC.

6.3.3.9 GAS CHROMATOGRAPH (GC)

The gas that is sold to SNGPL has some minimum level of BTUs. Those BTUs are measured

indirectly by gas chromatograph. Gas chromatograph measures the composition of sale gas and

if we know the composition of gas then measurement of BTU becomes possible as there is a

fixed value of BTUs for unit mass of a hydrocarbon.

Gas chromatograph has 3 gases:

1. Sales gas

2. Calibration gas

3. Helium gas

GC measures the composition of sales gas by comparison with calibration gas. the composition

of calibration gas is known and the composition of sales gas is measured by comparison with

calibration gas.

Helium is a light gas and it is used for the quick transportation of calibration gas. The flow of

gases is changed every three minutes.

6.3.3.10 METERING PCV

PC takes pressure indication from the upstream of PCV and controls valve opening/closing in

order to maintain a certain downstream pressure. This PCV controls the system pressure and

also the pressure at which sale gas is supplied to SNGPL.



6.3.3.11 SHUT DOWN VALVE (SDV)

This is a solenoid operated piston type valve which can be used to discontinue gas supply to

SNGPL. It is connected with the PLC and can also be manually operated.

6.4 CONDENSATE PROCESSING

CPF plant is designed to produce 6600 barrels of condensate per day. The plant can be

operated on 110% load and hence its production is higher than the design value. During my

internship interval the condensate production was around 7000 barrels per day.

Capacity = 6600 bbl/day

Production = 7000 bbl/day

The condensate that is separated from the feed from well at slug catcher is further processed to

meet the requirements of ARL. After Slug Catcher, Condensate is processed in the following

units:

1. Condensate Stabilization Unit

2. Storage Tanks

3. Condensate Loading Area

6.4.1 CONDENSATE STABILIZATION UNIT:

In this unit, stabilization of condensate takes place in which the lighter volatile hydrocarbons

are separated from condensate. Stabilization is done by maintaining the Reid Vapor Pressure

(RVP) of condensate. RVP is the measure of volatility of condensate and is defined as "The

absolute vapor pressure exerted by a liquid at 100 °F temperature." Higher the RVP, more will

be the lighter components present and thus the condensate will be more volatile.

This process is done for the separation of very light hydrocarbons gases like CH4, C2H6, and

C3H8 from heavy hydrocarbons components in order to control RVP below 7psig so that vapor

phase is not produced on flashing the liquid to atmospheric storage tank or during bowzers

filling and in transportation.

The Stabilization Unit consists of the following units:



Flash Separator

Flash Gas Compressor (FGC)

Feed Bottom Heat Exchanger (FBHE)

Stabilization Tower

Condensate Stabilizer Re-boiler

Condensate Stabilized Overhead (CSO) Compressor

Product Cooler

6.4.2 FLASH SEPARATOR

Flash separator is a horizontal separator type vessel equipped with a deflector plate and a

demister and weir plate. It receives feed from:

Slug Catcher

Inlet Gas Separator

TEG Contactor

Cold Separator

Low Temperature Separator

CSO Compressor

Feed enters the flash separator and strike the deflector plate. As a result of this, a big change in

momentum occurs and pressure drops. The heavier hydrocarbons and water are not able to

follow this rapid change of momentum and thus they settle down by gravity. The weir plate is

used to ensure a particular limit of condensate. Water being the heavier settles down before

the weir plate while condensate floats over water on the weir plate. Water is then drained to

slope vessel. The flashed gases rise and are passed through the demister to catch any liquid

droplets and is then directed towards the FGC compressor while the condensate is routed

towards a feed bottom heat exchanger via a 3-way TCV for further processing.

6.4.3 FLASH GAS COMPRESSOR (FGC)

Gas from flash separator is then introduced to flash gas compressor which is basically a motor

driven 2 stage double acting reciprocating compressor. A suction scrubber removes the liquid

droplets from the gases entering FGC 1st stage. The gases are compressed and are passed

through a forced draft fin fanned cooler to remove the heat of compression. Again a suction

scrubber removes condensed liquid from gases entering the second stage. After getting

compressed to the pressure of inlet separator the gas are cooled in the fin fanned cooler and



are routed towards the inlet gas separator. The gas is compressed to a pressure of about 1300

psi to the inlet separator.

6.4.4 FEED BOTTOM HEAT EXCHANGER (FBHE)

FBHE is a shell and tube type heat exchanger. It is used to pre-heat the cold condensate feed in

order to reduce load on stabilized re-boiler. The cold condensate feed from the flash separator

flows in the tube side, while the hot stabilized condensate is circulated in the shell side. The

cold condensate feed after pre-heating is directed towards the middle section of Stabilization

tower while the temperature of hot condensate feed is reduced.

Cold condensate:



Hot condensate:



6.4.5 CONDENSATE STABILIZATION TOWER

It is a long vertical packed column in which the condensate is stabilized by maintaining its RVP.

It is used to stabilize the condensate by removing the lighter hydrocarbons like CH4, C2H6 etc

by continuous heat supply from vapors coming from stabilizer re-boiler and the hot condensate

feed coming from FBHE to the middle of tower. The tower is equipped with two packed

sections. This tower is attached with a re-boiler which heats the condensate to a temperature

about 280 °F. The pre-heated stream from the FBHE enters into the middle of the column and

flows downwards through packing material within the tower counter currently contacting the

hot hydrocarbon vapors’(coming from the re-boiler) rising through the tower. At this stage heat

exchanging occurs b/w hot vapors and preheated condensate stream. At the same time, the

cold condensate feed is fed to the top of tower where baffle plates are installed from which the

cold condensate feed is allowed to drop due to which the heavier hydrocarbons separate and

fall down due to gravity while the gases rise up from where they are fed to the CSO

compressors.

Heating medium in this Column are vapors that comes from the respective Re-boiler.

6.4.6 CONDENSATE STABILIZED OVERHEAD (CSO) COMPRESSORS

Gases from the overhead of stabilization tower are routed to the condensate stabilized

overhead compressor which is basically a motor driven 2 stage double acting reciprocating

compressor. A suction scrubber removes the liquid droplets from the gases entering CSO 1st



stage. The gases are compressed and are passed through a forced draft fin fanned cooler to

remove the heat of compression. Again a suction scrubber removes condensed liquid from

gases entering the second stage. The gas is compressed to a pressure of about 330 psi. The

compressed gases from second stage are injected in the stream entering flash separator and in

this way they are recovered.

CSO compressor also creates a low pressure zone at the top of the stabilization tower and

hence the escaping tendency of the lighters is increased which helps in the controlling of RVP.

6.4.7 STABILIZER REBOILER

The stabilizer re-boiler is basically a kettle type shell and tube heat exchanger. The purpose of

re-boiler is to heat the condensate to a temperature of around 280 °F before being fed to the

stabilization tower. The condensate is heated by exchanging heat with Texatherm-46 Heating

Oil which is circulated in the tubes while the condensate is circulated in the shell side of the

heat exchanger. A spill over weir plate is also installed inside the Re-boiler for level controlling

of condensate. The vapors produced in the R-boiler are return to column. The stabilized oil is

then routed to feed bottom heat exchanger for maximum heat transfer and then send to the

product cooler to reduce its temperature. Heat duty = 1.25 MMBTU/hr

6.4.8 PRODUCT COOLER

Product cooler is a forced draft aerial cooler. Stabilized condensate from stabilizer re-boiler is

cooled by blowing of ambient air present in the environment. The angles of fins of cooler are

adjusted according to the environmental conditions. If more cooling is required in case of

summers then the fan inclination angle is increased which causes more suction and flow of air,

hence causing cooling.

6.4.9 STORAGE TANKS

Storage tanks are large metallic tanks used for storage of condensate. Storage tanks are four in

numbers. The capacity of each tank is 17019 barrels.

On the storage tanks, the following systems are arranged for safety purposes:

Fire protection setup

Nitrogen / fuel gas

Pressure relief valves

Foam injection package

Level indicator transmitter



Condensate from the product cooler is directed towards storage tanks. Condensate from slope

vessel is also injected to the inlet line of the storage tanks through a centrifugal pump.

Nitrogen is used to form a blanket on the condensate surface. As it is inert so the combustion

chances are reduced and also it exerts enough pressure to prevent the escaping of lighters.

Pressure relief valves are installed at the top of the storage tank. The set point of PRV is 2

inches of water column. In case the PRV doesn’t operate then the second PRV is used which has

a dead weight that exerts pressure on a surface is opening. Its set point is 7 inches of water

column. The level of condensate in storage tanks is indicated by level transmitters which are

installed on top of storage tanks. The level is also checked manually with the help of dip rod

having color kut on it.

6.5 PRODUCED WATER PROCESSING

Produced water contains harmful chemicals which are injurious for the mankind and this water

cannot be used for the utility or other purposes. This water has the ability to cause production

problems such as the formation of hydrates and damage to the process equipment by

corrosion. Water, therefore, must be recovered, treated and disposed of. The Produced Water

Treatment system is provided to treat all water and dispose of it in an environmentally friendly

manner.

The produced water treatment facility consists of following equipments:

1. Water Degassing Boot

2. Corrugate Plate Interphase (CPI) Separators

3. Evaporation Ponds



6.5.1 WATER DEGASSING BOOT

The water degasser is a vertical two phase separator. Water degassing boot is used to separate

water gas and condensate from the water. It has following parts:

Deflector plate

Demister pad

Vortex breaker

The raw water from slug catcher and Condensate flash separator of two trains is introduced to

De-gassing boot where sudden pressure drop make the gas flash off from the water. A deflector

plate reduces the incoming stream momentum and water and traces of condensate droplets

fell down and collected at the bottom. The gas leaves the vessel at the top through demister

pad to catch any contaminate of water. Vortex breaker prevents swirling of water as swirling

will create an open area for gas to again penetrate in water. The dissolved gases are flashed off

and are sent to the flare. Water from water degassing boot enters CPI separator.

6.5.2 CORRUGATE PLATE INTERPHASE (CPI) SEPARATORS

CPI separator is a rectangular chamber having a weir plate to make main chamber for partial

separation and corrugated plate interception. Its purpose is to separate water and condensate.



Water from de-gasser boot combines with the condensate from knock out drum and the

combine stream is introduced into CPI chamber The CPI corrugated plate provides sufficient

time for the separation of oil and water from each other’s due to gravity/density differences.

The water having greater density will settle down while the oil having low density will flow over

the surface of water and make interface. The oil layer flows to the oil chamber and water to the

water drain chamber. The condensate is then pumped via a centrifugal pump to slope vessel

from where condensate is recovered. Water is pumped to the evaporation pond via 2

centrifugal pumps per train.

6.5.3 EVAPORATION PONDS

Evaporation ponds are basically constructed to evaporate the unwanted contaminated

Produced Water. Liners (High Density Polyethylene HCDP‘s) also called Geo-Membranes are

installed at the bottom to prevent water from seepage, so to protect the land from this acidic

water. For their welding, Wedge Machine is used, which heats it up to temp of 300 ºC.

A test is done to check whether there is any leakage. At a pressure of 35-Psi, the wedge is

tested for a pressure drop. If any leakage exists, then Extrusion Machine is used for its welding

using same material. It is done by melting it with hot air which is blown at 270 ºC at the points

where leakage exists.

7. MGPF PROCESS

MOL Pakistan launched a new gas processing facility in Tal Block along with CPF

(CentralProcessing Facility). This is only crude oil and LPG processing facility of Mol Pakistan.

Another fact is, it is largest LPG processing facility in Pakistan. The processing products of this

plant are Natural gas, LPG, condensate Oil, and crude oil. The main supplies in GPF are coming

from Makori east, Maramzai and Mamikhel. These two lines have different compositions. So

their products are processed separately from each other, mainly crude oil and condensate oil.

7.1 SEPARATION OF FLUIDS

This is a 1st step of processing of fluid which is coming from wellhead. Density base separation

occurs when fluid comes into the slug catcher. Our wellheads are far away from processing

facilities. So, when a fluid travels too long, across the elevations and depths. There are

turbulences occur in the fluid. It comes in the form of slug that is why we place a slug catcher at

the start of process. There are different types of slug catchers:

A vessel type slug catcher: It is essentially a conventional vessel. This type is simple in design



and maintenance.

A finger type slug catcher: It consists of several long pieces of pipe ('fingers'), which together

form the buffer volume.

The advantage of this type of slug catcher is that pipe segments are simpler to design for high

pressures, which are often encountered in pipeline systems, than a large vessel. A disadvantage

is that its footprint can become excessively large.,

A Parking Loop slug catcher: It combines features of the vessel and finger types. The Gas/Liquid

Separation occurs in the vessel, while the Liquid is stored in the parking loop shaped fingers.

In GPF, there are two slug catchers due to different composition of the fluids.

Makori East line: this line has low temperature, when it reaches to the facility. Temperature of

this line rises by trunk line heater before any processing. Slug catcher separates gas from the

top, crude oil and water on the basis of densities.

Maramzai and Mamikhel line: It is passed through slug catcher, Gas, condensate and water

separate on the basis on the basis of densities.

The phenomenon of separation is same in both cases. First of all, momentum breakage occurs

by deflector plate. Secondly gas, water and condensate separate out on the basis of densities.

7.1.1 INLET OIL TRUNK LINE HEATER

Oil/Associated Gas from Mamikhel-2 well and Makori-East wells is routed to the tube side of

Inlet Oil Trunk Line Heater, having Rated Heat Duty 21.29 MMBtu/hr. This Oil/Associated gas

stream will be heated up to 115oF with a pressure drop of 5 Psi. After heating this stream will

be routed to the Inlet Slug Catcher (Oil). As oil is viscous so need heating to reduce its viscosity.

7.1.2 INLET SLUG CATCHER (OIL)

The Well’s Oil and Associated Gas and Water from the liquid pipeline(s) are first introduced to a

Finger-Type Three Phase Inlet Slug Catcher at 115oF. Bulk of separation of the phases takes

place in the Slug Catcher. Vapour stream from this Slug Catcher at temperature 115oF and

pressure 1500 Psig is routed to Pressure Reduction Section after being combined with Gas

Stream from Inlet Slug Catcher (Gas). The Un-Stabilized oil is then routed to Oil Stabilization

Section. Free Water in the oil feed stream is collected in Water Degassing Boot and flows on

level control to the Produced Water Treatment and Disposal Facilities.

7.1.3 INLET SLUG CATCHER (GAS)



The Well’s Gas and Associated Condensate/Water from the gas pipeline(s) are first introduced

to a Finger-Type Three Phase Inlet Slug Catcher (VS-306-01) which operates at 1500 PSIG and

115.53degreeF. Bulk of separation of the phases takes place in the Inlet Slug Catcher (VS-306-

01). Condensate from Inlet Slug Catcher (VS-306-01) is routed to Condensate Stabilizer Feed

Drum. The condensate is further processed to produce Stabilized Condensate. Produced Water

from Inlet Slug Catcher (Gas) (VS-306-01) is routed to the Produced Water Treatment and

Disposal Facilities.

7.1.4 RAW GAS HEATER

Raw Gas Streams from Inlet Slug Catcher (VS-306-01) enter the Raw Gas Heater (E-306-02) at

temperature 69.02oF and pressure 1475 Psig. This stream IS heated to 106°F with a pressure

drop of 5 Psi. It is not in operation during the summers.



7.2 GAS PROCESSING

7.2.1 PRESSURE REDUCTION SECTION

Gas streams from Slug Catcher and Oil / Gas Separator are combined together and let downin

pressure prior to entering Inlet Gas Separator (V-307-01), Pressure is reduced down by PCV up

to 1005psi.

7.2.2 INLET GAS SEPARATOR

The Inlet Gas Separator is a 2-Phase vertical knock out drum which serves to disengage the

entrained liquids from the feed gas streams. Combined Gas streams from Slug Catcher, Oil / Gas

Separator and Stabilizer Overhead Compressors enter Inlet Gas Separator (V-307-01) below the

demister pad. Entrained liquid in gas stream is knocked out and collected in V-307-01.Gas

leaves from the top of separator and goes into feed sales gas exchanger.

7.2.3 FEED/SALES GAS HEAT EXCHANGER

The Vapours leaving from the top of inlet separator is routed to Feed / Sales Gas Heat

Exchanger which is used to exchange heat with sales gas in order to meet required sales gas

outlet temperature of 115°F (SNGPL Requirements).

7.2.4 MERCURY REMOVAL VESSEL

Mercury is generally present in nature and also in most natural gas streams to varying levels.

The primary reason for mercury removal from natural gas is to protect downstream Brazed

Aluminium Heat Exchangers (BAHX) and Turbo Expander wheel used in cryogenic hydrocarbon

recovery natural gas plants. Mercury tends to form amalgamates with Aluminium which can

result in mechanical failure of BAHX as well as gas leakage. Another reason for removing

mercury is to produce mercury-free product streams.

As the gas passes through the absorbent bed which consists of Metal Sulphide adsorbent, the

mercury is removed by adsorption/reaction. The adsorbent bed is supported by ceramic balls

and separated with a mesh screen.



7.2.5 DEHYDRATION COALESCER:

This unit is also called molecular sieve dehydration unit receives gas from dust filters. In this

unit coalescing action takes place in which small water droplets coalesce and form big water

droplets, which are easily separated by gravity.

7.2.6 DEHYDRATION PACKAGE:

Dehydration package mainly contain a dehydration unit. It consists of beds of activated

alumina, which adsorbs moisture content. There are three dehydration units in GPF. Two of

them are working all time and one on regeneration. Gas enters from the bottom, passes

through the beds and dry gas obtains at the top.

The Dehydration Adsorbers are used to remove moisture from inlet gas feed. The three bed

Molecular Sieve system is time cycle controlled to switch beds every 18 hours. One bed begins

its 18 hours adsorption cycle, another bed is half way thru its 18 hours adsorption cycle and the

third bed is starting its regeneration cycle, which includes 6 hours heating step, 2 hours cooling

step and 1-hour Stand-by time.

At design conditions, two beds are in adsorption at all times while the third bed is in

regeneration. During adsorption, the flow direction of the inlet gas is down through the bed.

However, during regeneration the flow direction of the regeneration gas is up through the bed.

This arrangement ensures that the bottom of the bed will be the driest portion of the bed. The

regeneration cycle requires approximately 12 MMSCFD of regeneration gas to regenerate one

bed.

Regeneration system consists of number of steps,

Heating of Dry Gas: dry gas is heated at elevated temperature and passed through

the dehydration unit for six hours to remove moisture content in the reverse direction.

Cooler: hot gas is cooled after passing through the dehydration unit.

Scrubber: this cool gas is separated from moisture by scrubber.

Compressor: During all this process pressure of the gas drops, Compressors are

used to pump this again to dehydration package.



7.2.7 HCDP CONTROL UNIT J-T VALVE / TURBO EXPANDER & DE-ETHANIZER

Dry gas from dehydration dust filters (A/B) enters Hydrocarbon Dew Point Control Unit (HCDP)

Joule – Thomson (J-T) valve / Turbo Expander (TE) & De-ethanizer, which is a Cryogenic system.

In Cryogenic system the dry gas is split into two streams that are chilled by heat exchanged with

De-ethanizer side and product streams. The chilled streams recombine and enter the Cold

Separator. The remaining gas is split into two streams. About 20% flows directly to the De-

ethanizer and the remainder is fed into the Turbo Expander (TE-308-01), where it is expanded

down to -99 °F and 285 Psig before it is introduced to the De-ethanizer Tower.

7.2.8 GAS/GAS HEAT EXCHANGER

The Gas/Gas Exchanger (E-308-01) is combined with Reflux Condenser (E-308-02) About 85% of

dehydrated inlet gas exiting the dehydration dust filters (A/B) is routed through E-308-01 where

it is chilled by De-ethanizer tower. E-308-01 is a Brazed Aluminium Plate Fin Heat Exchanger.

This type of exchanger is composed of alternating layers of corrugated sheets, called “fins” and

flat sheets, called “separator sheets”.

7.2.9 COLD SEPARATOR

The Cold Separator is a 2 Phase Vertical separator. The split dehydrated inlet gas is re-combined

before entering V-308-01, in which condensate drops out of the gas. The condensate is level

controlled to middle section of De-ethanizer by 308 LCV-0101. Gas exiting the top of V-308-01 is

the suction of Turbo Expander with remainder combining with condensate going to Reflux

Condenser.

7.2.10 TURBO EXPANDER / COMPRESSOR

The Expander is a radial turbine driving a centrifugal compressor. Expansion through a turbine,

called turbo-expansion will generate more cooling than expansion through a valve. It also

generates useful mechanical work which, in this case is used to compress the De-ethanizer

overhead vapour. The work is transmitted from the Expander to Compressor through a shaft

that connects the two services. At design conditions, rotating speed of this unit is in the range

of 25,000 RPM. At this extremely high speed, the unit is very sensitive to vibration problems

and solid particulates in gas stream.



7.2.11 JT VALVE

The Expander is equipped with a by-pass valve also known as the JT valve, which is used

whenever the Expander is down or taken off line for maintenance. It is generally closed when

the Expander is in operation unless the gas rate exceeds the Expansion capacity.

7.2.12 SALES GAS HEATER

The Sales Gas Heater is equipped with heating element. A portion of the residue gas leaving the

Residue Gas Compressor and the Dry-out recycle / sales gas are routed to sales gas heater to

provide heated seal gas requirement for TE.

7.2.13 SALES METERING SKID

The Sales Gas Metering Package comprises of Three Meter runs (2 operating and 1 spare) sized

for total capacity of 160 MMSCFD. The Metering System will include Online Flow Measurement,

Gas Chromatograph (C6+ analysis) and Moisture Analyser and is installed on common discharge

header of Sales Gas Booster Compressors. Also the Barton chart recorder is installed at each of

the three legs of metering skid.

7.3 LPG PROCESSING

7.3.1 DE-ETHANIZER TOWER

The De-ethanizer Tower is equipped with packed beds and re-boiler to remove light ends from

the liquids recovered in chilling and expansion process. Generally the De-ethanizer pressure

sets the recovery level, lower the pressure is maintained the greater the product recovery. The

chilling and expansion system is designed to operate in the Ethane Rejection mode of Gas Sub

Cooled (GSP) Cryo process. From Reflux Condenser (E-308-02) two phase (liquid/vapour) stream

enters the top section of the De-ethanizer Tower above the top packed bed. Tower has four

separate packed beds packed with low temperature Aluminium and stainless steel rings. Each

packed bed is provided with a liquid distributor on top. Two chimney trays are provided to

collect the liquids flowing down the Tower for passage through the Re-boilers. Liquids flowing



down the tower act as reflux to scrub the stripping vapours produced in the re-boiler.

7.3.2 REFLUX CONDENSER

The reflux condenser uses cold residue gas from the overhead of de. Ethanizer on cold side to

chill portion of V-308-01 vapour on hot side before it is introduced to top of C-309-01. During

operation in ethane rejection mode the liquids from V-308-01 flows through E-309-02.

7.3.3 SIDE RE-BOILER

Warm dehydrated inlet gas flows through the hot side but tower liquid does not flow through

the cold side. The De-ethanizer side Re-boiler (E-309-02) will be used to preheat V-308-01

liquids before they are introduced into C-309-01. The Bottom Re-boiler (E-309-01) will be

bypassed on the tower side.

7.3.4 TRIM RE-BOILER

Trim Re-boiler (E-308-03) is a shell and tube type heat exchanger used for re-boiling the

Deethanizer. Hot Oil circulating through the tube side provides the heat needed to produce the

required stripping of vapour in the De-ethanizer.

7.3.5 METHANOL INJECTION PUMP

Methanol injection pump (P-308-01) is a positive displacement type pump that takes suction

from Methanol Storage Tank and injects methanol to various injection points to melt down

freezes in the extremely cold piping and equipment.

7.3.6 DE-BUTANIZER

The liquid bottoms product from de-ethanizer enters De-Butanizer Tower (C-310-01) at a

pressure of about 200 Psig. C-310-01 is used to separate the combined LPG / Condensate

produced. Stabilized Condensate feed from Condensate Stabilization Unit is combined with de-



ethanizer bottoms and fed to C-310 01. This in turn helps by adding heavy components to the

mixed LPG / Condensate feed there by separating LPG from NGL and meeting required product

specifications. The overhead vapours are routed to an overhead reflux condenser air cooler and

is condensed and sub-cooled.

The condensed liquid flows to Debutanizer Reflux Accumulator and is then routed to

Debutanizer Reflux Pumps (A/B). A portion is pumped back to de-butanizer as reflux while the

remainder is sent as final product to Condensate Storage Tanks after being cooled by Air Cooler

(AC-310-02). De-Butanizer column is equipped with single pass from valve tray #1 to #12 and

two pass from valve tray #13 to #30, a total condenser (De-Butanizer Reflux Condenser (AC-

310-01) and a kettle type Debutanizer Reboiler.

The condenser pressure is specified at 200 Psig to produce sub-cooled LPG, and NGL is the

bottom product of De-Butanizer column. The NGL product is further cooled to 125 ºF and let

down in pressure to around 50 Psig in order to avoid vaporization in NGL Storage Tank.

LPG product contains 61 mol% C3, 38 mol% C4s, 0.30 mol% C2, and 0.16 mol% (or 0.20 vol %)

C5+. The required specs on C2 and C5+ content of LPG product are as follows: C2 < 0.5 mol%,

and C5 < 1 mol% (or 2 vol %).

7.4 OIL PROCESSING

7.4.1 OIL STABILIZATION UNIT

Un-stabilized oil from Inlet Oil/Gas Separator is processed in this section to produce stabilized

oil with Reid Vapour Pressure below 7 psi. The Oil Stabilization has been split up into two trains

in order to accommodate 20,000 BPD of stabilized oil and each train has been designed to

handle 10,000 BPD of Oil.

7.4.2 OIL FILTERS

Oil from Inlet Slug Catcher (oil) (VS-306-02) is split into two streams and passed through Oil

Filters of Train-1 and Train-2 in order to remove the carried solid particles. A Pressure

Differential Indicator (PDI) across the filter is used to indicate when to change the Filter

Cartridge and switch from filter A to B (and vice versa) and C to D (and vice versa). Filtered Oil

Stream from the filters is routed to Oil Stabilization Unit Feed Drums of Train-1 and Train-2.



7.4.3 OIL FEED DRUM OF TRAIN-1

The oil from Inlet Oil / Gas Separator is flashed to 450 psig and enters Oil Feed Drum. Vapour

and liquid portions get separated inside the vessel, which is designed as a 3 Phase Knock Out

Drum. Vapours exiting this vessel are let down in pressure by 316A PCV-0101A and fed into the

3rd stage suction of (CSO A/B/C).

7.4.4 OIL STABILIZATION FEED/PRODUCT EXCHANGER

The pressure of the liquid stream from oil feed drum is reduced through the level-flow control

valve and enters the tube side of feed product exchanger. It is heated to 183 ºF by the hot

Stabilized Oil product stream which enters the shell side of feed product exchanger at 230 ºF

and is cooled to 118 ºF at the outlet. This crude oil then passes through the Feed/ Product

exchanger.

Actually product of crude oil from low pressure separator is too ho up to 230F. While

temperature of discharge of oil feed tank is up to 99F. So by feed/ product exchanger its

temperature rises up to 183F. For low temperature separator the required temperature is 230F.

By hot oil exchanger temperature is raised from 183F to 230F

7.4.5 OIL STABILIZATION HOT OIL EXCHANGER

The two-phase stream from tube side is routed to E-316A-02 (Oil Stabilization Hot Oil

Exchanger) shell side. Its outlet temperature is increased to 230 ºF by using Hot Oil flowing

through the tube side, and is controlled by the flow rate of Hot Oil through TCV.

7.4.6 OIL STABILIZATION LOW PRESSURE SEPARATOR

The two-phase stream from shell side of hot Oil Exchanger is separated into vapour and liquid

inside (Oil Stabilization Low Pressure Separator). In Oil Stabilization Low Pressure Separator

pressure is controlled at 9 Psig by the pressure control valve on the vapour outlet line.



7.4.7 OIL STABILIZATION OVERHEAD COMPRESSORS

Flashed vapours from V-316A-02 are compressed from 5 Psig to 115 Psig in two stages via Oil

Stabilization Overhead Compressors (OSO).

7.4.8 OIL STABILIZATION OVERHEAD COMPRESSOR LIQUID VESSEL

The Oil Stabilization Overhead Compressor Liquid vessel is designed as a 2 Phase horizontal

vessel to separate gas and light hydrocarbon liquids.

7.4.9 OIL STABILIZATION OVERHEAD COMPRESSOR LIQUID PUMPS

Liquids separated in V-316-01 which comprises of light hydrocarbons are pumped via the oil

Stabilization Overhead Compressor Liquid Pumps to Condensate Stabilization Unit.

7.5 CONDENSATE PROCESSING

7.5.1 CONDENSATE STABILIZATION UNIT

Un-stabilized Condensate from Slug Catcher is let down in pressure from 1500 Psig to 120 Psig

prior to entering Condensate Stabilization Unit where condensate is stabilized to RVP of 12 Psi.

The Condensate Stabilization Unit (comprising of Condensate Stabilizer Feed Drum, LiquidLiquid

Coalescer, Condensate Stabilizer, Condensate Re-boiler and Stabilized Condensate Pumps)

is split into two trains to accommodate 10,000 BPD of stabilized condensate and each train has

been designed to handle 5,000 BPD of condensate.

7.5.2 CONDENSATE FILTERS

Condensate from Inlet Slug Catcher (Gas) (VS-306-01) is passed through Condensate Filters to

remove the carried solid particles. A Pressure Differential Indicator (PDI) across the filter is used

to indicate when to change the Filter Cartridge and switch from the filter A to B (and vice

versa).



Filtered Condensate from the filters is routed to Condensate Stabilizer Feed Drum.

7.5.3 CONDENSATE STABILIZER FEED DRUM

The Condensate Stabilizer Feed Drum (V-317-01) is a three phase separator which receives the

flashed condensate stream from upstream Condensate Filters, and liquids from P-316-01

A/B/C. These two liquid streams are flashed from 1500 Psig to 120 Psig, prior to entering

Condensate Stabilizer Feed. Light Liquid from Condensate Stabilizer Feed Drum is routed to the

Liquid-Liquid Coalescer to reduce the water content in condensate to 0.1 wt% whereas gas is

sent to oil stabilization overhead compressors (CSO).

7.5.4 LIQUID-LIQUID COALESCER

The Liquid-Liquid Coalescer is designed as a Horizontal knock out drum with Boot and in-built

Coalescer plate pack to reduce water content down to 0.1 wt%. Condensate from condensate

feed drum enters Liquid-Liquid Coalescer and is controlled based on a level and flow cascade

control.

7.5.5 CONDENSATE STABILIZER

The Condensate Stabilizer column is used to generate stabilized condensate with Reid Vapour

Pressure of 12 Psi. This Column is equipped with 12 single pass valve trays and a kettle-type re-

boiler. The condensate feed enters the top tray at two phase condition. The liquid portion is

stripped off the light components by the Condensate Stabilizer Re-boiler heat.

7.6.6 CONDENSATE STABILIZER REBOILER

Condensate Stabilizer Re-boiler is designed as a kettle-type Re-boiler in which Hot Oil is used as

heating medium. The Stabilized Condensate flows through shell side and overhead vapour is

further processed by being sent to the cryogenic plant after it is pressurized by Stabilization Gas

Compressors Re-boiler feed is supplied from tray # 12 liquid, and the re-boiler outlet is returned

to the column below the bottom tray. The vapour portion rises along the column, and the liquid

portion is collected in the bottom section of Condensate Stabilizer and being fed into

Debutanizer Tower for NGL processing.



7.7.7 STABILIZATION GAS COMPRESSORS

Flashed vapor are compressed from 85 Psig to 1005 Psig in three stages via Stabilization Gas

Compressors (A/B/C). Each package comprises of Scrubbers (knock out drums) and inter-stage

air coolers.

8. UTILITIES

Utilities includes the following:

8.1 FIRE WATER SYSTEM

Fire water is used in emergency situations. Fire water system provides high pressure water to

every point of plant through underground pipes for emergency situation. Fire water is feed to

two fire water storage tanks each from underground raw water tanks through centrifugal

pumps. If there is no danger of emergency then firewater main pressure maintained by an

electric driven jockey pump. Fire water header is equipped with two low pressure switches,

which on sensing low pressure will start the fire water pumps.

8.2 SLOP VESSEL

Slop Vessel is an underground vessel provided to collect hydrocarbon drains from Flare knock

out drum and from various process equipments. Slop vessel is designed for collecting drain

from largest liquid holding vessel. Two vessels mounted Slop Oil Pumps are provided to transfer

liquid condensate to Condensate Storage Tanks and CPI.

8.3 DECANTING VESSEL

Decanting vessel is present near loading area. It is used rarely only when needed. It is used to

decant condensate from bowzer due to some leakage or other reason. Condensate is decanted

in the slope vessel and from slope vessel condensate is pumped to storage tanks through

centrifugal pump.

8.4 FUEL GAS SYSTEM

The Fuel Gas System is installed to provide fuel gas supply to many units in the plant. The

source of fuel gas is recovered from sales gas main line where it passes through pressure

regulating valve to drop the pressure then enters the fuel gas Knock out drum where entrained

liquid is separated by passing through filters inside it. The Fuel Gas K.O Drum is a vertical



separator which provides gravity settling and retention time, to remove any entrained liquid

mist from the gas. The liquid fell down at the bottom and the fuel gas leaves at the top. This

fuel gas then goes into the fuel gas distribution header. The fuel gas system supplies gas to

following areas:

Domestic users

HVAC heater

Dehydration unit

Booster Compressors

Power Generation System

Hot oil heater

8.5 HOT OIL SETUP

Hot oil is used to provide heating source to different units in both trains of plants. Specific heat

of hot oil is very high and the hot oil used in the plant has excellent thermal properties. When it

is heated to a temperature of round about 470 F then it doesn’t drops its temperature easily. It

is also an economical way of providing heat source to the plant as compared to the direct

combustion or using other fluids such as steam etc.

It has following parts:

Hot Oil Storage Vessel

Hot Oil Fill/Drain Pumps

Hot Oil Expansion Vessel

Hot Oil Circulation Pumps

Hot Oil Cartridge Filter

Hot Oil Heater

8.6 INSTRUMENT AIR SYSTEM

The instrument air provides continuous instrument air to pneumatic transmitters, controllers

and control valves.

Two types of air is produced in this system:

Plant Air

Instrumental Air

Plant air is untreated air which is supplied to plant for different purposes:



Cleaning of Equipment

Drying of Equipment

Instrumental air is a treated air having no moisture and dust particles and used in plant for

pneumatic systems. Instrument air must be available at the required pressure, be free of dirt,

oil and moisture that could condense in the instruments.

The instrument/utility air supply system consists of the following:

Screw type Compressors

K/O Drum

Filters

Absorber

Receiver Vessel

Rotary screw type air compressors supply air from the surrounding for the instrument air

system. The air is compressed where its pressure is increased and raises the air’s relative

humidity and eventually condenses moisture from the air to required pressure. The wet air is

send to K/O Drum for storage and to reduce the pressure fluctuations.

Instrument air is used in the operation of:

BDV

SDV

PCV

LCV

TCV

PRV

8.7 NITROGEN GENERATION UNIT:

Nitrogen is used as a blanket gas in the top of storage tanks. Its inert nature makes it best

option to be used as blanket gas. The Nitrogen Generation Unit consists of:

Compressors

Pre-Filters

Air Receiver Vessel

Nitrogen Generation Units

Nitrogen Storage Vessel



Air is sucked from the atmosphere by compressors. The air is compressed to increase its

pressure to the required pressure. The air flows through pre-filters for the removal of dust and

moisture and then enters into the Wet Air Receiver Vessel which is used for storage of wet air.

The compressed air from the wet air reservoir enters into Nitrogen Generation units. Oxygen

Adsorbent Unit consists of a dual bed PSA Nitrogen generating vessels. Each PSA Nitrogen

generating vessel is filled with a granular carbon beds that adsorbs Oxygen from air passing

through it and leave nitrogen.

8.8 FLARE SYSTEM

Disposal of Gaseous Hydrocarbons is achieved by discharging exhaust gases through Relief

Systems into the Flare System. GPF is provided with separate Hot and Cold Flare System (Cold

Flare System for Cryogenic Section made of Stainless Steel & Warm Flare System for Warm

Services made of Carbon Steel). The cold flare system is also provided in order to prevent the

cooling effects in the line. The Flare System is also facilitating in depressuring the system during

Turn Around or Emergency Shutdown. Discharges of all BDV (Blowdown Valves) are routed to

Flare Header and Flare Knockout Drum before being sent to the Flare Stack. Hydrocarbon Liquid

separated in Flare Knockout Drum is returned to the Closed Drain Header, through the Flare

Knockout Drum Pumps

8.9 FIRE AND GAS SYSTEM

The F&G system will protect personnel and the plant from the effects of Flammable Gases

and Fire. It provides Automatic Audible and Visual Alarms i.e. Flash Beacon and Hooter for

the operator to initiate appropriate actions. Inputs to the Fire and Gas system will consist of Manual Alarm Call Points and Fire &

Combustible Gas Detectors in various parts of the installation where Flammable Gas could

accumulate or fire may be anticipated.

9. LOADING POINT

9.1 STABILIZED OIL STORAGE & LOADING SYSTEM

The Stabilized Oil from the Oil Stabilization low pressure separator is pumped via Stabilized Oil

Pumps and stored in three Stabilized Oil Storage Tanks (A/B/C) of 23,100 Barrels net capacity

each (one in receiving and two in off-loading mode). The tanks shall be equipped with

necessary instrumentation.



The contents of the tanks are transferred to tankers through Five Stabilized Oil Loading Pumps

of 525 USGPM (Rated) capacity each (four operating and one standby). For truck loading, five

Mechanical Loading Arms (four operating and one standby), each having a capacity of 525

USGPM (Rated) at 35 Psig, and a Metering System with necessary instrumentation are also

provided. Oil Decanting Vessel is provided to collect any field slops and emergency draining of

trucks in the loading area. A vessel mounted decanting vessel pump shall be provided to

transfer collected liquid back to oil Storage Tanks.

9.2 LPG STORAGE LOADING SYSTEM

LPG from De-Butanizer Reflux Pumps is stored in Ten LPG Storage Bullets of 2,729.66Bbl Net

capacity each (four in receiving, four in off-loading mode and two are reserve for off-spec LPG).

The Bullets will be equipped with necessary instrumentation. The contents of the Bullets will be

transferred to tankers through two LPG Loading Pumps of 460 USGPM (Rated) capacity each

(one operating + one standby). For truck loading, three Mechanical Loading Arms (A/B/C) (two

operating and one standby), each having a capacity of 230 USGPM (Rated), and a Metering

System with necessary instrumentation are also provided.

10. REVERSE OSMOSIS PLANT

10.1 INTRODUCTION

Osmosis is the transfer of liquid having low impurities to liquid having high impurities separated

by semi permeable membrane. It is a diffusion controlled phenomena. If we provide driving

force for the reverse process by applying pressure more than osmotic pressure, uphill diffusion

can occur. This phenomenon is called reverse osmosis and used for water purification widely in

industries.

Reverse Osmosis (RO) plant at CPF: In 2014, a new RO plant is installed at Central Processing

Facility (CPF) MOL PAK Oil and Gas Co. B.V. It is installed next to Evaporation Ponds; purpose

was to purify the produced water of CPF. MOL Pakistan has rendered the services of Aqua zone

for installing this Plant. Produced water of CPF has almost 40000-45000 ppm total dissolved



solute (TDS). By using RO plant we have to reduce this number at least <500 ppm.

Process is carried out in two steps

10.2 PRE TREATMENT

Pretreatment is done for removing any suspended solid impurities and hydrocarbons in impure

water. It is carried out in following steps

10.2.1 AERATION BASIN

Water from evaporation ponds is pumped to aeration basin. Air is blown into the water through

blowers to fulfill the Biological Oxygen Demand (BOD) and Chemical Oxygen Demand (COD).

Water due to higher density settles down here and oil floats over it. So, here water separates

form hydrocarbons and flow into multimedia tank under gravity.

10.2.2 ANTHRACITE FILTERS

Before filtration water is dosed with chlorine which is a widely used germicide. Anthracite is a

form of coal which has 90 % carbon of the total content. Usually sand and anthracite is used for

filtration. This filtration tank consists of fine anthracite particles in the upper portion and

gravels at lower portion. Anthracite particles can filter any suspended impurity > 10 um. Gravels

bed support the anthracite filter and prevents them to wash away with water. There two

anthracite filters are working at a time. Back washing process is used to remove reject particles

from these multimedia filters.

10.2.3 ACTIVATED CARBON FILTER

Activated carbons mean carbon functional groups that have unsatisfied bonds. Activated

carbon filters consist of beds of Fine particles of activated charcoal. Efficiency of activated

carbon filters depend upon particle size. By decreasing size contact area is increased, so

efficiency also increased. Activated carbon filters are used to removing volatile hydrocarbons,

sediments, odor, and taste by chemical adsorption from water. Typical particle size that can be

removed by carbon filters range from 0.5 to 50 micrometers. Back washing is used for

regeneration.



10.2.4 ULTRA FILTRATION

An ultra filtration filters in Pretreatment is consist of a pore size around 0.02 micron. Ultra

filtration is used to remove solid particles, bacteria’s, some viruses from the system. There are

ten filters are working in CPF RO Plant. After ultrafiltration pretreatment is completed and

water is stored in RO feed tank.

10.3 POST TREATMENT

Water is ready for final treatment in RO feed tank.

10.3.1 CARTRIDGE FILTER

Water is drawn from RO feed tank to cartridge filter by a pump. Cartridge filter separates any

impurities which water may get from the RO feed tank so that RO membranes do not damage.

10.3.2 REVERSE OSMOSIS

RO is the most important part of RO plant. From cartridge filter a high pressure multi stage

centrifugal pump takes suction and takes water is RO membranes, where RO takes place.

10.3.3 RO MEMBRANES

RO membranes are semi permeable molecular membranes made of composite. Typically

Polyamide is deposited on top of polysulfone porous layer woven on top of the non-woven

fabric support. The three layer configuration gives mechanical support and desired properties

of rejection of brine solution. The top polyamide layer is responsible for high rejection and is

chosen primarily for its permeability to water and relative permeability to various dissolved

impurities including salt ions and other small unfilterable molecules. Configuration: There is

various type of configuration in which a RO membrane is assembled.

Plate and frame type

Hollow fiber

Tubular

Spiral wound In CPF RO plant spiral wound RO membranes are used. Spiral RO membranes

are tightly packed filter media. Water to be filtered enters the membrane module from one



end. Once inside the module, filtration occurs when backpressure is applied to drive the clean

water through the membrane surface. Coming out of the module on the other end, you have

clean water (permeate) traveling through the core where it has been collected and

concentrated brine (concentrate). Purified water is used as drinking water and for fire fighting.



11. PLANT SHUTDOWN LEVELS

11.1 LEVEL I OVERALL SHUTDOWN OF FACILITY WITH BLOWDOWN

Level-I emergency leads overall facility shutdown with blow down. This is required in case of

Fire and Gas (F&G) detection or any other acute emergency. Except F&G detectors Level-I

emergency is initiated by operator at his/her own discretion by pressing emergency push

button. In this shutdown, all the ESDVs are actuated and the plant is de-pressurized.

11.2 PLANT SHUTDOWN (PSD) WITHOUT BLOWDOWN

Level-II emergency leads overall facility shutdown without blow down. This emergency is

initiated on operational upsets. In this shutdown, all the BDVs are actuated but the plant

remains pressurized. There is another level of shutdown which only requires the shutdown of

particular equipment for maintenance purposes or other relevant purposes. In that the BDVs

are not actuated.

12. ASSIGNMENTS DURING INTERNSHIP

12.1 DIFFERENCE BETWEEN CENTRIFUGAL COMPRESSORS AND PD

COMPRESSORS

Positive displacement compressors develop high pressure but flow is less. Centrifugal

compressors develop high flow but low in pressure terms.

Positive displacement compressors are used to deliver air with high pressure and in small

quantity. It uses movement of piston to create vacuum inside the cylinder whereas

centrifugal compressor uses blowers or fans to create vacuum and is used to deliver air

with low pressure and in large quantity.



The motion of centrifugal compressors is rotating whereas Positive displacement

compressor has a reciprocating motion.

Centrifugal compressors are constant head machines whereas Positive displacement

compressors are variable head machines.

Centrifugal compressors have a continuous flow whereas Positive displacement

compressors have intermittent flow.

Relatively high compression ratios can be achieved by Positive displacement compressors

(at low flow rates) whereas centrifugal compressors require multistage compressors to

achieve high compression ratios of PD compressors.

Positive displacement compressors have constant volume whereas centrifugal

compressors have variable volume.

Reciprocating compressors are typically used where process fluid is relatively dry whereas

wet gas compressors tend to be centrifugal types.

Centrifugal compressors have the advantage that they are reliable, compact, have a

better resistance to foreign object damage.

Centrifugal compressors have a wide operating curve compared to positive displacement

compressors.

12.2 DIFFERENCE BETWEEN CENTRIFUGAL COMPRESSORS AND CENTRIFUGAL

PUMPS

Centrifugal compressor is a machine for raising gas- a compressible fluid-to a higher level

of pressure. The centrifugal force moves the gas from the rotating impeller to the

stationary diffuser whereas Centrifugal pump is a machine for raising a liquid-a relatively

incompressible fluid-to a higher level of pressure or head.

Both centrifugal compressors as well as pumps operate on a similar principle - rotating

impellers drawing in the gas (in case of compressor) or liquid (in case of pump), and

increasing the velocity of the medium (and often the pressure slightly) and thus providing

a near constant volume at outlet.



The main difference lies in the "compressibility" in the volume of liquid and gas. Liquid is

considered "incompressible" (volume remains constant) when subjected to compressive

forces, while gas is "compressible" (volume decreases when subjected to compressive

force). The word "pumping" connotes "moving" a fluid (usually a liquid) from place to

place without any perceptible change in its temperature but with an increase in the

discharge pressure. Compressors, on the other hand, aside from moving the fluid, also

reduces the volume of the compressible fluid (a gas), with a resulting increase in

temperature and pressure of the fluid at the compressor discharge.

For purely "moving" gases without compression, "blowers" are used instead of

compressors. However, there is always a degree of compression however small that

occurs for blowers since there is a pressure reading at the blower discharge.

Centrifugal pump will move air, not well but most of what make a centrifugal compressor

work exist in the pump. But the pump is so poor at generating head with air it would be

near impossible to pump the air out of a system to draw the water into the suction, thus

the need for priming.

Features are near similar, but since the mediums conveyed are different, the relative

design (such as thickness, slip, angle of attack) etc. can be different for pumps and

compressors.

12.3 RICH BURN AND LEAN BURN ENGINES

12.3.1 LEAN BURN ENGINES

A lean burn engine is an engine which runs on a lean mixture. A lean mixture consists of excess

air and less fuel. The Air to Fuel Ratio (AFR) is greater in lean mixture. Lean burn refers to the

burning of fuel with an excess of air in an internal combustion engine. The excess of air in a lean

burn engine combusts more of the fuel and emits less hydrocarbons. High air–fuel ratios can

also be used to reduce losses caused by other engine power management systems such as

throttling losses. A lean burn mode is a way to reduce throttling losses. The engines designed

for lean burning can employ higher compression ratios and thus provide better performance,

efficient fuel use and low exhaust hydrocarbon emissions than those found in conventional

petrol engines. Ultra lean mixtures with very high air–fuel ratios can only be achieved by direct

http://en.wikipedia.org/wiki/Internal_combustion_engine

http://en.wikipedia.org/wiki/Internal_combustion_engine

http://en.wikipedia.org/wiki/Compression_ratio

http://en.wikipedia.org/wiki/Fuel_efficiency

http://en.wikipedia.org/wiki/Exhaust_gas

http://en.wikipedia.org/wiki/Petrol_engine

http://en.wikipedia.org/wiki/Gasoline_Direct_Injection



injection engines. The main drawback of lean burning is that a complex catalytic converter

system is required to reduce NOx emissions. Lean burn engines do not work well with modern

3-way catalytic converter—which require a pollutant balance at the exhaust port so they can

carry out oxidation and reduction reactions—so most modern engines run at or near the

stoichiometric point.

12.3.2 RICH BURN ENGINES

A rich burn engine is an engine which runs on a rich mixture. A rich mixture consists of excess

fuel and less air. The Air to Fuel Ratio (AFR) is less in rich mixture.

12.4 A COMPLETE ANALYSIS OF THE HVAC SYSTEM

HVAC systems have the following elements in common:

Equipment to generate heating or cooling: The equipment is selected with a capacity to

offset the peak load of the space or spaces to be served.

A means of distributing heat, cooling, and/or filtered ventilation air where needed: air,

water, or steam.

Devices that deliver the heat, cooling, and/or fresh air into the building: registers and

diffusers, hydronic radiators or convectors, and fan coil units.

There are two types of Air Conditioning Systems:

Absorber

Compression

The HVAC system at Karak facility are Absorber type Air Conditioners

12.4.1 WATER-LITHIUM BROMIDE VAPOR ABSORPTION REFRIGERATION SYSTEM In a water-lithium bromide vapor absorption refrigeration system, water is used as the

refrigerant while lithium bromide (Li Br) is used as the absorbent. In the absorber, the lithium

bromide absorbs the water refrigerant, creating a solution of water and lithium bromide. This

solution is pumped by the pump to the generator where the solution is heated. The water

refrigerant gets vaporized and moves to the condenser where it is cooled while the lithium

bromide flows back to the absorber where it further absorbs water coming from the

evaporator.

The water-lithium bromide vapor absorption system is used in a number of air conditioning

applications. This system is useful for applications where the temperature required is more

than 32 degree F.

http://en.wikipedia.org/wiki/Gasoline_Direct_Injection

http://en.wikipedia.org/wiki/Catalytic_converter


http://en.wikipedia.org/wiki/NOx





12.4.2 SPECIAL FEATURES OF WATER-LITHIUM BROMIDE SOLUTION Here are some special features of the water and lithium bromide in an absorption refrigeration

system:

Lithium bromide has great affinity for water vapor, however, when the water-lithium

bromide solution is formed, they are not completely soluble with each other under all

the operating conditions of the absorption refrigeration system. Because of this, the

designer must take care that such conditions would not be created where crystallization

and precipitation of the lithium bromide would occur.

The water used as the refrigerant in the absorption refrigeration system means the

operating pressures in the condenser and the evaporator must be very low. Even the

difference of pressure between the condenser and the evaporator must be very low.

This can be achieved even without installing the expansion valve in the system, since the

drop in pressure occurs due to friction in the refrigeration piping and in the spray

nozzles.

The capacity of any absorption refrigeration system depends on the ability of the

absorbent to absorb the refrigerant, which in turn depends on the concentration of the

absorbent. To increase the capacity of the system, the concentration of absorbent

should be increased, which would enable absorption of more refrigerant. Some of the

most common methods used to change the concentration of the absorbent are:

controlling the flow of the steam or hot water to the generator, controlling the flow of

water used for condensing in the condenser, and re-concentrating the absorbent leaving

the generator and entering the absorber.

12.4.3 COMPONENTS

12.4.3.1 GENERATOR

Heat energy from hot water is used to boil a dilute solution of lithium bromide and water.

This boiling results in release of water vapor, and in concentration of the remaining lithium

bromide solution. After exiting the heat exchanger, the solution moves in to generator and is

sprayed over a bundle of tubes carrying hot water. The hot water transfers heat to the

surrounding dilute lithium bromide solution. The solution begins to boil sending refrigerant

vapour in to the condenser leaving behind concentrated lithium bromide.

The concentrated lithium bromide solution flows back down to the heat exchanger where it is

cooled by the weak solution.

12.4.3.2 CONDENSER



The refrigerant vapour flows around a mist eliminator plate up to the condenser tube bundle. It

condenses on the external surface of the tube bundle and the heat of condensation released is

removed by the cooling water flowing through the tubes. As the refrigerant condenses it

collects in a trough at the bottom of the condenser.

12.4.3.3 EVAPORATOR

The refrigerant liquid flows from the condenser to the evaporator. Due to the extremely high

vacuum (6 mm Hg absolute pressure) the refrigerant liquid sprayed over the evaporator tubes

evaporates at 3.9°C, creating the refrigerant effect. This high vacuum is maintained by the

hygroscopic effect in the absorber below.

12.4.3.4 ABSORBER

As the refrigerant vapour migrates from the evaporator to the absorber, the concentrated

solution is sprayed in to it. This is driven by the high pressure difference, as the pressure in the

generator/condenser section is about ten times higher than in the evaporator/absorber

section. The lithium bromide solution absorbs the refrigerant vapour, creating the extremely

high vacuum in the evaporator. The absorption process releases heat which must be removed

by the cooling water. The now diluted lithium bromide solution collects on the bottom of the

absorber and the process begins again

12.4.3.5 BOILERS

There are two boilers present at HVAC system, which supplies water at 100 degrees Celsius.

There supply line is connected to the generator portion of the chiller.

12.4.3.6 COOLING TOWER

An HVAC cooling tower is used to dispose of unwanted heat from a chiller. Water cooled

chillers are normally more energy efficient than air cooled chillers due to heat rejection to

tower water at or near wet bulb temperatures

An HVAC cooling tower is used to dispose of unwanted heat from a chiller. Water cooled

chillers are normally more energy efficient than air cooled chillers due to heat rejection to

tower water at or near wet bulb temperatures.



12.4.3.7 INTERMEDIATE SOLUTION PUMP

The diluted lithium bromide

solution is collected at the bottom

of the absorber. A completely

hermetic solution pump pumps the

solution through a shell and tube

heat exchanger for preheating. The

intermediate solution used at CPF

have following composition.

Lithium Bromide: 2300 kg

Water: 600 liter

Alcohol: 3.5 liter

Nitrate: 6 liter

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