STUDENTS’ INDUSTRIAL WORK EXPERIENCE SCHEME

(SIWES) HELD AT

NNPC E&P LIMITED

NNPC
OGBA AIRPORT ROAD, BENIN CITY, EDO

STATE, NIGERIA. BY

ENABOIFO DESTINY DIVINE

SUBMITTED TO

DEPARTMENT OF MECHANICAL ENGINEERING

AMBROSE ALLI UNIERSITY.

IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE

AWARD OF BACHELOR OF SCIENCE (B.Sc.) DEGREE IN

MECHATRONICS ENGINEERING.
 Contents

Abstract - - - - - - - - - - 2
Acknowledgement - - - - - - - - - 3
Introduction - - - - - - - - - 4
Chapter one
The company’s symposium - - - - - - -
5
Chapter two
General Description of a Typical Oil Field - - - - - 11
Chapter three
Separation processes - - - - - - - - 32
Chapter four
Basic Operation Carried Out at the NNPC Flowstation / Well Site - 36
Chapter five
Integrated gas handling facility- - - - - - - 43
Conclusion - - - - - - - - - - 45
Recommendations - - - - - - - - - 46
References - - - - - - - - - - 47
Nomenclature - - - - - - - - - 47

Page 1 of 47
 Abstract
The introduction of students’ Industrial Work Experience Scheme (SIWES) into
the normal schools’ curriculum has opened up an avenue for students to acquire
a lot of experience, skills, information and knowledge during the period of
attachment to the company/ industry in order to supplement the theoretical
background of their chosen course of study and also to prepare them for the
challenges the future holds. This report is centered on my four month industrial
training program with Nigerian Petroleum Development Company, with
highlight on office and field activities such as monitoring the plant process,
operational calculation, control systems of NNPC e.t.c. The organizational
structure of the company is also included.

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 CERTIFICATION

This is to certify that ENABOIFO DESTINY DIVINE, with matriculation

number FET/MEE/18/47449 of the Department of MECHANICAL

ENGINEERING at the Faculty of Engineering, AMBROSE ALLI

UNIERSITY carried out an effective Student Industrial Training

Programme at NNPC E&P, under the Project Department NNPC E&P

Limited Ogba Road PMB 1262, Benin City, Edo state, with the much-

needed commitment and dedication.

Page 3 of 47
 DEDICATION

I ENABOIFO DESTINY DIVINE, will like to dedicate this technical report

to GOD ALIMIGHTY, first of all who saw me through my entire internship

and kept me safe all through. To my family who believed in me and gave

me all the support. To the Manager of Facilities Maintenance Department,

Engr Rahman Dauda my industry supervisor, who was always ready to help

and provide any basic knowledge. To all the NNPC E&P LIMITED staff

who I met through my internship. And to all my colleagues at NNPC E&P

LlMITED who 1 couldn’t mention them, may God bless you all. I say a big

Thank you. May God bless you all.

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 ABSTRACT

The introduction of students’ Industrial Work Experience Scheme

(SIWES) into the normal schools’ curriculum has opened up an avenue

for students to acquire a lot of experience, skills, information and

knowledge during the period of attachment to the company industry in

order to supplement the theoretical background of their chosen course of

study and also prepare them for the challenge of the future holds.

This is a report centered on the Student Industrial Work

Experience of ENABOIFO DESTINY DIVINE a 400 LEVEL student

of the department of Mechanical engineering undertaken at the (NNPC

E&P LIMITED), the exploration and production subsidiary of the

Nigerian National Petroleum Company Ltd (NNPC).

During my time at NNPC E&P LIMITED, I was led through siK

months of vigorous training in both field works which included the data

collection/acquisition, oil and gas production etc, and office works

which included processing of the data collected, writing of memos and

reports. All these were carried out under the close Supervision of Engr

Rahman Dauda. I was also made to undergo training in office

management and leadership social responsibility functions too.

This report contains a summary of the experience I received in

the company thanks to this industrial training scheme. Here is an

overview of the eKperience;

I learned

• How projects are being managed.

• How the oil and gas sector work i.e., how oil and gas is being produced.
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 • Health and safety and how to avoid accident in the field, site or office.

• How to relate in the professional world especially during meetings or jobs

Introduction

This report begins with the organizational structure of the company, where the
various departments in the company are briefly described with more emphasis
on the department I was trained and its sub-sections. There after a brief
description of the fields I have been to, with a detailed description of the various
processes and activities such as installation of automatic voltage switches in the
company air-conditioner system, repair and maintenance of generators,
Generator Synchronization, repair, maintenance of electric submersible pump,
laying of PVC cables, replacement of 3-phase rectifier for generators, perimeter
light installation, installation and test-running of electric submersible pump and
other engineering activities in field and office. Also included in this report are
the activities I participated in during my stay at the office such as review and
comment on process and instrumentation diagram of plant equipment, creation
of internal and external memorandum, document dispatch, etc.

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 Chapter One
Company’s Symposium
The Nigerian National Petroleum Corporation (NNPC) was formed on April
1st 1977, through the merging of Nigeria National Oil Company {NNOC} and
the ministry of petroleum. Section 1, 5 (d) of decree number 33 of 1977
constitution empowers NNPC to establish and maintain subsidiaries model. As
part of the commercialization program the NNPC has established the following
subsidiaries:

➢ Nigerian Petroleum Development Company Limited (NPDC)

➢ Integrated Data Services Limited (IDSL)
➢ Warri Refinery and Petrochemicals Company (WRPC)

➢ Kaduna Refinery and Petrochemicals Company (KRPC)

➢ Port Harcourt Refinery and Petrochemicals Company Limited (PHRC)

➢ Pipeline and Product Marketing Company Limited (PPMC)

➢ Eleme Petrochemicals Company Limited (EPCL) (DISSOLVED)

➢ National Engineering and Technical Company Limited (NETCO)

➢ Hydrocarbon Services of Nigeria Limited (HYSON)

➢ National Petroleum Investment Management Services (NAPIMS)

➢ Research and Development Division (RDD) (NEW)

1.1 Nigerian Petroleum Development Company (NPDC)
Nigerian Petroleum Development Company (NPDC) is an oil producing
company under the umbrella of NNPC and it plays a crucial role in the
exploration and production of crude oil in Nigeria. The company (NPDC) was
established as one of the eleven strategic business units (SBU) of NNPC in June
1988 at inceptions.
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The company was assigned ten concessions comprising of OPL 90 (offshore),
OPL 450 (onshore), OPL 477 (onshore tar), OML 64 (onshore), and OML 65
(swamp).

These departments/sections are listed below with their functions. Fig.

1.0 displays NPDC’s organogram.

Managing Director

EXECUTIVE DIRECTOR
EXECUTIVE DIRECTOR
ENGINEERING AND EXECUTIVE DIRECTOR EXECUTIVE DIRECTOR EXECUTIVE DIRECTOR
FINANCE AND
TECHNICAL SERVICE JOINT VENTURE OPERATIONS SERVICES
ACCOUNT
DIVISION

CIVIL AND SURVEY

DEPARTMENT

CAPITAL PROJECTS
DEPARTMENT

FACILITY
MANAGEMENT
DAPARTMENT

Fig. 1.0: A typical NPDC organogram

1.2.1 Exploration Department:

The function of this department is to find out and locate the region in which
crude oil reservoir can be found, through sampling of the rock or soil and
carrying out all type of seismic activities or survey in order to pin point the exact
location of the oil well and also to know quantity of crude oil in that deposit.
They also provide adequate information on the exact point to drill, the type of
rock, topography, size of well and other useful facts. The exploration
department also has a work station unit, where all the analysis of the data
obtained from the field during seismic surveys is logged on to the computer for
interpretation and simulation.

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1.2.2 Drilling Department

The department deals with the technology surround with drilling and casing of
oil well into the likely oil bearing formation. Drilling forms the final test of
exploration stage and first step of production stage. It is only by drilling into the
potential oil bearing rock structures that the presence or absence of oil can be
finally determined.

1.2.3 Engineering and Technical Services Division:

The engineering and technical services Division is concerned with the

following:
➢ Pipeline installation
➢ Electrification
➢ Road construction
➢ Minor and major repairs on machines
➢ Maintenance and servicing of equipment, etc.
There are three different sections in this department:-
Capital projects department: This department deals with every engineering
and procurement aspects in the company, it deals with capital intensive
engineering and procurement projects from various departments in the
company.
Facility Management Department: this section supervises pipeline
installation, welding, generator servicing, and general repairs on equipment, it
is also concerned with the electrification of buildings, circuit connections,
community electrification and so on.
Civil and survey department: This section makes plans and constructs
buildings. They are also concerned with the construction of roads to the
company’s flow stations and their operational areas.
1.2.4 Petroleum Engineering Department:

This department is known to be the assets owners. Here the main control of the
flow station is handled. This department is divided into three different sections
namely: Production operations, production technology and reservoir
engineering.
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1.2.4.1 Reservoir Analysis Section

This section run reservoir simulation model, estimate initial in place volume
reserve, construct a reservoir surveillance plan, monitor and improve reservoir
performance, perform fluid sampling and analyze fluid properties (PVT),
predict reservoir performance, design, implement and analyze well tests (BHP).

1.2.4.2 Production Technology Section

This section measures well and plant effluent, investigates all chemicals used in
drilling and production process, advises other functions on production chemical
subject, applies new technology for profitability, improvement, monitor well
performance and gives recommendation on required remedial measures,
preparation of short, medium and long production potentials for management
information, maintenance of adequate records for NAPIMS, DPR and for
studies, or procurement of well test data, well review acquisition of well cost
data, provision of program for well completion/work over jobs, forecast down
hole equipment requirement and also they takes care of well completion design
and engineering. They also carry out production test, by finding the percentage
of various impurities and other liquid contents associated with the crude oil
produced.

Basically, this section is involved in well completion, well surveillance and well
intervention.

1.2.4.3 Production Operations Section

The activities of this section can be grouped into:

1. Office activities like crude oil accounting, preparation of periodic reports

on flows stations, preparation of spread sheet for reconciliation of crude
oil quantities pumped, liaising with other department to ensure that
materials and services needed in the stations are provided on time,
definition of scope of work and tendering process, planning, organizing
supervision and surface well testing operation during the well completion
phase.
2. Field activities that consist of the flow station and well head operations.
The flow station operations includes periodic testing of the well in order

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 to measure well performance and the monitor of cumulative production
volume, monitoring of flow station equipment to detect problems,
operation of flow station equipment to ensure optimal and uninterrupted
production, injection of chemicals into crude oil stream at manifold in
order to achieve optimal separation. The well head operation includes
periodic pressure survey and crude oil sampling, injection of chemicals
at the well head in order to avoid flow line blockage.

1.2.5 Quality, Health, Safety and Environment Department (QHSE):

The activity of this department ranges from ensuring safety of the

environment, personnel and facilities of forestalling any hazard that could
pose a threat to human being and environment. The section also ensures
pollution control and general impact assessment. It also ensures the quality
control/improvement of the product.

The safety section, in addition to providing safety of the environment,

personnel and facilities, provides personnel protective equipment, combats fire
in the event of fire outbreak, maintenance of fire alarm system, servicing of
fire extinguisher etc.

Page 11 of 47
 Chapter Two
General Description of a Typical Oil Field
Oredo Flow station
At the Oredo field, there are five producing strings. These wells are dual
completed (i.e., Long and Short String). The wells are as follows, 2L, 4L, 5L,
7L, and 9S. Of all the wells, the 2L, 4L, 5L and 7L are oil wells, while the 9S is
a gas/condensate well (A gas condensate well is one in which the fluid is a gas
under reservoir condition but on getting to the surface, due to changes in
pressure and temperature condenses to liquid). Due to the dual completion, the
Oredo 2S, 4S, 5S, and 7S started producing gas. All Oredo wells are produced
by natural reservoir pressure and are also monitored constantly.
Oredo field has a mini-Flow station which has only two (2) separators (Test and
medium pressure MP), a degassing tank and two (2) 10000 bbl storage tanks, to
increase setting time which will result in better desanding (removal of sand) and
dewatering (removal of water).
In Oredo the flow station is shared into various categories and they each have
their functions, which we have FST1, FST2 and FST3

FLOW STATION 1
In FST1 hydrocarbons flow from the well head to the Manifold, The Manifold
is the assembly of headers. In FST1 we have a two-phase separator, which is
the Test separator and the MP Separator. From the Manifold the hydrocarbons
goes to the Test separator where the hydrocarbon will be broken down into
Oil, Water and Gas. The water goes to the flotation cell through the inlet and
to the saver pit where it is stored. The Oil goes to the degasser (A degasser is
a device used to remove dissolved and entrained gases from a liquid) to the
storage Tank. The Gas goes through the Knock out drum ( This is a device used
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to remove entrained liquid from the gas) before going to the Flare to avoid
thick soot and goes to the IGHF and Utilities.

Mp separator is a two-phase separator. It separates Oil and Gas. The gas that
has high portions goes to IGHF, Utility and Flare.

Oil goes to the degasser, mp separator to the storage tank.

In FST1, we produce about 5000 – 6000BBL of Oil per day and 10-15 Million
SCF of gas

FLOW STATION 3
Hydrocarbons goes from the wells, to the manifold and flexibility line.
Flexibility line is used to collect hydrocarbon from Fst1 and Fst2 from their
own manifold. The manifold is the central gathering point before sending them
to the separator according to their temperature and pressure. In Fst3 we have
Five (5) Manifolds , XHP 1and XHP 2 are connected to vertical separator, HP
and LP to the Horizontal separator. We also have the Mini manifold which
helps to re-direct hydrocarbon to beam line.
In Fst 3 we compress gas and send to OGPOOC (Oredo Gas Supply To
PanOcean Gas Plant)

2.1 Well Site

These are the areas where wells and Christmas trees are located. Each well site
is provided with a dual completion Christmas tree. The well stream from one
tubing string only is routed in a flow line provided with two chemical injection
points, surface safety valve and a high/low pressure switch. A well head control
panel is provided to operate both surface safety valves and the sub surface safety
valves. Closure of the SSV is initiated automatically by the pressure switch that
vents the hydraulic fluid. Manually operated button is provided to close both
SSV and SSSV during an emergency. The valves are opened using manually

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operated hydraulic pump, corrosion coupons are provided to monitor the
condition of flow line.

2.1.1 Automatic voltage switch

This is an electrical equipment that is used in protecting other electrical

equipment from high voltage, it serves as an interface between the source and
the equipment. The automatic voltage switch has three functions: to stop high
voltage, to stop very low voltage and to delay and examine the incoming current
before passing to the equipment.

Figure 2.0 automatic voltage switch circuit diagram.

2.1.2 Company substation

A substation is a part of electrical system where a voltage is transformed from

high to low or the reverse, or perform any of several other important functions.

There was a report about overheating of the company transformer. A visit to the
company substation was done with one of the project engineers to observe and
report about the working condition of the transformer, and the mechanically and
electrically connected sensors of the transformer. The sensors are as follows:

1. Voltage meter/indicator
2. Current meter/indicator
3. Lightening arrester

2.1.3 Equipment’s found in a substation

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The following equipment are found in a substation

1. Transformer: is a static electrical device that steps up or step down

electric voltage without change in frequency.

Figure 2.1 Distribution transformer

2. Feeder pillar: this provides local insulation to the electrical distribution
equipment, protecting both the cabling and the transform from fault. It
contains units and bus-bars for distribution.

Figure 2.2 Feeder pillar

3. Gang isolator: used in switching OFF and ON of the transformer. For
discontinuing electric from the source to the substation.

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 Figure 2.3 Gang isolator
4. Reinforced concrete cement pole (RCC pole): supports the cables and the
insulators in the substation.

Figure 2.4 RCC Pole

5. J&P Johnson and Phillip fuse: a protection device that cuts off when in
the events of high voltage. Also known as J&P fuse.

Figure 2.5 J&P Fuse

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6. HT cable/Riser cable (XLPE Cable): this is usually cross link
polyethylene cable and is used in supplying power to the high voltage
side of the transformer. It is a three core cable.

Figure 2.6 Single core HT cable

7. Bus-bar: this is a strip of copper conductor that is used to tap power
supply to the units. Located in a feeder pillar. Usually four.

Figure 2.7 Bus bars in a feeder pillar

8. Feeder pillar units: this is used in distribution of electric energy to various
units of the substation. Each unit is connected to bus-bar.

Figure 2.8 Feeder pillar units

9. LT cable (PVC cable): used to connect the low voltage side of the
transformer to the feeder pillar.

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 Figure 2.9 Low tension cable (PVC Cable)
10. Insulator: high resistance material used to isolate conductors from short
circuiting or touching each other.

Figure 2.10 Different types of insulators used in a substation

2.1.4 Maintenance of electric pump

An electric pump is an induction motor that is used in suction and discharge of

fluid. Crude oil, diesel and water are the fluid used in this pump.

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Figure 2.11 Electric pump

2.1.5 Types of maintenance of electric pump

1. Preventive maintenance: routine check up on the pump seals and

impeller, greasing of rotor ball bearing, tightening of the priming section
of the pump and test running it for two hours prior to maintenance report.
2. Corrective maintenance: replacement of rotor bearing, rewinding of the
stator coil, re-terminating of incoming cables to the pump at the control
panel, replacement of damaged cables to the pump, and replacement of
electric pump control panel.
2.1.6 Common Electric Pump Faults:

1. Single Phasing of Electric Pump: An electric pump is single phased if

there is a fault in one of the incoming lines to the pump, thereby causing
resistance to the motor rotation, this in turn causes overheating and if not
attended to burns the field windings.
Single Phasing is prevented by phase failure in the control panel. The
phase failure is one of the component of the control panel that helps to
cut supply when the incoming lines is not 3 phase. This happens due to
failure of one (or more) line(s).
2. Cavitation: This happens when air enters the liquid that is flowing
through the pump. This is a dangerous fault that can cause breakage of
the impeller. This is prevented by lowering the temperature of the liquid
being transported, reduce motor rpm (not applicable to all electric
pumps), and use of an impeller inducer.

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 3. Mechanical Faults: These faults are associated with the mechanical parts
of the pump. It includes wearing out of rotor ball bearings, cooling fan
blockage, and misalignment of motor parts and corrosion of motor parts.
These faults are prevented by carrying out routine preventive
maintenance on the electric pumps and ensure faulty parts are replaced
duly.
2.1.7 Common Tests carried out on Electric Pumps

During electric pump maintenance, they are three (3) basic tests that are carried
out to ascertain the electric motor’s fault. These tests are:

1. Insulation Resistance Test: this is used as a quality control measurement,

the insulation resistance test also known as a Megger is spot insulation
test which uses an applied D.C voltage.

Figure 2.12 Megger OHM meter

2. Continuity Test: This is used to ensure there is continuity in a conductor.

It is carried out by connecting the two ends of a conductor.
3. Earth Leakage: this test is designed to find out if there is any leakage
current flowing from the live wire to the earth wire.
Electric submersible pump

This is a device that has a sealed motor close coupled to the pump body. The
whole assembly is submerged to the fluid to be pump. There is no pump
cavitation in this pump.

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Electric submersible pump connection

Electric submersible pump connection was explained that the input is usually
single phase, a capacitor is connected in parallel with the phase to create a third
line which will operate the pump as a three phase. The figure below shows the
electric connection of an electric submersible pump.

Figure 2.13 Electric submersible pump electrical connection

2.1.8 Well Head and Xmas Tree

Wellhead is the equipment used to maintain surface control of the well. It is

usually made of steel, cast or forged and machined to desired specification. It
maintains sealing property that helps to prevent well fluid from blowing out or
leaking to the surface. A typical wellhead consists of a Xmas tree, casing head,
tubing head valves, pressure/temperature gauge, and stuffing box. Fig. 2.2
shows a typical well head.

The name Xmas tree depicts the shape and the large number of fitting/valve
network mounted and ready to distribute the goodies (oil for sale). Wells which
are expected to have high pressure (corrosive gases) are usually equipped with
special valve and control equipment above the casing or tubing head before such
wells are completed. These valves control the flow of oil and gas from the well.
The pressure gauges are part of the wellhead/Xmas tree to measure
casing/tubing pressure. By knowing the pressure under various operating
condition, it is better to have a better well control.
2.2 Flow Station

A flow station is a gathering centre where primary separation takes place. At

the flow station pipes are ran from the wellhead to the manifold, then to different
separators. NPDC presently has two flow stations namely Oredo and Oziengbe
flow station. Oredo and oziengbe flow stations are designed to carry out two
phase separations that is separating liquid phase (water and oil) from gas phase.

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2.2.1 Flow-Lines

These are steel pipes that convey crude oil from the producing wells to the flow
station. Fig. 2.3 shows a picture of flowlines.

Fig. 2.14 Flowline

2.2.2 Arrival Manifold

This is an inlet by which all crude oil flow-lines enters the flow station, the
essence of the manifold is for easy switching of crude oil from the well head to
different separators. The arrival manifold has ESD (Emergency Shut Down)
valves attached to the headers for automatic shut down should in case pressure
for a given header is exceeded or below it. Fig. 2.4 shows an arrival manifold.

2.2.3 Injector

This process plant equipment injects a chemical (demulsifier) into the medium
pressure manifold line before the crude gets into the separator. The chemicals
enhance the separation of oil and water. The chemical enhances the separation
of oil and water by breaking the emulsion bond formed between the oil and
water. Fig. 2.5 shows an injector at Oredo flow station.

The Emulsion formed can be either of the following:

➢ Primary emulsion, which can be oil-water emulsion or water-oil

emulsion.
➢ Secondary emulsion, which can be oil-water emulsion or water-oil
emulsion.

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 Fig. 2.15 Injector plant

2.2.4 Test Separator

The primary essence of a separator is to separate gas, water from the crude oil
and at the same time reducing the pressure at which the crude oil is coming from
the well. Test separator is similar in configuration as the other separators.

The different between test separator and any other separator is that the test
separator is equipped with measuring facilities to determine the potential of the
well that flow through it at any particular time. Measuring facilities such as
Digital flow Analyzer for measuring the quantity of crude oil and water
produced from the well, and also Daniel Orifice meter that measures the
quantity of gas produced from the well.

As the reservoir fluid flows into a separator, it falls on a baffle through the test
header inside the separator by so doing the liquids settles while gas escapes
through the gas line (vent). At the retention time with the help of gravity, the
crude oil that is less dense than water will settle at the top while water settles at
the bottom. Inside the oil/water interface chamber the oil settles on top of water
and over flows into the oil chamber. There is a floater designed there to send
the signal to the level controller, which in turn gives signal to the control valve
to dump the crude. This Separator can handle any form of pressure well, high,

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low and medium pressures. Fig. 2.6 shows the test separator at Oredo flow
station.

Fig. 2.16 Test separator at Oredo Flowstation

2.2.5 High Pressure Separator (HP)

HP separator have the same working principle as a test separator, the only
difference is that the HP is designed for reservoir fluids from high pressured
wells. The HP separator is designed to handle the bulk of the incoming
production from the high pressured well(s) and remove gas from the liquid.
Crude is fed into this separator via the HP header on the arrival manifold.

2.2.6 Medium Pressure Separator (MP)

MP separators has the same working principle as the test separators but the
difference is that the MP is designed for reservoir fluids from medium pressure
wells as pressure specified in separation staged. The well stream flows through
the MP separator for further processing. The MP separator is designed to
remove free water from the oil and remove gas from the liquid. Fig. 2.7 shows
an MP separator at Oredo flowstation.

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 Fig. 2.17 MP separator at Oredo Flowstation

2.2.7 Low Pressure Separator (LP)

LP separator has the same working principle as test separator but the only
difference is that, it is designed for low pressure wells as pressure specified in
separation staged. It is also designed to remove free water from oil that is
coming from the MP separator prior to sending the oil to surge tank or crude
storage tanks.

About 65% of the existing gas from the top far end of the test separator, MP
separator and HP separator is piped to HP flare knock out vessel, while 25% of
the gas is piped to fuel gas scrubber. The gas from the LP separator is vented to
the LP flare knock out vessel.

2.2.8 Flare Knockout Tank

These are tanks where produced gas is channeled. The tanks dry the gas by
allowing any liquid that is with the gas to that point to settle in it, so as to allow
the dried gas to be sent to the flare knock out stack where it is being flared. We
have two flare knock out tanks, they are the LP flare knock out tank and the HP
flare knock out tank. Gas from the test separator, HP and MP separators are
channeled to the HP flare knock out tank whereas the gas from the LP separator
is channeled to the LP flare knock out tank.

2.2.9 Pumps:

(a) Booster Pumps: These pumps collects crude oil from the crude oil storage
tanks and boost the pressure on the export line for the major export pump to
pick up on an adequate line pressure.

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(b) Export Pumps: These pumps depend on the pressure built by the booster
pump to suck and discharge crude oil for export.

(c) Produced Water Transfer Pumps: These pumps suck water from the
storage tanks and send it into the skimmer.

2.2.10 Water Degasser

This is the equipment that receives produced water from the separators and
extracts further traces of gas and oil from the water. The produced water
dumped by the HP, MP, LP and test separators is piped to the water degasser.
The degasser is also designed to remove large oil droplet from the water by
feeding oil water through the three sets of coalesce plate packs. The water
discharged from the water degasser is then sent to the floatation cell or
corrugated plate interceptor (CPI) for final treatment. The accumulated oil is
pumped to the closed drain sump tank. Any excess gas which breaks out from
the water, while inside the water degasser vessel is vented to the LP flare knock
out tank, and the water is sent to the skimmer pit.

2.2.11 Fuel Gas Scrubber

This process plant equipment traps gas from the gas header and purify it by
removing further traces of crude oil in it, with mixer or extractor, then send it to
the fuel filter. The fuel gas scrubber is designed to remove oil droplets from the
incoming gas to be used as fuel. The accumulated liquids are dumped to the
closed drain sump tank. The gas is then sent to the instrument gas filter
separator, which is designed to remove aerosols from the gas prior to sending
the gas to the end users, such as gas driven generator and cooking. Fig. 2.8
shows a fuel gas scrubber at Oredo flowstation.

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 Fig. 2.18 Fuel gas scrubber at Oredo flowstation

2.2.12 Closed Drain

The Closed Drain Sump Tank and Associated Diaphragm Pumps are designed
to accumulate the liquid from the closed drain header and then pump this liquid
back to the LP separator for reprocessing. This pump must be adjusted to
discharge oil from drain tank into LP separator and overcome the pressure inside
the LP separator. The drain tank basically operates at atmospheric pressure and
any pressure gases which accumulate inside the vessel are vented to atmosphere
through a vent type flare arrestor. Pump exhaust gas is piped into the drain tank
so that flammable gases are not present around the drain tank. The tank will be
place in a cement pit approximately 1 meter below grade to facilitate liquids
drain header draining into this vessel. A closed drain can be seen in Fig. 2.9.

Fig. 2.19 Closed Drain

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2.2.13 Corrugated Plate Interceptor (CPI)

Produced water is sent into this equipment and it purifies the water before sending it
to the produced water storage tank. There are many pumps used and they all perform
different function. The principle is the same as they suck liquid and discharges it into
the produced water storage tank or LP Separator for reprocessing. The pump must
be adjusted to discharge oil from drain tank into LP Separator and overcome the
pressure inside the LP Separator. The drain tank basically operates at atmospheric
pressure and any gases, which accumulate inside the vessel, are vented to the
atmosphere through a vent type flare arrestor. A corrugated plate interceptor can be
seen in Fig. 2.10.

Fig. 2.20 Corrugated plate interceptor

2.2.14 Produced Water Storage Tank

This store and preserves purified water produced from the process and serves as
a stand by for the firefighting unit in case there is an emergency. Fig. 2.11 shows
a produced water tank.

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 Fig. 2.21 Produced Water Tank
2.2.15 Crude Oil Storage Tank

These are vessels with high storage capacity where crude oil produced is stored
prior to pumping. The storage capacities of the two storage tanks in Oziengbe
flow station are 10,000 barrels each and 34 feet each in height. These tanks serve
as a center for decantation of water after being allowed to settle for at least 12
hours or more. These tanks allow gas liberation while limiting pressure loses
through evaporation. Crude oil storage tanks are seen in Fig. 2.12. The tank has
the following accessories:

➢ Production or Inlet pipe: generally fixed at the bottom of the tank and
internally extended with a perforated pipe rising in a cage. This device
acts as a separator, which permits the liberation of gas towards top and
helps to avoid the agitation of liquid hence promotes the draining.
➢ Discharge or export pipe: this is also fixed at the body of the tank at a
certain height, perforated and extended in the tank. It makes it possible to
discharge crude oil at the top.
➢ Drainage pipe: this is used to collect drains at the bottom of the tank.

➢ Overflow pipe:

➢ Circulation pipe:

➢ Man-hole: all storage tanks are equipped with one or two man-hole to be
used as an access into the tanks to carry out repairs or cleaning. All tanks
must also be free of gas before any work is carried out in order to avoid

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 explosion due to gas and air. Therefore to degas the tank, vapour may be
injected and then an explorimeter is used to verify if it has been degassed.
➢ Level controllers: these are liquid level indicator that gives direct reading
of liquid head.

Fig. 2.22 Crude oil storage tanks

2.2.16 Metering Unit

This is the export unit where all quantities of crude oil pumped out are
measured in barrels. In some cases the LACT (Lease Automated Custody
Transfer) unit is used. Fig. 2.13 shows a metering unit.

Fig. 2.23: Metering unit

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2.2.18 Flare Stack

This is the point where all the gas after being filtered from water and oil in the
flare knock-out tanks are flared. Fig. 2.15 shows a flare stack.

Fig. 2.25: Flare stack

2.2.19 Programmable Logical Control (PLC)

The programmable logical control panels controls all the system in the station
electrically (D.C). The PLC controls all the valves and it is designed to shut
down valve for safety reason. It also helps to control pressure from the well, the
PLC sense pressure from the SSV (sub safety valve) in case of excess pressure.
The PLC shut down the station with the aid of pressure transmitters that send
signal to the PLC, which knock off the solenoid.

2.2.20 Measurement and instrumentation in the Flow-station

Pressure Sensor

A pressure sensor is a device for pressure measurement of gases or

liquids. Pressure is an expression of the force required to stop a fluid from
expanding, and is usually stated in terms of force per unit area. A pressure
sensor usually acts as a transducer; it generates a signal as a function of the
pressure imposed.

Pressure Indicator

In a pneumatic pressure indicator, the pressure on the piston or diaphragm (the

sensing element) is transmitted by means of a rod to the arm of a recording
instrument, which registers the changes in the position of the piston or
diaphragm (that is, changes in pressure).
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Pressure Transmitter

This receives electrical signal from the sensor and sends the signal to a control
room. An engineer in the control room can monitor the pressure variations with
the help of the pressure transmitter.

Figure 2.26 Pressure sensor, pressure indicator and pressure transmitter.

Temperature Sensor

A temperature sensor is a device, typically, a thermocouple or RTD, that

provides for temperature measurement through an electrical signal. A
thermocouple (T/C) is made from two dissimilar metals that generate electrical
voltage in direct proportion to changes in temperature.

Temperature Indicator

A temperature indicator was defined as a device that works in connection with

a temperature sensor, used for indicating the degree of hotness or coldness of a
body.

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Temperature transmitter

This also receives information from the temperature sensor and sends the signal
to the control room. Temperature variations in the plant is monitored using the
signal received from the transmitter. The figure below shows a temperature
transmitter.

Figure 2.27 Temperature transmitter

Chapter Three:
Separation Process

Separation of well stream gas from free liquids is the first and most critical stage
of field-processing operations. Separators work on the basis of gravity
segregation and/or centrifugal segregation. A separator is normally constructed
in such a way that it has the following features:

➢ It has a centrifugal inlet device where the primary separation of the liquid
and gas is made.
➢ It provides a large settling section of sufficient height or length to allow
liquid droplets to settle out of the gas stream with adequate surge room
for slugs of liquid.
➢ It is equipped with a mist extractor or eliminator near the gas outlet to
coalesce small particles of liquid that do not settle out by gravity.

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 ➢ It allows adequate controls consisting of level control, liquid dump valve,
gas backpressure valve, safety relief valve, pressure gauge, gauge glass,
instrument gas regulator, and piping.

The centrifugal inlet device makes the incoming stream spin around. Depending
on the mixture flow rate, the reaction force from the separator wall can generate
a centripetal acceleration of up to 500 times the gravitational acceleration. This
action forces the liquid droplets together where they fall to the bottom of the
separator into the settling section. The settling section in a separator allows the
turbulence of the fluid stream to subside and the liquid droplets to fall to the
bottom of the vessel due to gravity segregation. A large open space in the vessel
is required for this purpose. Use of internal baffling or plates may produce more
liquid to be discharged from the separator. However, the product may not be
stable because of the light ends entrained in it. Sufficient surge room is essential
in the settling section to handle slugs of liquid without carryover to the gas
outlet. This can be achieved by placing the liquid level control in the separator,
which in turn determines the liquid level. The amount of surge room required
depends on the surge level of the production steam and the separator size used
for a particular application.
Small liquid droplets that do not settle out of the gas stream due to little gravity
difference between them and the gas phase tend to be entrained and pass out of
the separator with the gas. A mist eliminator or extractor near the gas outlet
allows this to be almost eliminated. The small liquid droplets will hit the
eliminator or extractor surfaces, coalesce, and collect to form larger droplets
that will then drain back to the liquid section in the bottom of the separator.

3.1 Types of Separator

Three types of separators are generally available from manufactures based on

configuration: vertical, horizontal and spherical separators. Each type of
separator has specific advantages and limitations.
3.1.1 Vertical Separator

Fig 3.1 shows a vertical separator. Vertical separators are often used to treat low
to intermediate gas–oil ratio well streams and streams with relatively large slugs
of liquid. They handle greater slugs of liquid without carryover to the gas outlet,
and the action of the liquid level control is not as critical. Vertical separators
occupy less floor space, which is important for facility sites such as those on
offshore platforms where space is limited. Because of the large vertical distance
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between the liquid level and the gas outlet, the chance for liquid to revaporize
into the gas phase is limited. However, because of the natural upward flow of
gas in a vertical separator against the falling droplets of liquid, adequate
separator diameter is required. Vertical separators are more costly to fabricate
and ship in skid-mounted assemblies.

Fig 3.1: A typical vertical separator

3.1.2 Horizontal Separator

Fig 3.2 presents a sketch of a horizontal separator. Horizontal separators are

usually the first choice because of their low costs. They are almost widely used
for high gas–oil ratio well streams, foaming well streams, or liquid-from-liquid
separation. They have much greater gas–liquid interface because of a large,
long, baffled gas separation section. The liquid-level control placement is more
critical in a horizontal separator than in a vertical separator because of limited
surge space. Horizontal separators are easier to skid-mount and service and
require less piping for field connections. Individual separators can be stacked
easily into stage-separation assemblies to minimize space requirements.

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 Fig 3.2: A typical horizontal three-phase separator.

3.1.3 Spherical Separators

A spherical separator is shown in Fig. 3.3. Spherical separators offer an

inexpensive and compact means of separation arrangement. Because of their
compact configurations, this type of separator has a very limited surge space
and liquid settling section. Also, the placement and action of the liquid-level
control in this type of separator is very critical.

Fig. 3.3: A typical low-pressure spherical separator.

3.2 Factors Affecting Separator

Separation efficiency is dominated by separator size. For a given separator,

factors that affect separation of liquid and gas phases include separator
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operating pressure, separator operating temperature, and fluid stream
composition. Changes in any of these factors will change the amount of gas and
liquid leaving the separator. An increase in operating pressure or a decrease in
operating temperature generally increases the liquid covered in a separator.
However, this is often not true for gas condensate systems in which an optimum
pressure may exist that yields the maximum volume of liquid phase. Computer
simulation (flash vaporization calculation) of phase behavior of the well stream
allows the designer to find the optimum pressure and temperature at which a
separator should operate to give maximum liquid recovery. However, it is often
not practical to operate at the optimum point. This is because storage system
vapor losses may become too great under these optimum conditions.

In field separation facilities, operators tend to determine the optimum conditions

for them to maximize revenue. As the liquid hydrocarbon product is generally
worth more than the gas, high liquid recovery is often desirable, provided that
it can be handled in the available storage system. The operator can control
operating pressure to some extent by use of backpressure valves. However,
pipeline requirements for Btu content of the gas should also be considered as a
factor affecting separator operation.

Chapter Four:
Basic Operation Carried Out at the NPDC Flowstation / Well Site

4.1 Chemical Injection (Demulsifier)

Chemical injection is an essential operation carried out in the field because at

some point in the life of every oil well, an unacceptable amount of water will
be produced with the oil. Water usually seeps into the formation as oil and gas
are produced from the reservoir. Generally the older the well, the more the water
it produces. Crude oil and water mixture, which do not easily separate, are
referred to as emulsions and must be treated to break the emulsions. Though
treating emulsion is an expensive process, but to ensure treating is done at the
lowest cost properly sized equipment must be installed, maintained and
monitored. Complete record should be kept.

An emulsifying agent is a substance that promotes the formation and stability

of an emulsion. The emulsifying agent collecting on the surface of water
droplets and forming a tough film, which keeps the droplets from joining,
accomplishes this. Emulsifying agents commonly found in oil field emulsions
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include asphalt, resins; paraffin’s and oil soluble organic acids. Different
emulsifying agents occur naturally in different reservoirs.

4.1.1 Emulsion Stability

A stable emulsion is one, which will not breakdown or separate without some
form of treating. The stability of an emulsion depends on several factors:

(a) Emulsifying agent: The effect depends on the type of agent and conditions
under which it occurred.

(b) Viscosity of oil: Oil with a high viscosity (resistance to flow) tends to keep
water droplets in suspension creating a more stable emulsion.

(c) A.P.I gravity of oil: Oil with a low A.P.I gravity tends to keep water droplets
in suspension creating a more stable emulsion

(d)Water percentage: Generally, a small percentage of water in an emulsion

means greater stability.

(e) Agitation: Increased agitation means greater dispersion of water and greater
stability.

(f) Droplet size: Emulsions containing small water droplets are more stable
because small droplets are lighter and will not settle out as easily.

(g) Age of Emulsion: The longer an emulsion remains untreated, the harder it
is to break.

4.1.2 Effects of Emulsion

The effects of emulsion in process plant are very numerous, they include:

➢ It reduces the efficiency of the pumps since it will pump emulsion with
high viscosity, which the pump are not designed for.

➢ It aids corrosion since the pump line is not designed to pump water but
crude with reduced percentage of water in traces.

➢ It is a waste of energy.

It is not economical because crude is designed to be separated, processed

and not water, since water is not marketed in the oil industry.

4.1.3 Emulsion Treatment

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Treating of emulsion is usually done in the field using various types of
equipment like free-water knockouts, separators, heater treater, electrostatic
treater, etc. and by adding chemicals to the emulsion immediately after it is
produced.

In other to break an emulsion, the film must be neutralized or destroy by using

treatment methods. Treating emulsions may include one or more of the
following procedures: allowing setting time, applying heat, injecting chemicals,
using electricity or operating mechanical devices.

4.2 Well Testing

This activity is usually carried out to determine the potential of a well by

allowing the fluid from the well flow through the test separator at a particular
time. Measuring facilities such as rostrum meters for measuring the quantity of
crude oil and water produced from the well and also Daniel orifice meter to
measure the quantity of gas produced from the well are used.

4.3 Bean Inspection

Bean inspection is carried out to check if the choke has been eroded or blocked
by scale or wax. The easier way of determining whether the choke has problem
is if the tubing head has the same pressure with the flow line or an increase in
flow line rate with a decrease in tubing head pressure. While caring out bean
inspection it is important to ensure that the master and wing valves are closed
to avoid crude flow from the well and as well as the flow line valve to avoid
back flow from the flow station.

4.4 Pressure Survey

Pressure survey is carried out to determine the pressure of the well and as well
another means of detecting if the choke as eroded, waxy blockage or scale in
the choke. To accurately determine the pressure of a well we have to use a
pressure gauge with rating that is three times greater than the expected pressure
of the well. The tubing head pressure is determined by placing the pressure
gauge at the top adaptor. While the flow line pressure is obtained from the
sample point in the flow line.

4.5 Pig Launching Operation

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Pig launching operation is carried out by launching Pigs/brushes into the export
line to help clear the line of dirt and corroded portions in order to facilitate the
crude flow.

To carry out this operation these are the procedures to be followed:

➢ Maximize the stock of crude oil before pig launching. If possible, fill all
the tanks before starting.
➢ Close pipeline gate valves upstream and downstream of pig launcher.
➢ Open drain valve on pig launcher to drain crude oil into flare knockout
tank.
➢ Open pig launcher barrel with brass hammer.
➢ Launch a befitting rigid pig into the pig barrels. Ensure tie-in pig is being
pushed in beyond the bye pass to export line.
➢ Close all drains, open bye – pass valve to pig launcher and gate valves
upstream and downstream of pig launcher.
➢ Commence shipment from one of the tanks after launching the pig
➢ Observe pig movement to ensure it flags off.
➢ Continue shipment non – stop for at least 8 to 10 hours to be sure that the
pig arrives Ogharafe LACT unit.
➢ Mobilize to the LACT unit to receive pig during daylight hours.
➢ Stop shipment to enable you receive pig at the LACT unit end and
observe flag to see if pig has arrived.
➢ Close gate valve upstream and downstream of pig launcher.
➢ Open drain valves to drain crude oil into the sump pit.
➢ Open receiver barrel to remove the pig.
➢ Close back the receiver barrel.
4.6 Crude Oil Shipment

Shipment of crude oil commences when the crude in the storage tank has been
built to a considerable level, some water is still contained in the tank which is
then allowed to settle down after some hours; because water is denser than oil.
The water is first drained from the bottom with the pump before shipment
begins. To start shipment, the booster pump is switched ON before the export
pump. The pressure reading of the export pump is taken and recorded as
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discharge/export line pressure (DELP). Shutting down the export pump is the
reverse of starting. Before shipment begins, the panel in the control room is first
acknowledged and then reset. Sometimes shipment may be difficult when the
pressure of the export pump is low. It might also be due to low level in the
storage tank. The pump may also cavitate thereby vibrating ceaselessly and
consequently shutting down.

Gear oil and harmony oil are the two important lubricants used in running the
export pump and needs to be refilled when their levels fall. Harmony oil is
otherwise called light/compressor oil. During shipment, the crude oil level in
the storage tank where export is taking place and the reserve storage tank are
taken and recorded continuous for every two hours. There is a side glass
attached to the storage tank which shows the level of crude contained in it.
Shipment of crude can only be done with one export pump, one booster pump
and from one storage tank at a time. During shipment, the level of crude oil in
the reserved storage tank is built up. When building up levels in a tank, the
produce line and the drain line of that storage tank are opened while the over
flow line and the export line are closed. Most times there may be needed to
divert production from one tank to another. In this case, the production line of
the storage tank where diversion is directed to is first opened before the opening
of the production line and drain line of the tank where diversion is coming from.
After shipment has been terminated, a daily production report is written which
shows the quantity of barrels shipped for that particular day.

Chapter five:
Integrated Gas Handling Facility (IGHF)

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The Integrated Gas Handling Facility (IGHF) which is located at the Oredo
field, Edo state was commissioned in 2013. IGHF was necessitated by the
federal government’s regulations to improve power supply, generate
employment opportunities as well as eliminate gas flaring in compliance with
government’s environmental requirements. This facility which is designed to
mainly produce methane has a capacity to produce 100 MMSCF/D. The early
first gas phase is currently delivering 45MMSCFD to the Ihovbor Independent
Power Plant (IIPP) and the remaining 20MMSCFD to the domestic market for
other users through the Escravos-Lagos Pipeline System (ELPS).
When completed, the facility will fully operate in five gas processing stages:
compression, dehydration, refrigeration, fractionation and then to the metering
unit. These different stages will be described in details in the next sections. But,
at present the facility is only operating the compression stage, otherwise known
as the Early First Gas mode. The feed for IGHF is from the Early Production
Facility (EPF) at Oredo flowstation.
Natural gas processing is carried out through the following stages as shown
below:

Compres Dehydrat NGL

sion ion removal

Sales Metering Fractionation

Figure 5.1 IGHF gas treatment sequence

5.1 Compression Stage
The compression stage consists of three (3) reciprocating double stage
compressors, scrubbers, inter and after coolers (aerial coolers), shutdown
valves, relief valves.
Pressure plays a major role in gas processing, as it moves gas from the field,
through the gas plant, and into the sales gas line. When a gas has insufficient
potential energy for its required movement, a compression station must be used.
The essence of the compressor is then to increase the gas pressure. The first
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stage compression at the IGHF increases the gas pressure from 200 psi to about
400 psi, while the second stage compression increases the gas pressure to above
900 psi.
A scrubber is placed before the compressor’s inlet to remove any liquid
entrained in the gas stream, as the liquid may reduce the efficiency of the
compressor or even damage it. The intern and after coolers are very important
in the gas compression because when a gas is compressed heat is generated.
This heat can cause two major problems. First, most compressors are oil
lubricated and excess heat can cause the oil to lose its lubricating characteristics.
If this occurs, the compressor’s internal components can be severely damaged.
Secondly, gases expand when they are heated, and since a compressor is
designed to compress gases, this effect creates an additional force the
compressor must overcome i.e. more work is required to compress a given
amount of gas when the gas is heated.

Conclusion

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I had a tremendous experience during my training at NPDC. Within the duration
of six month, I was able to visit the flow stations and rig site. The experience I
was able to gather, I believe will be of relevance to my career now and in the
future. I learnt about the operations going on at the various flow stations and
how most of the separating plants works and also how to carry out daily
production reading and calculations.

I thank God for such an opportunity to get all these experience during my six
months industrial training.

RECOMMENDATION
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 Based on my experience with NPDC, I thereby make the following
recommendation:

1) Federal government should make amendments to the industrial training of

university students by reviewing and reworking the period and emoluments
given to them.

2) Also the Industrial Training Fund (ITF) officials should be paying regular visit
to industries/factories where industrial trainees are, to access their level of
performance and to ensure they were well placed in the area patterned to their
discipline.

3) Finally I wish to recommend this report to the entire IT students in the oil related
disciplines.

REFERENCES
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NNPC website

Process plant equipment procedure by NPDC

Flow station production operation manual by NPDC

NPDC library

NOMENCLATURE
BS&W = Basic sediment and water

BOPD = Barrels of oil per day

BLPD = Barrels of liquid per day

BHP = Bottom hole pressure

CPI = Corrugated plate interceptor

DST = Drilling stem testing

ESD = Emergency shut down

SSV = Surface safety valve

SSSV = Subsurface safety valve

SCSSV = Surface control subsurface safety valve

SBU = Strategic business unit

THP = Tubing head pressure

FLP = Flow line pressure

GOR = Gas oil ratio

MCC = Motor control center

OML = Oil mining lease

PSI = Pounds per square inch

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