Internship Report

MUHAMMAD ALI
PETROLEUM & GAS ENGINEERING
DAWOOD UNIVERSITY OF ENGINEERING & TECHNOLOGY,
KARACHI.
INTERNSHIP REPORT OF ZARGHUN GAS FIELD
INTERNSHIP DURATION: JUNE 9TH TO JULY 20TH 2016

ZGF Internship Report Page 2
Table of Content
S.NO. Topics Page No.
1 Token of Appreciation 3
2 Learning outcomes 4
3 HSE Philosophy 5
4 About Field 6
5 Different type of valves 7-9
6 Pipeline Quality Specification 9
7 Christmas Tree 10-11
8 Tubing Accessories 11-15
9 Well head Facilities 16-17
10 PSP Survey 18-21
11 Daily log Activities (1-10) 22-26
12 Production Separators 27
13 Degassers 27-28
14 Flash knock out Drum 29
15 Water Bath Heater 30-31
16 Hot oil System 31-33
17 Reverse Osmosis 33-34
18 Amine Sweetening unit 35-39
19 Gas Dehydration unit 40-43
20 Hydrocarbon Dew Point unit 43-44
21 Fuel Gas Scrubber 44-45
22 Sales Metering Skid 45-47
23 Instrument Air System 48
24 Fire Water System 48-50
25 Accessories 50
26 Power Generation System 51-52
27 Compressors 52-53

TOKEN OF APPRECIATION
Starting with the name of Almighty Allah Who is the most merciful and beneficent, whose entity
is beyond our intellect. I am very grateful to Allah for providing me the strength, health and gave
me persistent determination in every stage of my life. Parents are also one of the precious gifts of
Allah; I cannot express their support in my words.
I am very kindful to the HR manager of Mari Petroleum Company Limited (MPCL) who
approved of my request for internship. I am thankful to Incharge Zarghun Mr. Khalid & Mr.
Rasool Baksh who motivated me at every step. I recognize the service of Mr. Hasan Mehmood &
Mr. Inam Shah, Health & Safety Environment advisor who delivered me a brief orientation on
company QHSE Policy in the commencement of my internship.
I would like to thank Engr. Muhammad Jahanzaib, Production Engineer who spent his precious
time with me throughout my internship & guided me in a pave way. It was an honor for me to be
a part of his patronage. I acknowledge the efforts of Engr. Umar Ahsan & Engr. Kaleemullah
kasi, Trainee Engineer Production who taught me several things whenever I asked from them.
With my core heart, I would like to appreciate the sincere efforts of Mr. Umar shaukat, Mr.
Ghulam Khaliq & Mr. Tumbail Marri, Chemical Engineers who helped me in understanding the
whole process involved in the field.
I am also grateful to Mr. Waleed Murad & Mr. Latif Bhutto, Generator operators who gave me
the surficial knowledge of power generation system.
I am kindful to Mr. Muhammad Ali, Mechanical Technician who taught me the working
involved in instrument air & gas compressors.
I also appreciate the services & knowledge imparted to me by the process operators including
Mr. Ghulam Shabbir, Mr. Muhammad Waqas, Mr. Omar Farooq, Mr. Shahid Qurban, Mr. Irshad
Gul, and Mr. Saeed who were present on site & supported me during the entire duration of my
internship.
I acknowledge the efforts of Zia staff members who provided me healthy meal throughout my
internship.

LEARNING OUTCOMES
Internship is a short-term program offered by company to explore the areas which accomplish in
increasing practical knowledge. Internship is a prolific way to acquire the practical knowledge
which is applied in the industry.
The main assessment of internee is to adjust himself in the environment of industry. It was a
prestigious opportunity for me to learn the methodologies of production & process department.
The aim of my internship was to acquire the technical aspects involved in process. To understand
the function of components involve in down hole assembly was first prioirty which I had knew. I
am got awared about well head facilities. I accomplished in acquiring the knowledge about 3
phase separator. I was also involved in the daily activities. I got the chance to understand the
practical implementation of Amine sweetening unit process.
Another priority was to get knowledge about Gas Dehydration unit & to memorize the process
flow diagram (PFD). Although, Hydrocarbon dew point unit was not alive but due to the
presence of that unit, I successed to know it’s working. I was curious to know the procedures
which are under consideration in reducing the environmental hazards. I am awared about the
working phenomena of instrument air & gas compressors.
On completing my task, I am feeling much more confident and self-motivated. All my instructors
had an excellent and sound knowledge about their respective areas which helped me to learn
many things. Working with MPCL was the turning point of my student life. The company also
taught me the moral values. It was a remarkable exposure for me to work with one of the
renowned companies in oil and gas.
I realized a sense of intimacy from my seniors which assisted me to feel free in the environment
of well site. Other employees of company were also very kind to me .They helped me with my
every query, I asked. I am looking forward to grasp more opportunities in near future in this
esteemed company.

HSE Philosophy
HSE Philosophy plays a pivotal role to minimize the risk and the consequences of accidental
events. Adequate fire protection systems (Fire hydrants, fire water pumps, fire monitor)is provided
to rapidly detect, control and extinguish any reasonably foreseeable fire which could develop
during normal operation. Fire extinguishers are available which can protect personnel in any fire
incident. Mustard points are arranged where personnel can gatherin the case of any alarming
situation. Wind socks are provided to know the direction of wind. UA/UC (unsafe act/unsafe
condition) is strictly implemented. First aid center for immediate delivery of first aid to injured
person is established inside the plant, functioning under a qualified doctor. Personnel protection
equipment (PPEs) like cover all, hard shoes, gloves, safety glasses & hard helmet is provided to all
the employees and visiting staff for plant operation / visit. Telephone No. of nearest fire brigade is
displayed for emergency contact. Ambulance / vehicle for transportation of injured person are
available at plant. Hazardous gases are present with greater ppm which can cause high damage. It
is the routinely job to check H2S and LEL levels while performing walk around inspection and
take readings. If H2S levels are detected above 10 PPM, self-contained breathing apparatus is
necessary to wear. 3 SCBA is deployed in different places. Fire alarms will ring in the event of any
emergency. Wild life are present in bulk amount on the plant so personnel should beware &
vigilant during activity on plant.
Effects of H2S on the Human body at various concentrations
Sour gas or Hydrogen Sulphide (H2S) is a highly corrosive and extremely toxic gas. It is colorless
and smells like rotten eggs. In the higher concentrations it will kill your sense and impede your
ability to detect it.
The below table shows the concentration of H2S of different parts per million (ppm) with their
effects:
H2S Concentration Effects
1 ppm (0.0001 %) Detectable “rotten eggs” odor.
100 ppm (0.01 %) Kills sense of smell in 3 to 5 minutes.
200 ppm (0.02 %) Kills sense of smell rapidly.
500 ppm (0.05 %) Loss of reasoning ability and sense of balance.
700 ppm (0.07 %) Rapid loss of consciousness and breathing.
1,000 ppm (0.10 %) Immediate unconsciousness.

About Field
Zarghun field is located in the Baluchistan province of Pakistan approximately 52 km north-east
of Quetta city in Harnai district. This Asset is sharing amongst four JV Partners. Spud Energy is
holding the largest share of 40%, MPCL has 35%, and GHPL & PKP has shares of about 17.5%
respectively. 1st
well ZS-1 was spud in 1998 while ZS-2 was spud on dated. December 31st
1999.
ZS-3 is under construction process.
According to Specification on Raw Gas metering skid:
 Design pressure= 715 Psi
 Design temperature=138 °F
 Flow capacity (maximum) =15 MMSCFD
Features Zarghun South-1 Zarghun South-2 Unit
Original Gas in Place 102 BCF
Recoverable Reserves 76.2 BCF
Reserves Utilized 8.0 BCF
Produced gas 5.718 3.877 9.587 MMSCF/Day
Sale gas 5.224 3.547 8.772 MMSCF/Day
Heating value 913 902 BTU
Pressure (Psig) 902 534 Psig
Moisture 100 150 Lb/MMSCF
Water production 260 140 Bbls
Condensate production 3 1 bbls
H2S Quantity 450 1250 Ppm
Formations Mughal kot& Chilton
Limestone
Dunghan Limestone -
SSSV 92 No Meters
Producing from WREG & Perforated
Pup
Both SSDs -
Operated choke size
(Adjustable)
36/64 40/64 Inches
Nature of Reservoir Conventional
(Gas)
Unconventional
(Tight gas)
-
Geometry of well bore Inclined Vertical -
Inclination Angle 32°at 1663 m - Degree, meter
TD 2172 2720 mRTKB
PBTD 2130 1980 mRTKB
EOT 1847 1926 mRTKB
Line Pressure 429.94 429.93 PSIG
Line Temperature 94.72 91.92 °F
Differential Pressure 19.65 11.44 In H20

Different Type of Valves
Gate valves: In the fully opened position, Gate valves are designed to
minimize pressure drop across the valve and completely stop the flow of
fluid. The direction of fluid flow does not change, and the diameter
through which the process fluid passes is essentially equal to that of the
pipe. Hence, they tend to have minimal pressure drop when opened fully.
 Rising Stem: The stem rises when valve operates.
 Non-Rising Stem: A pointer threaded onto the upper end of the stem. When gate valve
travels up or down the stem on the threads without raising or lowering the stem.
Globe valves: A globe valve is a linear motion valve used to stop, start
and regulate flow. Conventionally used for isolation and throttling
services. With a good shut off ability, available in tee, wye and angle
patterns and easy to machine the valve seats - it’s easy to see why they
are so popular. The slight disadvantages of the globe are that they
perform unfavorably when high pressure drops, and require greater
force or throttling flow under the seat to shut off valve.
Butterfly valves: A quarter-turn rotational motion valve, the
butterfly valves is used to stop, start and regulate flow. Easy
and fast to open, the valve usually comes equip with a gearbox
where the hand wheel by gear is connected to the stem.
Ball valve: It is a form of quarter-turn valve which uses a
hollow, perforated and pivoting ball (called a "ball") to control
flow through it. It is open when the ball's hole is in line with the
flow and closed when it is pivoted 90-degrees by the valve
handle. The handle lies flat in alignment with the flow when
open, and is perpendicular to it when closed, making for easy
visual confirmation of the valve's status. They are better for
on/off control without pressure drop.
The two types of Ball valve are:
 Reduced bore: The valve opening is smaller than the diameter of piping.
 Full bore: The valve opening is same as the diameter of piping.

Pressure Relief Valve - is the term used to describe relief device on a
liquid filled vessel. For such a valve the opening is proportional to
increase in the vessel pressure. Hence the opening of valve is not
sudden, but gradual if the pressure is increased gradually.
Pressure Safety Valve - is the term used to describe relief device on
a compressible fluid or gas filled vessel. For such a valve the opening
is sudden. When the set pressure of the valve is reached, the valve
opens almost fully.
Control valves are used to control conditions such as flow,
temperature & liquid level by fully or partially opening or closing in
response to signals received from controllers that compare a set point to
a process variable whose value is provided by sensors that monitor
changes in such conditions.
Blow Down valve (BDV): valves designed for operation in open
position. Their function is mainly to control a continuous flow of steam
and/or water under high differential pressure. It can depressurize the
plant/bleed the excess pressure and send to flare.
Shut Down valve (SDV): (also referred to as SDV or Emergency
Shutdown Valve, ESV, ESD, or ESDV) is an actuated valve designed
to stop the flow of a hazardous fluid upon the detection of a
dangerous event. This provides protection against possible harm to
people, equipment or the environment. Shutdown valves form part of
a Safety Instrumented System. The process of providing automated
safety protection upon the detection of a hazardous event is
called Functional Safety.

Needle Valve is a type of valve having a small port and a threaded,
needle-shaped plunger. It allows precise regulation of flow, although it
is generally only capable of relatively low flow rates.
Plug valves are valves with cylindrical or conically tapered "plugs"
which can be rotated inside the valve body to control flow through the
valve. The plugs in plug valves have one or more hollow passageways
going sideways through the plug, so that fluid can flow through the plug
when the valve is open.
S.NO. Pipeline Quality Specifications
Component Quantity Units
1 CO2 <3 mole %
2 Gas Temperature < 125 °F
3 Calorific Value >920 BTU/SCF
4 H2O < 7 Lb/MMSCF
5 H2S < 4 ppm
6 Pressure 450-500 PSI
7 Wobbie Index > 1150 BTU/SCF
8 Gas Dew Point Temperature <32 °F

Christmas Tree (Often Known As X Mass Tree)
It is an assembly of valves and fittings which forms the top of the completion. It is connected to
the tubing hanger spool and directs the flow of fluids from the production tubing into the
production flow line. It also provides vertical access to the production tubing(s) for well servicing
and side access to the production tubing(s) for pumping services, i.e. well kill, circulation and
chemical injection facility.
Christmas tree Cap
It provides the connection for vertical well servicing equipment such as a wire line lubricator,
injection head and rod BPV lubricator which are installed directly above the swab valve. The
Christmas tree cap normally has a quick union type connection and is capable of supporting the
lubricator stresses encountered in well servicing operations. The inside diameter of the cap is
compatible with the tree bore and tubing to accommodate the largest size tools which can be run.
Needle valve pressure gauge
During normal production, the cap has a plug in situ with a threaded part to accommodate a needle
valve pressure gauge. This gauge is used for periodic visual checking of well pressure. The needle
valve is used to bleed off trapped pressure above the swab before removing the plug.
Upper master valve (UMV)
The UMV is used on moderate to high pressure wells as an emergency shut- in system. Company
policy is that the valve must be capable of cutting at least 7/32 " size braided wireline. The valve
can be actuated pneumatically or
hydraulically. The UMV valve is a surface
safety valve and is normally connected to an
emergency shut -down (ESD) system.
Flow wing valve (FWV)
The FWV permits the passage of well fluids
to the choke. This valve can be operated
manually or automatically (pneumatic or
hydraulic) depending on whether is to be
included in the surface safety system design.
On moderate to high pressure wells, often
two production wing valves are usually
installed one manual and the other equipped
with a valve actuator.

Choke valve
The choke valve is used to restrict, control or regulate the flow of hydrocarbons to the production
facilities. This valve can be operated manually or automatically and may be of a fixed (positive) or
an adjustable type valve. It is the only valve on the Christmas tree that is designed and used to
control flow. All other main valves are invariably gate type valves, although needle valves are used
on instrumentation and chemical injection lines.
Kill wing valve
The Kill Wing Valve permits entry of kill fluid into the completion string and also for pressure
equalization across tree valves e.g. during wireline operations or prior to the pulling or opening of
a sub- surface safety valve. The kill wing valve is usually operated manually.
Swab valve
It permits vertical entry into the well for well servicing such as wireline (slick line and electric
line), coiled tubing. It is also used for BPV installation n in the tubing hanger. This valve (often
referred to as the lubricator valve) is operated manually and is the uppermost valve on the
Christmas tree.
Tubing Accessories
Tubing
A single length of the pipe that is assembled to provide a conduit through which the oil or gas will
be produced from a wellbore. Tubing joints are generally around 30 ft (9 m) long with a
thread connection on each end.
Tubing Hanger
It is equipment attached to the casing spool used to hang the tubing and seal the annulus between
the tubing and casing. Hangers are run through the blowout preventers and are landed in the top
bowl of the tubing head. Tubing hangers also act as a means to access and manipulate additional
smaller tubing lines that are utilized down hole and extended to the surface on the outside of the
tubing string or strings.
Seal bore extension
A seal bore extension is used to provide an additional sealing bore when a longer seal assembly is
run to accommodate large tubing movements induced by changes in temperature and pressure
during pressure testing or production conditions. The seal bore extension is run below the packer
and has the same ID as the packer.

Sliding Side Door (SSD)
It Sleeve is installed in the tubing during well completion to
provide a communication path between the tubing and the
annulus when it is opened. It is used to: bring a well onto
production after drilling or work over by unloading, (i.e.
circulating the completion fluid in the tubing out with a
lighter fluid), kill a well prior to pulling the tubing during a
work over operation (reverse of the previous) and allow
selective zone production in a multiple zone well
completion.
SSDs and other tubing string wire line operated completion
components should be spaced out at least 10m (30ft) apart to
prevent accidental operation of the wrong component.
Separation Sleeve: It is located in the B Nipple at the place
of SSSV so that the polish bore may not be damaged.
Side Pocket Mandrel (SPM): Chemical injection valve
(CIV) is fitted with the help of Kick off tool (i.e. Component
of slick line). The mixture of condensate & corrosion
inhibitor is sprinkled upon the upcoming fluid stream which
forms a thin layer along tubing string as it moves upward.
Landing Nipples
They are tubing string components designed to
accommodate the installation of various wire line retrievable
flow control devices. The most common flow controls are
plugs, standing valves, chokes, pressure and temperature
gauges and storm chokes. Tubing hanger for pressure
testing Christmas tree and plugging for barrier protection
when working on the wellhead. SCSSSV top sub for
installation of an insert valve, leak finding and back up
plugging position for barrier protection. At SSSV depth for
installation of a storm choke. Bottom of tubing string for
pressure testing tubing string. Below packer in packer
tailpipe for setting and/or pressure testing packer and string
during installation, leak finding and plugging for barrier
protection. Below perforated tubing joint to catch any
dropped tools and for installation of BHP gauges.

Flow Couplings
In high flow rate wells flow couplings are installed above (and sometimes below) flow control
devices, including SSDs and SCSSSV landing nipples, in the completion string to protect against
internal erosion caused by flow turbulence. To allow erosion a heavy-walled tubular is run above
& below the nipple.
Blast joints
They are installed opposite perforations (Non gravel packed) where external cutting or abrasive
action occurs caused by produced well fluids or sand. In actual fact they perform the same task as
flow couplings but protect against external erosion. They are constructed from a heat treated alloy
material and are heavy walled tubular. Blast joints are usually available in 10, 15, and 20 ft
lengths. Completion designs should ensure that blast joints extend at least 4 ft on either side of a
perforated interval.
Re-Entry Guide (REG)
Half mule shoe is a type of REG which has shoulder of 45°, located on the bottom of tubing which
set through wireline job. It provides an easy path when retrieving any tool.
Pup Joint
The pup joint is a short length of tubing having the same specifications as of the tubing to be used
in completion string. The main purpose to use this pup joint at this place is to provide a length or
housing to keep the pressure gauges hanging from the bottom no-go nipple inside the completion
string.
Top No-Go Nipple
It is a short tubular device with an internally machined profile with exactly same specifications as
of the bottom no-go nipple. The basic purpose is to provide an internal profile for plugs to be
seated. It is also known as F nipple.
Bottom No-Go
A nipple that incorporates a reduced diameter internal profile that provides a positive indication of
seating by preventing the tool or device to be set from passing through the nipple. It is also known
as R nipple. The basic difference between the two nipples is the lesser ID of bottom no-go.
Cross over (X-over)
It is used to join the two equipment which have different threaded connections.

Spacer Tube
It provides the accommodation to Bottom & Top No-Go nipple. It is located above Top No-Go &
on the bottom of Bottom No-Go.
Perforated Joint
It may be incorporated in the completion string for the purpose of providing bypass flow if bottom-
hole pressure and temperature gauges are used for reservoir monitoring. It is located between Top
No-Go & Bottom No-Go nipples.
Mill-Out Extensions (MOE)
It provide a large ID below the packer seal-bore, which allows a single-trip packer milling tool to
be used when tubing is run blow the packer assembly. It is a pup joint used to provide additional
length and inside diameter necessary to accommodate a standard milling tool. The outer diameter
(OD) of MOE is greater than Seal bore extension (SBE).
Production packer
It is a sub-surface component used to provide a seal between the casing and the tubing in a well to
prevent the vertical movement of fluids past the sealing point, allowing fluids from a reservoir to
be produced to surface facilities through the production tubing. Retrievable packers are generally
lowered into the well bore attached to and as an integral part of the production tubing string. As the
name implies, retrievable packers can be recovered from the well, usually be applying pull to the
tubing. Permanent packers can be lowered into the well bore and set on an electric wireline or on
tubing after which the wireline or tubing is released from the packer mechanically. When set,
permanent packers may be considered as an integral part of the casing and can only be removed
from a well by milling through the slips, thus releasing the grip on the casing.
Locator Seal Assembly (LSA)
A system of seals arranged on the component that engages in a seal-bore to isolate the production-
tubing conduit from the annulus.
Centralizer
In highly deviated wells, these components may be included towards the foot of the completion. It
consists of a large collar, which keeps the completion string centralized within the hole.
Sub-surface safety valve (SSSV)
Primary purpose is shut-in of the well in event of loss of surface wellhead integrity.

SSSV Installations
There are two main versions of surface controlled sub-surfacesafety valves: Wire line retrievable
safety valves run and installed in a wire line nipple in the completion string after the completion
have been landed, tested and the Christmas tree installed. Tubing retrievable safety valves is
installed as an integral part of the completion string. When this valve is not capable to hold the
pressure it opens by permanent lock, dogs are broken & insert type is accommodated in it which is
opened by HOT (hole opener tool).
Flapper valve mechanism
During actuation, the flow tube moves downwards and mechanically opens the flapper system.
Reverse of the above action closes the flapper valve; closure is initially assisted by the flapper
spring and then by well pressure. This flapper closure system has a metal -to-metal 'hard' seat for
high pressure sealing and a 'soft' seat for low pressure sealing.
Ball valve mechanism
The assembly consists of the ball, seat, control arms, sleeve weldment and alignment pins; the ball
is provided with slots to accommodate the drive pins. The ball and seat assembly provides a metal-
to metal sealing system and is the primary seal to well pressure below the safety valve when
closed. Downward movement of the valve seat and control arms within the sleeve weldment will
move the ball downwards. When the sleeve weldment butts up against the lower assembly, a 90°
rotation of the ball will have occurred moving it to the open position. The rotation is due to the
slots in the ball acting on the drive pins. When hydraulic pressure is removed the spring pulls back
the ball, assisted by any well pressure, hence reversing the opening action. Additional force from
well pressure will assist in making a pressure tight seal.

Wellhead Facilities
There are two wells (ZS-1 & ZS-2) and both wellheads consist of following facilities:
Wellhead Control Panel
Wellhead control panel is hydraulically operated taking signals directly from pressure sensing
line which activates the PSHH (600 psig) and shutdown the well in case of higher than expected
pressure. WHCP will also shut down the well on activation of PSLL (300 psig). Pneumatic
wellhead instruments are operated by instrument gas taken from the wellhead flow line via
Instrument Gas Scrubber. WHCP can only be operated from the individual well site.
Parameters ZS-1 (Psig) ZS-2 (Psig)
Regulated Panel supply Pressure 94 102
Fusible loop Pressure 53 75
ESD Pressure 53 74
SCSSV Control Pressure 4900 -
SSV Control Pressure 98 1300
Flow line Pressure 500 460
Hydrate Inhibitor Injection Skid
For the inhibition of hydrate formation in the flow lines, Methanol injection skids are provided at
both wellheads. Methanol will be injected upstream of choke valves. Hydrate Inhibitor injection
system comprises of a hydrate inhibitor storage tank, gas driven hydrate inhibitor injection
pumps and necessary instrumentation and piping. Gas for driving the injection pumps will be
taken from the Instrument Gas Scrubber. The rate of 5 gallon is injected per day.
T-0401 (Hydrate Inhibitor Tank)
Capacity (Liters) 1700
Diameter (mm) 1200
Length (mm) 1710
P-0401 (Hydrate Inhibitor Injection pump)
Flow Rate (Lit/Day) 545
Operating pressure (Psig) 1320
Corrosion Inhibitor Injection Skid
Corrosion Inhibitor chemical is injected at ZS 2 wellhead downstream of choke valve during
normal operation. Permanent corrosion inhibitor injection skid is provided at ZS 2 because
carbon steel is used to transport the gas from ZS 2 location to Plant which is 2.8 km in distance.

The skid mounted package consists of corrosion inhibitor storage tank, gas driven corrosion
inhibitor injection pumps, necessary piping and instrumentation. Instrument Gas Scrubber will
supply the gas for driving the injection pumps. The capacity of storage tank is 250 liters. The rate
of 9 liter is injected per day.
Fuel Gas Scrubber
It is placed on ZS-2 to supply gas in order to driven well head control panel. The operating
Design pressure of Fuel gas scrubber is 260 psig & operating pressure is 135 psig. The design
temperature is 150°F.
Pig Launcher & Receiver
Pigging in the context of pipelines refers to the practice of using devices known as "pigs" to
perform various maintenance operations. This is done without stopping the flow of the product in
the pipeline.
These operations include but are not limited to cleaning and inspecting the pipeline. This is
accomplished by inserting the pig into a 'pig launcher' (or 'launching station') - an oversized
section in the pipeline, reducing to the normal diameter. The launcher / launching station is then
closed and the pressure-driven flow of the product in the pipeline is used to push it along down
the pipe until it reaches the receiving trap – the 'pig catcher' (or 'receiving station').
Both wells have independent scraper launcher & receiver for pigging flow lines. Launcher is
installed at well location for ZS-2 and near raw metering skid for ZS-1. A receiver is located at
Gas Processing plant.

Back ground of PSP Survey in ZS-I
The Production logging job was performed because large volumes of water were produced from
ZS-I. The estimated water production was 430-440 bbl. /Day.
Water production is very expensive because it limits hydrocarbon production and has to be
treated and disposed of safely. Locating the source of the water production is vital towards
planning remedial work in wells that produce water.
PSP Survey was scheduled on the dated 20th
, 21st
, 22nd
, 23rd
June. This job was conducted in two
phases by two service companies. Slick-line job was performed by NWSL (Neuricon wire-line
service limited) while wire-line job was performed by Schlumberger.
Objectives of PSP Survey
The job was performed to meet the following objectives:
1) Establish tubing clearance by RIH gauge cutter (O.D 1.72’’)
2) Conduct PLT Survey during shut-in & flowing conditions to achieve following targets:
 To identify cross flow between different sets of perforations/reservoirs during shut-in &
flowing conditions.
 To identify water production contributing intervals.
 To quantify reservoir fluid (water/gas/oil) entries from perforated intervals.
 To perform shut in pressure analysis for estimation of reservoir pressure of Chilton &
Mughal Kot formations.
 To determine zonal contribution of producing fluids (Oil, Gas & water) across the perforation
intervals at 20/64’’, 28/64’’ & 36/64’’ chokes.
After determining these parameters, further strategies were supposed to make which could
minimize the water production.
First Phase: Slick-line job
Slick-line job was performed by NWSL on June 20th
2016.
Slick-line looks like a long, smooth, unbraided wire, often shiny, silver/chrome in appearance. It
comes in varying lengths, according to the depth of wells in the area it is used (it can be ordered
to specification) up to 35,000 feet in length.
Clearance up to 2092 m was established with slight restriction at 1970 m. The reason behind this
restriction was anticipated that there might be presence of any slug (During production some
quantity of heavier HC’s could be not be produce which can forms a scale in well bore).

Assembly used in Slick-line Job
1. Gauge cutter (O.D 1.72’’)
2. 2 Stem bar (each 5’)
3. Stem bar (3’)
4. Mechanical jar(6.5’) with 30 Strokes
5. Knuckle joint Note: Rope socket & knuckle joint (total 1.5’)
6. Rope socket
7. Stuffing box
8. Hay Pulley
9. 3 Riser/Lubricator (each of 8’=24’)
10. Pressure Equipment
11. BOP
12. Slick line (O.D 0.108’’, Size 1 1/2’’&Weight 1500 lb.)
Weight Calculation
 Total weight of stem bar
 1’=6 lb.
 13’x 6=98 lb.
 Rope Socket to Gauge cutter= 21’
Description of Equipment used in Slick line job
Stuffing Box: It holds the wire & don’t allow hydrocarbons to escape. It contains rubber sleeve
located on the upper side of lubricator.
Hay Pulley: It is used to keep the wire straight. Its hanging angle must be 90° which indicate the
weight accurately.
Knuckle Joint: It can provide flexibility up to 15° to BHA.
Stem/Sinker Bar: It serves to add weight to the tool string. The weight may be necessary to
overcome the pressure of the well. In the above assembly extra stem is installed for the safety of
Mechanical jar.
Mechanical Jar: This type of tool can be extended & closed rapidly to induce a mechanical
shock to the tool string. This shock can induce certain components such as plugs to lock into
place & then unlock for retrieving. Jars are commonly used to shear small brass or steel pins that
are put in place to function certain down hole tools at a certain moment.
Rope Socket: The wire is inserted in it.

Lubricator: The components i.e. Rope socket, knuckle joint, stem & mechanical jar are placed
inside it.
Pressure Equipment: It is the combination of BOP, Lubricator & Stuffing box.
At Every 1000 m pull test was conducted, to check the weight of string if in the case it struck, it
will take more weight. Datum point was RTKB: 29 feet.
Depth (meters) Weight (Pounds)
1000 32
2000 135
3000 190
4000 240
5000 285
Wrap Test: To know the strength of slick line, two strings are spooled on each other, rise in
temperature 120°F is given, if wire gets cut before 21 wrap, the strength of line is not
appropriate.
Wire line job
Main PLT Run was conducted 22nd July, 2016 however due to telemetry issues and instrument
fault; data could not be read/recorded. POOH PLT tools function test on surface again and RIH
but problem persisted. Full-bore flow meter and telemetry joints were replaced. RIH but no
success achieved. POOH PLT tool string, R/D wire line BOP and cross.
Assembly used in Wire -line Job
1. Tool catcher
2. Grease Injection head
3. Stuffing box
4. Line vapor (For cleaning of wireline& pullout)
5. Wireline
6. Cable head (O.D 5/16’’)
7. Stem/Sinker Bar
8. Telemetry Production Roller Centralizer
9. Gamma Radioactive Ray element
10. Casing collar locater Production Roller Centralizer
11. Quartz Pressure Sensor flow meter
12. Inline flow meter
13. Platinum Resistance Thermometer
14. Fluid Density Radioactive
15. Capacitance Water hold up
16. Spinner flow meter

17. 5 Riser
18. Tool catcher
Description of Equipment used in wireline job
Grease Injection head: Grease is continuously injected for lubrication purpose.
Stuffing box: It holds the wire & don’t allow hydrocarbons to escape. It contains rubber sleeve
located on the upper side of lubricator.
Line vapor: To clean the wireline during pullout.
Cable head (O.D 5/16’’): A cable is inserted with in it.
Stem/Sinker Bar: It serves to add weight to the tool string. The weight may be necessary to
overcome the pressure of the well.
Telemetry: It senses temperature & pressure, provide command forward & backward.
Production Roller Centralizer: It keeps the whole BHA in center having 4 arms.
Gamma Radioactive Ray element: A source is used to correlate the depth.
Casing collar locater: It is used in Depth Correlation.
Quartz Pressure Sensor flow meter: It Senses the pressure of down hole.
Inline flow meter: A hard fan which estimate the flow.
Platinum Resistance Thermometer: It Senses the down holetemperature.
Fluid Density Radioactive: It is used to detect the density fluid & formation.
Capacitance Water hold up: Estimate the accumulation of liquid within the well bore.
Spinner flow meter: A Sensitive fan which estimate the flow.
Risers: Whole assembly is inserted inside. There were 5 risers, each of 10’ so the total length of
riser was 50’.
Pressure Control Kit: Contains BOP & grease injection equipment. It is also used to control the
well pressure.
Wireline: Electrical signals are send on wire, that is used in well intervention jobs.
The length of Equipment from tool catcher to line vapor was 10’.
CCL & Gamma Ray log was used to correlate the depth.

Daily Activity Log
Activity No: 01 (June 13th
2016)
The Amine losses (0.1 gal/ MMSCF) can be occurred within Tower, Stripper & Amine Charge
Pump (i.e. packing between plunger and cylinders can be affected).
The previous calculated strength of ASU Surge Tank (V-200) was 37.6%. In this regard, 01x
drum MDEA was charged into ASU Surge Tank (V-200) which increases the strength up to
40%.
To remove air pockets from centrifugal pump, a bottle of water was added through pipe. This
process is called priming while cavitation indicates the presence of air pockets in pump.
Activity No: 02 (June 13th
2016)
Impurities in sales gas recorded w/dragger tube @ outlet of Glycol Dehydration unit
S.NO Impurities Chemical Quantity Measure
Range
Scale Range Unit
1 H2S Lead Acetate 1.3 0.25-20 0.5-10 ppm
2 CO2 Hydrazine 0.2 0.5-20 1.10-10 mole%
3 H2O Magnesium per
chlorate
1 3-100 3-40 Lb/MMSCF
Activity No: 03 (June 25TH
2016)
Objective: To calculate the Amine strength.
Apparatus
 Burette
 Round bottom flask
 1 ml Pipette
 Graduated cylinder (50 ml)
 Dropper
 Wash bottle
Chemicals
 1 N HCL
 Methyl Orange (Indicator)
 Amine Solution (To be tested)
 RO Water
Procedure
1. Read Job safety analysis (JSA) for chemical test before starting the procedure.
2. Rinse all apparatus from wash bottle.
3. Take 49 ml RO in Graduated cylinder& add in titration flask.
4. Pipette out 1 ml Amine solution & add in titration flask.
5. Add 1 or 2 drop of methyl orange (Indicator) from dropper in titration flask.

6. Fill the burette with1 N HCL & note the initial reading.
7. Slightly Add HCL from burette into titration flask until red (end point) color appears. This is
the final reading.
Calculation
Amine Strength (wt. %) = Volume of HCL used x 11.91/ Sample volume
Initial Reading=20.6 Final Reading=22.5
Volume of HCL used=22.5-20.6= 1.9
Result
Amine Strength (wt. %) = 22.629
Precautions
 Handle chemicals with extreme care. Use gloves when handling chemicals.
 Pipette out Amine solution when it is cooled.
2016)
Objective: Calculation of condensate and water level in condensate storage tank (T-4201)
through Rod Dip Method.
Thin film of color cut was placed on clean gauge line, rod or bob approximately where water
level was expected to appear. Then tape or rod was lowered into tank until bottom was reached.
Water gauge would appear by positive contrast of brilliant color; gold changes to red on contact
with water level. Same procedure was repeated for condensate reading but in the case, gasoline
gauging paste would be placed on gauge line.
S.NO. Scale (meters) Liquid Vol.in liters
(Calibrated chart)
Vol.in
barrels
Actual Quantity in
barrels
1 3.5 Condensate 55656 350.25 350.25-300.23=50.01
2 3 Water 47707 300.23 300.23
2016)
Objective: To calculate the amount of chlorides present in ZS-1 & ZS-2.
Apparatus
 Burette
 Round bottom flask
 2 ml Pipette
 Graduated cylinder (50 ml)
 Dropper
 Wash bottle

Chemicals
 0.1 N AgNO3
 Potassium Chromate, K2CRO4 (Indicator)
 Water Sample from both Separators (To be tested)
 RO Water
Procedure
1. Read Job safety analysis (JSA) for chemical test before starting the procedure.
2. Rinse all apparatus from wash bottle.
3. Take 25-50 ml RO in Graduated cylinder& add in titration flask.
4. Pipette out 2 ml water sample& add in titration flask.
5. Add 1 or 2 drop of Potassium Chromate, K2CRO4 (Indicator) from dropper in titration flask.
6. Fill the burette with0.1 N AgNO3& note the initial reading.
7. Slightly Add AgNO3 from burette into titration flask until red (end point) color appears.
8. This is the final reading.
Calculation
Chlorides (wt. %) = Volume of AgNO3 used x 35450 x Normality of AgNO3 / Sample volume
For ZS-1
Initial Reading= 43.8 Final Reading=46.8
Volume of AgNO3 used= 46.8-43.8= 3.0
Chlorides (wt. %) = 3 x 35450 x 0.1 / 2 = 5318
For ZS-2
Initial Reading=47.6 Final Reading=50.3
Volume of AgNO3 used= 50.3-47.6 = 2.7
Chlorides (wt. %) = 2.7 x 35450 x 0.1 / 2 = 4786
Precautions
 Handle chemicals with extreme care. Use gloves when handling chemicals.

Activity No: 06 (July 01st
2016)
Objective: ZS-2 Produced & Shifted Volume Calibration of Slop Tank
Time Dip Readings (Liquid depth in
mm)
Volume from Slope Tank Calibrated Chart
(barrels)
Morning 1090 38.62
1044 37.00
Evening 282 6.78
240 5.33
Night 1138 40.22
1090 38.62
For Condensate
38.62-37.00=1.62
6.78-5.33=1.45
40.22-38.62=1.6
1.62-1.45=0.17 (Shifted Volume)
1.6-1.45=0.15 (Produced Volume)
For Water
37.00-5.33=31.67 (Shifted Volume)
Activity No: 07 (July 02nd
2016)
Objective: ZS-2 Produced & Shifted Volume Calibration of Slop Tank
Time Dip Readings (Liquid depth in
mm)
Volume from Slope Tank Calibrated Chart
(barrels)
Morning 306 7.55
268 6.30
Evening 1142 40.30
1060 37.58
Night 278 6.60
236 5.25
For Condensate
7.55-6.30=1.25
40.30-37.58=2.72
6.60-5.25=1.35
2.72-1.35=1.35 (Shifted Volume)
For Water
37.58-7.55=30.03 (Shifted Volume)

Activity No: 08 & 09 (July 03rd
& 11th
2016)
9 Samples were taken from different sample points to
know their PH value. PH indicator strips (non-bleeding)
which is a universal indicator, range from 0-14 are used for
this purpose.
The pH scale measures how acidic or basic a substance is.
The pH scale ranges from 0 to 14. A pH of 7 is neutral. A
pH less than 7 is acidic. A pH greater than 7 is basic.
Activity No: 10 (July 15th
2016)
A Spot reading task was assigned in the morning at 6:45 A.M to note the parameters of ZS-2.
Following readings were noted which are mentioned below in the table:
S.NO. Sample Sample Points PH Values
July 3rd
July 11th
1 ZS-1 Separator (Water Line) 8.5 8
2 ZS-2 Separator (Water Line) 8.7 8
3 Rich Amine HEX Outlet 10 10.5
4 Lean Amine ASU Charge pump discharge 10.5 10
5 Hot oil Reboiler Inlet 6.5 6
6 RO water RO Product tank 6.5 6.5
7 Reflux Water Pump discharge 6 6.5
8 Lean TEG GDU Charge Pump discharge 11 9
9 Rich TEG GDU Flash tank bottom 11.5 9.2
Parameters ZS-2 Units
WHFP 533.02 Psig
WHFT 77.8 °F
Line Temperature 88 Psig
Flow line Pressure 460 Psig
Fuel gas 135 Psig
Hydrate inhibitor injection pressure 600 Psig
Corrosion inhibitor injection pressure 480 Psig
Level in tanks (A&B) 40 35 cm
Regulated Panel supply Pressure 102 Psig
Fusible loop Pressure 75 Psig
ESD Pressure 74 Psig
SCSSV Control Pressure - -
SSV Control Pressure 1300 Psig

Production Separators
Production separators are used to separate the fluid on density basis. As the density of water is
greater than oil & water so it will form a layer on upward. Horizontal separators are used where
higher GOR is needed. More space is also required.
Internal Structure
 When gas comes from well head it strikes on deflecting plate which is usually installed on
45°, with pressure drop the momentum of gas will break & it acquires larger surface area.
 Weir plate is installed on the 50% height of the separator from which condensate will come
on other side.
 Vortex breaker is used to prevent from turbulence & liquid seal may not be broken because
preceding skids are operating on lower pressure that’s why there can be a chance of gas
passage.
 Demister pad is used where lighter component like gas can pass out& also prevent liquid
carry over.
S.NO. Parameter ZS-01 ZS-02
1. Separator Pressure (psig) 470-480 430-440
2. Separator Level (%) 40% 25%
3. Separator Temperature (°F) 70-95 78-86
4. No of PSV 2 2
5. No of SDV 3 3
Water Degasser
The water and condensate after passing through three phase separator enter into the water
degasser. This processing is provided in order to remove and gas entrapped in the water.
For small amount of entrained gas in produced water, the degasser play a major role of removing
gas that is left in the water. In order to remove the gases, the fluid must pass degassing
technique.
In our case we have vacuum tank degasser. It can be horizontal, vertical or round vessel. We
have vertical degasser. A vacuum action is created to pull in the gas cut water. Mixed stream
enters the water degasser. The mixed stream upon striking the baffle separates into the gas and
water. The gas removed from the top of water degasser goes to the flare line via 6” line. LCV is
installed on the outlet line of the processed water to control the level. Instrument air supply is
there to the supply air to the valves. BDV is installed on the inlet line of the gas. SDV is also
there on the drain line.

Important Parameters
1 Current Pressure 16-25 Psi
2 Current Level 50%
3 PSV rating 65 Psi
4 Drain Line 2”
5 PSV @ outlet line of gas 6”
6 Produced water line 4”
Condensate Degasser
The condensate after separation through three phase separator enters into the condensate
degasser. This processing is provided in order to remove gas entrapped in the condensate.
Liquids naturally contain dissolved gases even after separation. So it is required to be separated,
before sent for storage. The gas is than allowed to flare. Condensate recovery is important to be
recovered from the gas.
For small amount of entrained gas in condensate, the degasser plays a major role of removing
gas that is left in the condensate. A vacuum action is created to pull in the gas cut condensate.
Condensate enters the condensate degasser. From here the condensate moves to condensate
storage tank. In the storage tanks we normally give settling time to the fluid to settle down. From
storage facility water is sent to evaporation pit and condensate to the loading for dispatch. The
gas removed from the top of water degasser goes to the flare line via 4” line. LCV is installed on
the outlet line of the processed water to control the level. Instrument air supply is there to the
supply air to the valves. BDV is installed on the inlet line of the gas. SDV is also there on the
drain line.
Important Parameters
1 Current Pressure 10-12 Psi
2 Current Level 35%
3 PSV rating 45 Psi
4 PSV @ outlet line of gas 4”
5 Drain Line 2”
6 Condensate line 4”

Flash Knock out Drum
It is the last skid from where carry over liquids in gas are separated &don’t allow the liquid to
send into flare. It has no pressure. A vapors-liquid separator is a vertical vessel used in several
industrial applications to separate a vapors-liquid mixture. Gravity causes the liquid to settle to
the bottom of the vessel, where it is withdrawn. The vapors travel upward at a designed velocity
which minimizes the entrainment of any liquid droplets in the vapors as it exits the top of the
vessel. The feed to a vapors-liquid separator may also be a liquid that is being partially or totally
flashed into vapors and liquid as it enters the separator. When used to remove suspended water
droplets from streams of air, a vapors-liquid separator is often called a demister.
Parameters Separators
(ZS-1/2)
Water Degasser Condensate
Degasser
Flash Knock
out Drum
Tag No V-1801/1802 V-1001 V-0901 V-3201
Fluid Name Three Phase Water Condensate HC Condensate
Design Pressure
(Psig)
1480 65 45 50
Operating pressure
(Psig)
525 50 15 22
Design Temperature
(°F)
100 150 120 150
Operating
Temperature (°F)
80 104 61-120 62.6
Hydraulic Test (Psig) 1921 135.227 61 65
Size (O.D) x L x THK
(MM)
1170x2540x5
0
Shell dia
I.D/O.D/Length:
(1067/1091/2112 mm)
Thickness Shell/head:
(12/14 mm)
931x2490x8 1236x3760x8
Corrosion Allowance
(MM)
4.5 4.5 4.5 4.5
Year Built 2013 2013 2013 2013
Capacity 2605 2203 1751 4871
Weight (kg) Empty:5772
Hydrotest:840
4
(Empty/Opera/test :
2220/4410/4420)
Empty:2092
Hydrotest:3913
Empty:1706
Hydrotest:6612
MAWP 1480 psig @
100 °F
1480 psig @ 100 °F 47 psig @ 120 °F 50 psig @ 150
°F
MDMT 54.86 °F @
1480 psig
-28.89 °C @ 717.46
kpa
-20°F @ 47 psig -20°F @ 50
psig

Water Bath Heater
The temperature of production separator is calculated as 70°Fand 51°Fduring summer and winter
after taking into account the heat transfer in the flow line. Therefore, a water bath fired heater is
proposed at the downstream of production separators to increase the gas temperature to 90 to
95°F prior to feeding into Amine Sweetening Unit.
The line of 8’’ is installed on the outlet of 3 phase separator. A reducer is used to reduce the
diameter of line up to 2’’. In this way, 6’’ line is entering into the inlet of water bath heater.
 With the combination of fuel gas (supplied from fuel gas skid) & pneumatic air Natural draft
forms. Air filter is also fitted on its inlet. From side glass inside view of fire tubes can be
observed. Two main burners & one pilot burner are sources which ignites the fire.
 The body of heater consists of two parts. Shell and tubes. RO water is present in coils and
tubes contain fire. Heat exchanges which heat up the tube that ultimately increases the
temperature of water.
 An expansion tank is installed above the water bath heater pumps. The purpose of the
provision of expansion tank is to account for the change of volume of water medium due to
increase in operating parameter like temperature. Expansion volume comprises of the <55 %
total capacity of the expansion tank with the remaining volume located for the surges.
 On the outlet of tube, chimney/stack through the flue gases likewise CO2, CO into the
atmosphere.
 Temperature control valve is installed to control the excess temperature. Vent filter which is
installed on the top, remove the vapors. On its adjacent, bridle which have floater is placed
that can controls the level.
Specifications
1. Water Bath inlet Temperature 75-80°F
2. Water Bath Outlet Temperature 90-100°F
3. Level of Expansion tank maintained >60 %
4. Fuel gas supply line size 1”
5. RO water supply line size 2”
6. Process gas supply line size 8”

Coil
1. Operating pressure 57.1 bar
2. Design pressure 96.5 bar
3. Operating temperature 17- 57°C
4. Design temperature 60°C
5. Capacity 1.42 m3
6. Heat Surface 938 m2
Water
1. Operating Temperature 80°C
2. Design Temperature 100°C
3. Capacity 22.78m3
4. Medium of heat Water
5. Make PIETRO FIONENTINI
Hot Oil System
Hot oil system is designed to meet the requirement of Amine Stripper Reboiler. It is
mainly consist of following components:
 Hot Oil (fired) Heater
 Hot oil expansion tank
 Hot Oil Storage tank
 Hot Oil Circulation Pumps
 Burning Management System
 Fuel gas train
 Modulator
 Temperature transmitters
 Blowers
 Stack
First the hot oil after transmitting the heat in the Reboiler of the Amine Sweetening Unit, the low
temperature hot oil passing through a Temperature Control Valve controlling upstream
temperature, enters the suction of the Hot oil Pump which increases the pressure of the Hot oil
from 8-9 psi to 25-30 psi. These are two centrifugal pumps & one is always on standby. Hot oil
flow rate is controlled by the Amine Re boiler control valve.
Outlet bundle is provided to heat the oil before entering into inlet bundle. Overlaid the hot oil
pumps, we have the expansion tank that helps to store the expanded volume due to temperature.
The tank is normally operated with the 50% level full. The expansion tank is provided with the
both High level Switch on 98% and Low level Switch. Vapor trapping & balancing lines are also
entering to expansion vessel. These line traps the vapor which may enter into pump that will needs
to be primed because air pockets can form with in it.

Now the hot oil is circulated through three pass coils which are continuously fired by the help of the
fuel gas through proper Burning Management System.
Burning System is incorporated with the blowers that are electrically driven to maintain air fuel ratio
(60:40) necessary for the combustion of fuel gas. All aspects of heater fire are managed through
Burning Management System.
The fuel gas train is equipped with three parallel self-contained pressure regulators to adjust the flow
of the pilot gas accordingly.
The hot oil system is provided with the temperature transmitters in order to monitor the return and
outlet temperatures.
As the hot oil temperature increases the temperature valve is modulated closed thereby admitting
less gas to the burner and decreasing firing intensity and conversely when the temperature decreases.
Stack is responsible to vent the flue gases to the atmosphere. Two Pressure Safety valve & 1
Pressure Relief valve is also installed which will release the excess gas to flare.
Parameters Ranges Units
Coil Capacity (Designed) 150 ft3
Surface Area of tube (Designed) 2067 ft3
Surface Area of tube (Calculated) 1884.00 ft2
O.D 0.33 ft
I.D 0.305 ft
Wall Thickness 4.25 mm
Total Tube pieces (together) 90 -
Each Tube pieces Length 20 ft
Total Tube length 1800 ft
Cross-Sectional Area of tube 0.07 ft2
Volume/Capacity of tube 131.811 ft3
Retention time in tubes 1.267 minutes
Indicated flow Rate 6240 ft3
/hr.
Velocity 76.0447 ft/sec
Heat Gain Rate by hot oil 7.71 MMBTU/hr.
Pump Suction Pressure 5-8 psi
Pump Discharge Pressure 28-34 psi
Hot Oil inlet Temperature 240-250 °F
Hot Oil outlet Temperature 280 °F
High Set Point Maximum 282 °F
Louvers Position 50 -75 %
Fuel Supply Fuel Gas -
Pump Frequency 60 Hz
Expansion Tank Level 50 -70 %

Reverse Osmosis
Reverse osmosis (RO) is a water purification technology that uses a semipermeable membrane to
remove ions, molecules, and larger particles from drinking water. In reverse osmosis, an applied
pressure is used to overcome osmotic pressure that is driven by chemical potential differences of the
solvent. Reverse osmosis can remove many types of dissolved and suspended species from water,
including bacteria, and is used in both industrial processes and the production of potable water. Total
dissolve solids in RO water should be less than 5 ppm. Osmotic pressure is the
minimum pressure which needs to be applied to a solution to prevent the inward flow of water across
a semipermeable membrane. It is also defined as the measure of the tendency of a solution to take in
water by osmosis.
Working
In the normal osmosis process, the solvent naturally moves from an area of low solute concentration
(high water potential), through a membrane, to an area of high solute concentration (low water
potential). The driving force for the movement of the solvent is the reduction in the free energy of
the system when the difference in solvent concentration on either side of a membrane is reduced,
generating osmotic pressure due to the solvent moving into the more concentrated solution.
Applying an external pressure to reverse the natural flow of pure solvent, thus, is reverse osmosis.
Process
Raw water tank is filled first by the water storage.
Then raw water is fed by the help of multi stage inline centrifugal pump into the sand filter. Sand
media filters distribute contaminated water over a sand medium bed capable of filtering out particle.
Sand filters use an automatic backwash cycle to clean the filter media, which lends to fewer
maintenance intervals. It contains a riser, at inlet water rises which is actually a rejected quantity of
water that drains & send to evaporation pit.
Expansion Tank Pressure 5-7 Psi
Operating capacity of Hot oil
pump
800 USGPM
Design capacity of Hot oil pump 1100 USGPM
Calculated Hot oil rate 446 (min)- 982(max) USGPM
Hot oil inlet line size to Reboiler 1 Inch
Hot oil outlet line size 1 Inch
Burner Management System
Heater outlet temperature
controller
293 °F
Heater outlet high temperature
limit, Set Point
292-298, 375-390 °F
Stack high temperature limit, Set
Point
332-370, 650 °F

After exiting from sand filter, 2 bag filters are installed are generally made of polyester. The particles
are normally captured on the internal surface of the bag filter. In bag filtration systems, water to be
treated passes through a bag-shaped filtration unit where the particles are collected on the bag's filter
media while allowing filtered water to pass to the outside of the bag.
4 Anti scaling pumps which are installed this is not on operating condition.
Cartridge filters, made of polypropylene (a plastic), trap particle contaminants as water passes
through the filter media. Cartridge filters are preferable for systems with contaminations lower than
100 ppm, which is to say with contamination levels lower than 0.01% in weight. These filters are
used to remove chlorine from the raw water.
The raw water is passed through the cartridge filter and then is backed fed to feed water tank.
This processed water is then feed to the RO membrane by the pressure of the Inline centrifugal
pump. In the RO membrane portion due to the excess applied pressure of around 150-170 psi, feed
water is passed through the membrane. A semipermeable membrane, that will allow
certain molecules or ions to pass through it by diffusion. The diffusion of water through a selectively
permeable membrane is called osmosis. This allows only certain particles to go through including
water and leaving behind the solutes including salt and other contaminants.
In the last stage the RO water is fed to the RO water tank.
From where up to the requirement the RO water when needed is pumped through the centrifugal
pump into the Amine Sweetening unit.
Parameters Ranges
Pressure applied through Membrane 150-170 psig
Daily average RO water make up 200 gallons
RO water/Rejected Volume 1000 gallons/100 gallons
RO water header line size 2 “
Bag Filter mesh size 10 micron
Cartridge filter mesh size 5 micron

Amine sweetening unit (ASU)
Physical Properties of MDEA
Parameters Ranges
Structural Formula CH3N-(CH2CH2OH)2
Molecular Weight 119.16
Specific Gravity at
20/20°C
Sp.Gr./ t per °C
1.041
0.00076
Boiling Point, °C at 760 mm Hg
at 50 mm Hg
at 10 mm Hg
247.3
163.5
128.6
Freezing Point, °C (°F) -21 (-6)
Solubility, at 20°C
in water
water in
complete
complete
Vapor Pressure, mm Hg at 20°C <0.01
Viscosity, CP
at 20°C
at 40°C
101
33.8
The main purpose of ASU is to sweet the gas after the removal of sour gases like CO2& H2S.
The sour gas stream first enters in the Coalescing filter separator. Bulk and entrained solids and
liquids are removed hereto 0.3 microns absolute. It has temperature range between 90 to 100°F and
pressure of 450 PSI. It has 7 cartridge filters which prevent foaming in the Amine Absorber. Coalscer
consist of two compartment units with a scrubber section in the base and a tube sheet section
equipped with up stands to support the filter / Coalscer elements.
The coalescing pack aids the separation of fine droplets. Gas enters though a pipeline into the lower
section of the vessel, where large liquid droplets can separate from the gas, and passes upwards
through the coalescing pack into the upper section. Fine liquid droplets accumulate on the coalescing
medium and when the drops are large enough they fall back onto the bottom of the upper section.
Safety limit at inlet filter PSV-2100 which is operating on 590 Psi.
ΔT between raw gas & lean amine must be 10 to 30°F. The temperature of absorber is between 90 to
95°F. Acid gases then move to absorber (T-2110) which has 24 trays. Each tray has multiple floating
valves are used for good liquid and gas contact. The liquid level is maintained on each tray by a weir
on the down comer. The number of trays or height of packing helps determine the degree of
sweetening. Safety limit at Scrubber PSV-2120which is operating on 590 Psi.

At the same time, MDEA & RO with ratio of 40% and 60% which has
entered from the top flow downward counter-current to the gas flow.
The temperature of the lean amine should be kept 10° F, above the
natural gas temperature to prevent hydrocarbon condensation. The gas
disperses through the amine in the form of bubbles, Froth is formed.
The gas disengages from the froth, travels through a vapor space and
up through the liquid on the next tray. Entrained amine solution falls
back onto the tray and then flows down through the down comer to the
next tray. Nearly all absorption of H2S and C02takes place on the trays
and not in the vapor space between the trays. Safety limit at Amine
Absorber PSV-2110 which is operating on 590 Psi.
At the top of the contactor, a mist extractor traps entrained liquids from
the gas before it enters the gas outlet. This liquid then drops back onto
the top tray and rejoins the amine stream. While sweet gas is leaving the
top of the contactor, rich amine solution, which contains H2S and C02, is
discharged from the base of the contactor. Sweet gas goes to scrubber
&then gas Dehydration unit for procedding process.
Inlet Coalescer filter, Gas Scrubber & ASU Absorber Specification
Maximum Allowable Working Pressure 150 Psi @ 200°F
Minimum Design Metal Temperature -20°F @ 150 Psi
Maximum Allowable External Working Pressure 15 Psi @ 200°F
Rich amine solution leaves the bottom of the contactor and flows
through a flash tank (V-2130) where 15 minutes settling time is
provided with pressure of 60 PSI, remove large portion of physically
absorbed gases in the rich amine. It also removed liquid
hydrocarbons carried out of the contactor through the rich amine.
The flash tank is simply a three phase separator in which entrained
gases, liquid hydrocarbons and amine solution are separated. The flash tank should be operated at the
lowest possible pressure to maintain amine flow to the stripper. Tank vapors, which are usually sour
are recycled to the contactor or flared. With increasing some level of condensate with in flash tank, it
enters into condensate bucket. This process is termed as skimming. Safety limit at Flash Tank PSV-
2130 which is operating on 150 Psi.
Advantages of using flash tank in the system being:
 Minimize hydrocarbon contents in the amine solution.
 Reduce vapor load on the stripper.
 Reduce erosion in rich and lean amine and extended life of activated carbon filter.

Then rich amine with temperature of 128°F transfers to the tubes
of heat exchanger (E-2140A/B) from where it goes to Stripper (T-
2150). The Lean / Rich Amine Exchanger used to heat the rich
Amine stream, flowing from the Rich Amine Flash Drum to the
Regenerator, using the hot stream of lean. This reduces the
required duty of the Regenerator Re-boiler and provides initial
cooling of the lean Amine stream, thus reducing the duty on the
Lean Amine Cooler.
The Amine Regenerator is designed to strip the acid gases from
the rich Amine solution to allow the Amine to be re-used in the
Contactor. Stripping is high temperature and low pressure
phenomenon. Heat input is provided by the Re-boiler (E-2160) in
the regenerator to break temporary bonds between acid gases and
amine solution. The heat input to the column by boiling liquid
from the bottom of the Regenerator to provide vapor (mainly
steam) to strip the acid gases from the rich Amine solution as it
percolates down the Regenerator column. Like the contactor, a stripper is valve tray column which
provides good vapor amine contact. The heated stream enters the Amine Regenerator on tray 05,
which is a tray column. Water reflux, at a lowered temperature, enters the top of tower& flows
downward thereby cooling & partially condensing the vapors & improving separation between the rich
amine & the absorbed gases.
Lean/Rich Amine Exchanger Amine Reboiler
MAWP MAEWP MAWP MAEWP
Shell 50 Psi 350 °F 50 Psi 450 °F
Tube 150 Psi 350 °F 50 Psi 450 °F
MDMT MAWP MDMT MAWP
Shell -20 Psi 50 Psi -20 °F 50 Psi
Tube -20 Psi 150 Psi -20 °F 50 Psi
Re-boiler temperature is primarily a function of the pressure at
which the stripper is operated. As the pressure goes up, re-boiler
temperature goes up. At higher temperatures (above 240°F) the
corrosion rate increases rapidly. Safety limit at Reboiler PSV-
2160which is operating on 50 Psi.
Level is transfer to surge tank up to 50% which is integral part of Re-boiler. 2 to 3 minutes residence
time is provided and that absorbs any system surges related to process upsets which also protects the
instrumentation in the system. Lean amine from surge tank (V-2200) moves to the shell of heat
exchanger then it goes to booster pump.
Rich Amine from the top of stripper travels to reflux accumulator (V-2180) having pressure of 8- 9
PSI. The Reflux accumulator is designed to separate the two phase mixture entering from the Reflux

Condenser. Regenerator reflux Condenser (E-2170A/B) is designed to reduce the temperature of the
overheads stream is reduced to approximately 130°F. The liquids collected are returned to the
Regenerator, and the gases are vented. Reflux accomplishes two things in the overhead system of the
stripper. First it cools vapors in the top of the stripper reduce the amount of amine carry over and
thus saving valuable amine losses and secondly it cools acid gases at the top of the stripper to reduce
its corrosiveness. However reflux is an additional load to the re-boiler. Over and under refluxing can
be an expensive operational problem. An overhead condensing temperature in the range of 190-
200°F is usually sufficient for good stripping. Below this re-boiler duty is increased and above this
range, the amine solution lost in the overhead will increase. Safety limit at Reflux Drum PSV-
2180which is operating on 50 Psi.
The Regenerator Reflux Pumps take their suction from the liquid discharge from the Regenerator
Reflux accumulator (V-2180). Two pumps are provided (P-2190A/B), one duty and one standby.
Discharge from the pump goes to the Amine Regenerator (V-2150).It increase the pressure up to 50
Psi. 9 Psi is given to Reflux BPCV 2180, assist the stripping process in good manner & also
maintains the temperature of Re-boiler.
Before booster pump (P-2210A/B) the temperature and pressure was 160°F & 10 PSI respectively.
The Lean Amine Booster Pumps provide the first stage of pressure increase of the lean Amine stream
prior to cooling, filtration and final pumping back into the Contactor.
Booster pump enhances the pressure up to 45 PSI.
Lean amine cools down by fin fan cooler (E-2220A/B) which decreases the temperature and becomes
105°F. It has ability to maintain the temperature at least 10-15°F high than the sour gas.
Pre-particulate filter (FL-2230) has 25 microns & 12 candles which catches the sand & dust particles
while Post-particulate filter (FL-2250) has 12 candles and 10 microns. The Lean Amine filters
remove solids and other contaminants prior to introducing it to the Amine Contactor (V-2110). These
if otherwise not removed from the system may cause plugging and foaming in addition they may
cause erosion of pump pistons, valve seals and discs. When the pressure drop across the filters rise to
predefined value, these should be replaced so that collapse of elements and stoppage of amine
solution does not occur.
The Carbon Guard Filter is a vessel, (FL-2240) has 32 candles and 5 microns containing replaceable
filter elements, through which a side stream of the lean Amine solution is passed to remove any
smaller particles that have passed through the Carbon Bed Filter. The solids consist of Amine
degradation products and precipitated salts that build-up during the recirculation of the lean amine.
The positive displacement triplex Plunger Charge pumps (P-2260A/B) is installed which works on
suction & discharge phenomena. At downstream, anti-foaming scale chemical & reverse osmosis

water is injected with 1:3. At last, lean amine transfers to absorber and circulation will continue till
pipeline quality specification will be achieved.
ASU Charge Pumps (P-2260A/B) Specification
Power 91 HP
Discharge Pressure 511 Psi
Suction Pressure 16 Psi
Flow Rate 275 GPM
Speed 311 Crank RPM
Temperature 133°F

Gas Dehydration Unit
Physical Properties of TEG
Parameters Ranges
Formula C6H14O4
Molecular Weight, g/mol 150
Boiling Point @ 760 mm Hg, °C (°F) 288 (550)
Vapor Pressure at 20°C (68°F) mm Hg <0.01
Density, (g/cc) @ 20°C (68°F) 1.125
Density, (g/cc) @ 60°C (140°F) 1.096 1.093
Pounds Per Gallon @ 25°C (77°F) 9.35
Freezing Point, °C (°F) -4.3 (24)
Pour Point, °C (°F) -58 (-73)
Viscosity, cP @ 25°C (68°F) 49.0
Viscosity, cP @ 60°C (140°F) 10.3
The purpose of a glycol dehydration unit is to remove water from natural gas. The objective is to
achieve an outlet water content of a maximum of 7 Lb. /MMSCF of gas.
The sweetened gas stream flows from the Amine Sweetening unit to inlet Gas scrubber of the Glycol
Dehydration unit. Any carried-over amine is captured in the scrubber.
Inlet gas scrubber operates at 420-430 psig and between 105°F and 107°F. The Bulk liquid separation
in Gas Scrubber (V-3110) is achieved in three phases:
 An inlet vane diffuser is facilitating the primary removal of liquid from natural gas & even
upward vapor flow distribution.
 Stroke type gravity settling for secondary separation.
 A mesh pad mist extractor for tertiary liquid droplet removal (10 microns) in the entrained gas.
Lean Glycol solution from the Lean Amine Charge Pumps (P-3210A/B) enters the Contactor near the
top at 01 tray and flows down through the vessel. Process gas enters into the bottom of the Glycol
contactor (T-3120) at around 410-420 Psig and in-between 105 to 107°F. High pressure & low
temperature is always favorable conditions for good absorption.
The Glycol Absorber is designed on the aggregation of these components:
 The Glycol Absorber uses 8 trays in a single flow path, spaced at 24’’. Each of the trays is
equipped with 3 slotted bubble caps.
 The trays are equipped with inlet & outlet weirs that distribute flow of TEG evenly across the
trays and down-comers.
 The bottom of the absorber contains chimney tray which contains a liquid seal pan to ensure that a
layer of TEG exists on each of the eight trays.

 A mesh type mist eliminator is provided in the gas outlet of the Glycol Absorber to remove any
entrained TEG from the dehydrated gas stream prior to exiting the contactor tower.
Safety limit at GDU Absorber Tower is PSV-3110 operating at 590 Psi. T between sweet Gas &
TEG should be maintained within range of 14 to 18°F. If this not achieve, absorption may not be
occurred properly. Foaming can be resulted if any Cooler Glycol solution forms because it allows
hydrocarbons vapors to condense which may also occur in the loss of amine in greater extent.
Lean glycol is trim cooled in the gas/TEG Exchanger prior to entering the top of the Glycol contactor
at a temperature of 5-10 degrees higher than the feed gas. The wet gas flow upward counter-current to
the lean glycol solution in the glycol contactor. Rich glycol leaves the bottom of the contactor tower
under level control to the Reflex coil.
The dry gas, after absorption of water by the TEG solution, then flows to the HCDPU for further
processing.
The Reflux coil is equipped with globe by pass & discharge valves to manually control the
temperature of the TEG regenerator steam overheads, thereby reducing the losses of TEG. Exiting the
Reflux coil the rich glycol then flows to the glycol flash tank.
High temperature and low pressure should be maintained for stripping where moisture is removed
from the rich glycol solution. Re-boiler and heat exchanger are providing heat to achieve this
objective.
The Glycol flash tank (V-3130) is located upstream of the lean/ Rich Glycol Heat exchanger &
operates at a pressure of 25-75 psig. Allowance of settlement is given to glycol solution for 15
minutes, which provides adequate separation of hydrocarbon from the glycol solution. After
increasing the level of condensate, it enters in condensate bucket which is termed as skimming and it
drains. Safety limit at Flash Tank is PSV-3130 operating at 150 Psi. It is for vapor generation.
GDU Flash Tank Vessel Specification (V-3130)
Maximum Allowable Working Pressure 150 Psi @ 200°F
Minimum Design Metal Temperature -20°F @ 150 Psi
Maximum Allowable External Working
Pressure
15 Psi @ 200°F
The rich glycol flow under level control out of the Glycol flash tank, & on to the Lean/Rich Glycol
Exchanger. The rich glycol enters at 100-180°F, where it is heated to 290-215°F by the hot lean
glycol solution from the Glycol Reboiler.
The lean/rich glycol heat exchanger is used to heat the rich glycol and simultaneously cooling the
lean amine. Here, it is heated by the stream of lean glycol coming from the surge tank (TK-3200).
This preheats the rich Amine stream which reduces the load on the Glycol Re-boiler (E-3180).The
heated rich Glycol stream then passes on to the stripper. The lean Amine Stream from the
Regenerator also passes into the Lean /Rich Amine Exchanger. There are 72 tubes present inside with

5/8’’ can produce heat 475,000 BTU/HR with working conditions of 50/150 Psi & 150 °F
respectively.
Full flow particulate & carbon filtration is installed downstream of the Lean/Rich Exchanger &
upstream of the Glycol Regenerator. Rich glycol then allowed passing through the first pre particulate
filer (FL-3150). The purpose is to remove entrained solids and debris so that glycol charge pump is
not affected, to prevent plugging of the lean/rich heat exchanger and to ensure no solid deposition
occurs on the fire tube.
This glycol then enters the carbon filter (FL-3160). This is basically 5 micron 20” filter element that
is used basically to remove dissolve impurities in the glycol which ensures that the foaming will not
occur in glycol absorber. The stripping of water in the Glycol Regenerator regenerates the rich glycol
solution. The Glycol Reboiler supplies the necessary heat to strip water from the rich glycol, using a
fire tube & flame-arrested natural gas burner as the source of heat. Water vapor from the Glycol
Regenerator exits the tower at 190-220°F& is vented to atmosphere.
The glycol from the stripper falls into the Reboiler. It is then heated to 360-400°F, which causes the
water that was absorbed in the Glycol Absorber to be vaporized. The fuel gas burner of Re-boiler is
the forced draft burner type that is used to heat the amine. The fire is generated in a tube called as fire
tube. The tube always remains in contact with the glycol solution and continuously heats the glycol
solution. The fuel of combustion is taken from the dry sales gas outlet of the gas dehydration facility.
Safety Limit at Reboiler Burner Inlet is PSV-3180 150 operating on Psi for Closed Outlet.
The rich TEG from absorber goes to the reflux coil (E-3190). The reason is to pre heat the glycol by
using vapors coming from the regenerator. The effluent water vapor is cooled and allowed to
condense so that can be used as reflux.
Reflux helps to give better separation of the moisture and glycol. Lean amine solution flows through
the Glycol Reboiler & into the Lean Glycol surge (TK-3200) section. About 2 to 3 minutes retention
time is provided to ensure adequate response time for system instrumentation in the event of an upset.
Normal operation of the glycol surge tank considers the operating level at 25-40%, thereby allowing a
minimum 60% surge volume. It is working on 1 atm & 392°F. The diameter of tank is 20’’ with
18.6’’ width.
The lean glycol solution flows out of the Glycol surge tank & through the Lean/Rich Exchanger
where it is cooled from 360-400°F to 180-240°F.The glycol charge pumps (P-3210 A/B) are positive
displacement triplex plunger pumps. These are installed in order to pump the glycol from the heat
exchanger to the absorber tower. Safety Limit at TEG Charge Pump is PSV-3210 A/B operating on
590 Psi to Block the discharge.

Parameters Ranges
Capacity 8 USGPM
Motor And Rpm 5HP And 1465 RPM
Efficiency 87.5 %
Discharge. Max Pump Speed 600 Rpm
Volts Required 380 volts
Ampere Required 8.75 Amperes
Hydrocarbon Dew Point Unit (HCDPU)
Dry gas from GDU enters in the tube side of Gas/Gas Heat exchanger (E-4100) where it is pre cooled
by effluent gas on shell side at temperature of 50-85°F.
The pre cooled tube side of chiller (E-4110) is further cools to 28-30°F. The propane refrigerant is
inserted on the shell side of chiller.
Cooled gas enters in low temperature separator (E-4120) which is installed on downstream of chiller
with 28-30°F due to increase in retention time of 30 minutes & low temperature causes adequate
degassing of condensate which reduces shrinkage of sales of gas volume. Condensate from bottom is
process to Gas/condensate heat exchanger & then towards condensate degasser while gas is routed
from the shell side of Gas/Gas Heat exchanger & Gas/condensate heat exchanger (E-4130) & towards
sales gas metering skid.
Propane vapor are compressed in oil flood screw compressor. Lube oil is also injected which can
assist to prevent excess temperature generation from the heat of compression.
Compress propane now enters to compress discharge separator where coalescing elements removed
by lube oil that has been injected.

Propane vapor are enters into propane condenser (E-5130) which condense it into liquid. Propane
condenser fan speed is controlled by VFD which dictates as ambient temperature. Propane liquid is
transferred to propane refrigerant accumulator (E-5140). Two drier filters are also installed on
downstream (FL-5150 A/B).
High pressure liquid propane is passes through JT valve where pressure is reduced by sudden
expansion which also lowers the temperature.
Cold propane on the tubes of gas chiller is vaporized by heat of warm process gas flowing inside the
tubes. The vaporizing of propane induces the cooling bon process side achieving the objective of
chiller.
Propane vapor flows out of the gas into propane suction scrubber (V-5100) in which any carried over
liquid (propane/lube oil) is removed to re-compression.
Lube oil is removed by compressor discharge separator (FL-5120) which is circulated through lube
oil cooler to remove heat which absorb from the compression of propane.
Cooled lube oil flows through 7 microns lube oil filter (FL-5180) which is protecting the lube oil
pump (FL-5160)
Lube oil flows through second lube oil filter prior to injection to ensure that no debris is injected into
oil flooded screw compressor.
Fuel Gas Scrubber
During normal operation, fuel gas is taken from the treated gas before Sales Gas Metering Skid. Flow
meter is provided at the outlet of Fuel Gas Scrubber for the measurement of fuel gas flow and
totalized volume. Pressure regulator is provided upstream of Fuel Gas Scrubber to regulate the
pressure of the gas at the operating pressure of fuel gas system (80 psig).
During the start-up when no fuel gas source will be available within plant, gas will be bought back
from the SSGC (Sales Gas Buyer) pipeline to run the gas driven power generators. A custody meter is
provided on this line to meter the gas taken from Buyer. Furthermore, provision is also provided from
downstream of production separators for startup gas.
Vertical separator has deflecting plate on inlet at which gas entrained with liquid enters from side
which ultimately breaks their momentum. The gas expands due to reduction in pressure which cools
it. After striking on weir plate, gas moves upward and liquid settles down. Gas goes outside the vessel
through demister pad on top.

Parameters Ranges Units
Tag No V-2901 -
Fluid Name Fuel Gas -
Design Pressure 150 Psig
Operating pressure 70 Psig
Design Temperature 120 °F
Operating Temperature 70-120 °F
Design Flow Rate 2 MMSCFD
Internal Diameter 2 Ft
Length 5.5 Ft
Hydraulic Test 214 Psig
Size (O.D) x L x THK 626x1876x8 MM
Corrosion Allowance 4.5 MM
Year Built 2013 -
Capacity 603 (Liters)
Weight Empty:853
Hydrotest:1467
kg
MAWP 164 psig @ 120 °F Psig&°F
MDMT -20°F @ 164 psig °F&Psig
Inlet Pressure 420-430 Psig
Outlet Pressure 80 Psig
No of ESDV 1 -
No of SDV 1 -
PCV set point 80 Psig
Inlet from Raw metering skid 4 Inches
Gas pipeline size 4 Inches
Liquid drain line size 2 Inches
Sales Gas Metering Skid
Metering skid is pursuing following controls:
 Pressure, Temperature & Flow is transmitted to flow computer for computation.
 The pressure of tie in point is controlling through pressure control valve installed at the
downstream of metering skid
 System pressure is maintained through PCV installed at upstream of metering skid (to flare).
 Skid is equipped with gas chromatograph and moisture analyzer for measurement analysis of gas
composition and water content via flow computer.
 Shutdown valve is provided at the downstream of metering skid for isolation.
 Blow down valve is provided at the upstream of metering skid for depressurization of GDU and
HCDPCU up to metering skid in case of fire.
 3-pen chart recorder is also provided for temperature, pressure & flow recording.

Parameters Ranges
Differential Pressure ( inch of water) 0-100
Static Pressure (Psig) 0-1500 Psig
Temperature (F) 0-150
Make Buorton
SWP 2500 psi
Static Tube Material 316 SS
The main components of the Sales Gas Metering unit comprise of:
 Flow Meters (FL-6100/6110)
 Gas Chromatograph (GC-6100)
 Flow computer
Flow Meters (FL-6100/6110)
The flow meters are equipped with:
a) Flow conditioning vanes b) Dual chamber orifice fittings
The orifice plates are adequately sized to ensure differential pressure across the orifice plate is
maintained between 90’’ & 200’’ of water column.
Orifice plate: It is a device used for measuring flow rate, for
reducing pressure or for restricting flow. Either a volumetric or
mass flow rate may be determined, depending on the calculation
associated with the orifice plate. It uses the same principle as
a Venturi nozzle, namely Bernoulli's principle which states that
there is a relationship between the pressure of the fluid and the
velocity of the fluid. When the velocity increases, the pressure
decreases and vice versa.
Working: An orifice plate is a thin plate with a hole in it, which
is usually placed in a pipe. When a fluid (whether liquid or
gaseous) passes through the orifice, its pressure builds up slightly
upstream of the orifice but as the fluid is forced to converge to pass
through the hole, the velocity increases and the fluid pressure
decreases. A little downstream of the orifice the flow reaches its
point of maximum convergence, the vena contracta where the
velocity reaches its maximum and the pressure reaches its minimum. Beyond that, the flow expands,
the velocity falls and the pressure increases. By measuring the difference in fluid pressure across
tapping upstream and downstream of the plate, the flow rate can be obtained from Bernoulli's
equation using coefficients established.

The sizing of the metering tubes is such that the beta ratio (d/D=Orifice diameter/Line bore diameter)
of the orifice plate is maintained to 0.3 minimum & 0.6 maximum.
Gas Chromatograph
It reports the sales gas composition & heating value to the flow computer. The gas chromatograph has
an analysis cycle time of < 30 minutes, the heating value measurement accuracy of +/-0.25% & has
designed to accommodate the following range of compositions:
Component Mole % Range
C1 up to 90
C2 up to 5.0
C3 up to 5.0
C4 up to 2.0
C5 up to 1.0
C6+ up to 2.0
N2 up to 15
CO2 up to 10
H2S up to 2000 ppm
Flow Computer
The flow computer is installed in the Central control room of processing which is responsible facility
to estimate the volume (MMSCF) & Energy of gas (MMBTU) according to its composition.
Secondary function is to generate the current, hourly, daily & monthly reports. To acquire the hard
copy of different reports from printer. It also indicates the values of line pressure, line temperature of
both ZS-I & ZS-II wells.

Instrument Air System
Two instrument air compressors are provided to meet the GPP utility and instrument air requirements.
The compressors operate in case of low instrument air header pressure. The compressors are designed
to cater for the requirements of instrument as well as utility (plant) air.
An instrument air storage (buffer) vessel is provided which will allow the instruments to be operated
for 20 minutes in case of instrument air failure. Two instrument air dryers are provided with the
instrument air package. One of the dryer will be working and the other will either be on regeneration
cycle.
Parameters Ranges
Make Kaeser Compressor
Type Twin Rotary Screw Compressor
Rated Power 30 KW
Rated Motor Speed 2945 RPM
Maximum Working Pressure 232 psig (16 bar)
PRV Setting 232 psig (16 bar)
Weight 740 kg
Free Air Delivery 3.6 m3
/min
Current Input 63 A
Noise Emission 69 Decibel
Fire Water System
The components of fire water system are mentioned below:
Jockey Pump& Fire Pumps
Jockey pump is installed near the dispatch line to give supply to the hydrants at a pressure of around
110psi.Two fire water pumps are provided each taking the suction through 8” suction line. Since the
maximum set pressure is 120 psi, so in the case if excessive pressures, PRVs are installed in order to
release excess pressure back to the storage fire water tank. The capacity of Fire water Tank is 3666
bbl. As the pressure goes down the fire water pump# 1 will start up to the point the pressure becomes
90 psi. For the fire water pump #02 the set point is 70 psi. Normally both the fire water pumps are on
auto mode, but can be shifted to hand or off mode.
Total 15 fire hydrants and 3 fire monitor are installed at different locations of the plant area that are
supplied water continuously through 8” dispatch line.
Fire Water is stored in one (01) Fire Water Tank having storage capacity equivalent to 4 hours of
uninterrupted firefighting at design flow of main fire water pump. Firewater main ring pressure is
maintained by electric driven Jockey Pump. Firewater header is provided with pressure switches
which will start main diesel driven firewater pump in case of low pressure. In case first pump fails to

start or unable to maintain the ring main pressure within a specific period of time, then second diesel
driven main firewater pump will start through a preset logic to provide the flow for firefighting.
In addition to above mentioned fire water system, wheeled and portable extinguishers will also be
provided at different locations of plant.
One motor driven main pump and one diesel pump were considered in JGC design. However, as per
MPCL’s requirement both main pumps are taken as diesel engine drive.
Specifications of Jockey pump
Parameters Ranges
Make GRUNDJOS
Frequency 50 HZ
RPM 2919
Power 5.50 KW
Mechanical Efficiency 0.7
Flow Rate 17 m3
/hr
Maximum .Head 84.7 meters
Head 67.3 meters
P.Max/T.Max 16/120 bar/℃
Efficiency 71.9%
Fire Engines
Fire engines are installed with both the fire water pumps. These engines are diesel driven which are
given supply through 120 gallons storage tank. Fire tender is also available with the following
specialties:
Specifications of Fire water pump
Parameters Ranges
Make PATTERSON
No Of Stages 1
Rated BHP 85
Max BHP 77
Max Suction 276 PSI
Max Discharge 750 GPM
RPM 2600
Impeller Diameter 10.563 mm
Max Pressure 124 Psig

 Water storage facility=4500 Liters.
 Foam storage facility=1000 Liters.
 DCP tank= 250 kg.
 No of hose connections=8
 No of monitors=1
Flow Monitor
Flow monitor has ability to rotate 360°. It is designed by Shilla Fire Company limited. The Flow
Range (Monitor Jumbo Nozzle) having the maximum Range 500 GPM (7.0 Kg/cm2
). The Inlet Size of
Monitor is 3’’ having Female connection & Outlet Size is 2.5’’ with Male connection.
Aqueous Film forming foaming concentrates AFFF
Its mixture contains 3% foam &97% fresh & sea water. It contains the Storage Temperature of 2°C/
60°C while having the lowest temperature of -2°C.
Accessories
Diesel Fuel System
Diesel fuel system consists of a diesel storage tank with two (2) unloading/transfer pumps (1 working
+ 1 standby). Transfer pumps feed the Day Tanks for Diesel Generator and Fire Water Pump. Diesel
Loading into the storage tank from Bowsers will also be done through same pumps.
Flare System
The flare consists of flare header, Flare KO Drum, Flare KO Drum Pumps, an elevated flare stack
equipped with flare tip, flare pilots and flare ignition system.
Flare headers is kept purged with fuel gas to avoid oxygen ingress into the system. Purging
connections are also provided at the farthest end of the flare header(s) for purging at the time of start-
up. Flame Front ignition system is provided with a control panel. The panel provides pilot status
(burning/extinguished). The pilot status is also communicated to main control system. Flare KO Drum
Pump starts at high liquid level and stops at low liquid level.
Closed Drain System
Slop Vessel collects hydrocarbon liquid drains from production separators, condensate & water
degassers, FG scrubber, Flare KO Drum, etc. Two (02) Slop Oil Pumps (1 working + 1 standby) are
provided to pump out the liquid from the slop vessel to the condensate storage tanks. Connection to
tank filling is also provided to burn the contents of Slop Vessel.

Power Generation System
Two (02) Gas Engine Driven Generators are provided to meet the power requirements of CPF. All the
gas engine driven generators will run based on 80% utilization during normal operation.
One Diesel Engine Driven Generator is provided to handle critical loads during emergency conditions.
The power generators are completing the all necessary instrumentation and accessories.
Radiator: It is used to cools the water of Genset which is circulating.
Generator is used to convert mechanical energy into electrical energy. Engine is used to convert
heat energy into mechanical energy.
Working
 While opening gas stream valve, first command is given to engine manually.
 Pre lube pump will start for 30 seconds which circulate oil to all parts of engine for lubrication
purpose.
 Now Command will supply to batteries. 4 Batteries of 24 volts will give command to sluf
(starting motor) also operate solenoid valve. Starting motor will start rotating the Crankshaft.
 The gas from solenoid valve passes to carborator through air filter. Air & gas mixed together
then mixture passes towards turbo charger. Turbo charge will built up the pressure
 The mixture is passes to after cooler where it cools down having temperature 30-45°C then it
goes to throttle plate.
Radiator Specifications
Water Jacket After Cooler
Set Point Trip point Set Point Trip point
87°C 105°C 40°C 60°C
Load Specifications
Plant load 190-250 KW
Load bank 225 KW
Plant load 190-250 KW
Engines Specifications
G-3516 A D-3412
Source Gas from well Source Diesel tank (10,000 bbl.)
Capacity 938 KW Capacity 648 KW
When Sinking Genset 1 to 2 (These parameters must be same)
AC Frequency 50 Hz
Voltage 400 V
Phase Angle 360°

 Throttle plate will operate through governor & EIS (Engine ignition system) is giving
command to governor. When throttle plate opens, mixture will go to 16 cylinders (972 KW).
16 Thermo couples are used to sense the temperature.
 Four stroke cycles will begin. Piston will suck on first, compression on second, ignition on
third & at last stroke flue gases will vent to atmosphere. The energy generate due to spark plug
in the 3rd
stage which rotates crankshaft through connecting rod.
 Engine contains a fly wheel which maintains the RPM of crankshaft.
 Crankshaft will rotate the alternator. Alternator will induce flux which generates the AC
supply.
 Through Slip rings supply will give to panel.
 First supply reaches to main breaker. Then it goes to load takeoff I then towards incomer II.
After it moves towards buscupler i.e. a main breaker which distributes supply to camp & plant.
Single Acting Dual Stage Reciprocating Compressor
Three compressors are installed which have:
 Design capacity 3.1 MMSCFD
 Operating capacity 2.5 MMSCFD
Compressor is not on operation condition due to following reasons:
 Actual working capacity 0.7 MMSCFD
To achieve the suction pressure of 200 psig, choke was increased by 50/64’’ which enhances the
water production. Due to increase in OPEX, JV partner was not willing to operate the compressors.
Definition
A gas compressor is a mechanical device that increases
the pressure of a gas by reducing its volume.
A single-acting cylinder in a reciprocating engine is a cylinder in
which the working fluid acts on one side of the piston only. A single-
acting cylinder relies on the load, springs, other cylinders, or the
momentum of a flywheel, to push the piston back in the other
direction. Dual stage refers to its compression in two stages.
At First Stage
 Cylinder I.D/ Bore 12
 Stroke: 11’’
 MAWP 600 Psi @ 200
At Second Stage
 Cylinder I.D/ Bore: 6.00
 Stroke: 11’’
 MAWP 1350 Psi

Components: The components are defined below:
Cylinders
The cylinder is a pressure vessel that contains the gas in the compression cycle. Single-acting
cylinders compress gas in only one direction of piston travel. They can be either head end or crank
end.
Crosshead Assembly
The crosshead assembly consists of a pair of shoes, the bolts and nuts to attach the shoes, and the
crosshead. A crosshead is a mechanism used in large reciprocating engines and reciprocating
compressors to eliminate sideways pressure on the piston.
Crankshaft
The crankshaft is the part of the engine that transforms the reciprocating motion of the piston to rotary
motion. The crankshaft rotates in the main bearings located at both ends of the crankshaft and at certain
intermediate points.
Connecting Rod
In a reciprocating piston engine, the connecting rod or conrod connects the piston to the crank or
crankshaft. Together with the crank, they form a simple mechanism that converts reciprocating motion
into rotating motion.
Working
In the first stage, gas flows through the inlet check valve and fills the larger diameter first-stage
cylinder. Pressurized hydraulic fluid, acting on the hydraulic piston, strokes the piston assembly to the
left compressing the gas in the first-stage cylinder. Gas in the first-stage cylinder flows through the
check valves into the smaller diameter second-stage cylinder.
At the end of the first stage, the four-way valve change position and directs pressurized hydraulic fluid
to the left side of the hydraulic piston. The piston assembly moves to the right compressing gas in the
second-stage cylinder. Gas flows out of the second-stage cylinder into the discharge gas line. The
piston assembly reverses direction at the end of the second-stage stroke and the cycle repeats.
In reciprocating compressors, the thrust of a positive displacement pump, within the cylinder, moves
the gas through the system. This thrust enhances both the pressure and the density of the gas being
transported. The compression process naturally causes the gas to heat up, so cooling is required before
it enters the next stage for further compression or before continuing on into the pipeline.

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