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5MOL PAKISTAN OIL & GAS Co. B.V. MANZALAI CPF
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
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6MOL PAKISTAN OIL & GAS Co. B.V. MANZALAI CPF
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
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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.
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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.
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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
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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.
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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.
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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.
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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.
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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
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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)
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6.3.1 SEPARATION
6.3.1.1INLET 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
6.3.1.2MERCURY 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
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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:
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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.
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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
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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
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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.
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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.
6.3.3.3JOULE 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.
6.3.3.4LOW 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
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24MOL PAKISTAN OIL & GAS Co. B.V. MANZALAI CPF
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
6.3.3.5BTAX 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.
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6.3.3.7SALE 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
6.3.3.8MOISTURE 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.
6.3.3.9GAS 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.
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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:
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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
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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:
Inlet temperature = 85 °F
Outlet temperature = 190 °F
Hot condensate:
Inlet temperature = 280 °F
Outlet temperature = 140 °F
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
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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
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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
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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.
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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
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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)
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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.
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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.
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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.
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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.
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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
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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-
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40MOL PAKISTAN OIL & GAS Co. B.V. MANZALAI CPF
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.
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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.
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42MOL PAKISTAN OIL & GAS Co. B.V. MANZALAI CPF
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).
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43MOL PAKISTAN OIL & GAS Co. B.V. MANZALAI CPF
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.
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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
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45MOL PAKISTAN OIL & GAS Co. B.V. MANZALAI CPF
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:
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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
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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.
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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
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49MOL PAKISTAN OIL & GAS Co. B.V. MANZALAI CPF
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.
