PIOTR BLAUT Student Placement Report

2015
Piotr Blaut
Department of Physical Sciences
Kinsale Energy Limited Cork
Abstract
This document contains a report on my placement during which I had a chance to participate in a
number of very interesting projects. I was also given opportunity to explore the process of
injection, extraction, dehydration, analysis, metering and transportation of natural gas. The subject
of my studies and projects were also systems not directly related to the production of gas but
crucial to the safety as Fire and Gas Detection and Mitigation System.
Submitted in partial fulfilment of the regulations for a
BSc Applied Physics and Instrumentation
Student: Piotr Blaut
Kinsale Energy Limited Supervisor: Mr. Paul Dowling, Control System Engineer
CIT Supervisor: Mr. Harvey Makin

Piotr Blaut IP3 Student Placement Report
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Contents
1. Abstract...................................................................................................................................1
2. Contents..................................................................................................................................2
3. CHAPTER I................................................................................................................................5
Student Work Placement...................................................................................................................5
1. Summary......................................................................................................................................5
2 Student Placement Projects............................................................................................................5
3. PSE Kinsale Energy Limited..........................................................................................................7
3.1 Company History .....................................................................................................................7
3.2 Natural Gas .............................................................................................................................7
3.3 Gas Production........................................................................................................................8
3.4 Gas Storage .............................................................................................................................8
2.5 The future of Gas Storage in Ireland..........................................................................................8
4. CHAPTER II...............................................................................................................................9
Natural Gas Processing......................................................................................................................9
1. OFFSHORE GAS PRODUCTION........................................................................................................9
2. Subsea........................................................................................................................................10
2.1 X-mas Trees...........................................................................................................................11
3. Seven Heads Gas Processing System.............................................................................................13
Gas and water separation .............................................................................................................14
Level measurement......................................................................................................................15
Types of valve.............................................................................................................................15
Valve Actuators...........................................................................................................................17
4. Wellhead & Separation................................................................................................................20
5. Gas Compression ........................................................................................................................21
5.1 Compression Train 1 ..............................................................................................................21
5.3 Compressor control ...............................................................................................................23
6. Gas Dehydration .........................................................................................................................25
6.1 Gas DehydrationPrinciples.....................................................................................................26
7. Injection & Compression..............................................................................................................29
8. Metering & Pigging......................................................................................................................30

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9. Inch Onshore Metering Terminal..................................................................................................31
9.1 GAS FISCAL METERING...........................................................................................................32
9.2 Flow measurement using the Orifice Flow Meter.....................................................................32
9.3 Natural Gas Analysis - Gas Chromatography............................................................................36
9.4 Natural Gas Analysis - Gas Moisture Analysis...........................................................................39
5. CHAPTER III............................................................................................................................43
1 Safety Systems.............................................................................................................................43
1.1 Fire & Gas Detection System...................................................................................................43
1.2 Gas Detection Principles.........................................................................................................46
1.3 Flame Detection Principles.....................................................................................................49
1.4 SMOKE DETECTION................................................................................................................52
1.5 Emergency shutdown and process shutdown..........................................................................53
2. Platform Utilities.........................................................................................................................55
2.1 Power generation..................................................................................................................55
2.2 Diesel System........................................................................................................................56
2.3 Instrument Air.......................................................................................................................56
2.4 Nitrogen Generation and Backup............................................................................................56
2.5 Seawater Lifting and Filtration................................................................................................56
2.6 Fresh Water...........................................................................................................................56
2.7 Fire Water.............................................................................................................................57
2.8 Fuel Gas ................................................................................................................................57
2.9 Drainage System....................................................................................................................57
6. CHAPTER V.............................................................................................................................58
7. Work Placement Projects........................................................................................................58
1. SKID 5 Modernization Project.......................................................................................................58
1.1 Project Introduction...............................................................................................................58
1.2 Project Assumptions ..............................................................................................................58
1.3 Project Summary ...................................................................................................................58
2. Fire and Gas Detection System Tagging and Drawings Update Project............................................60
2.3 Project Summary ...................................................................................................................60
3. Flame Detectors Field of View Adjustment Project........................................................................62

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3.3 Project Summary ...................................................................................................................62
Example with Sample Data..........................................................................................................63
8. REFERENCES...........................................................................................................................65
9. Figures and Tables..................................................................................................................70
10. ACKNOWLEDGEMENTS ...........................................................................................................72

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CHAPTER I
Student Work Placement
1. Summary
The work placement for me was exactly the same as a military training ground experience for a
soldier. Primarily, I achieved practical experience of the day to day work that is involved in PSE
Kinsale Energy Limited, which previously had just been a theory to me. The work that I did
improved my self-confidence, communication skills, and problem-solving skills. Because I had a
chance to work in an extremely demanding environment of the offshore platform, I particularly
learned about safety procedures and practices that would not arise in other industries. All in all the
work experience has reinforced my decision to pursue a career in instrumentation and has given
me plenty of ideas for my fourth year thesis. Work placement as part of my course was a valuable
opportunity to learn from professionals at work and put the theory I studied into practice. I have
been given a lot of responsibility in my placement and through having that responsibility I have
gained a lot of valuable experience. Additionally I have always wanted to experience what it
would be like to work in a demanding offshore platform environment.
The integral part of my work placement was also the Basic Offshore Safety Induction &
Emergency Training (BOSIET) which I went through in January. This 3 Day offshore course is
designed to assist in meeting the initial onshore safety training, emergency response training and
assessment requirements for personnel new to the offshore oil and gas industry [21].
2 Student Placement Projects
During my work placement I was involved in a number of company projects, practicals and
assignments. Before I was be able to become a helpful with the company projects I had to
familiarize well with used gas processing and transporting system and also all the supporting
systems like:
 Gas Extraction Process
 Wellhead and Separation

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 Gas Dehydration and Glycol Regeneration
 Gas Compression and Injection
 Gas Metering and Pigging
 Gas Analysis Systems
 Gas Moisture Analysis Systems
 Instrument Air System
 Fire and Gas (F&G) Detection and Mitigation System
 Emergency Shutdown and Process Shutdown
 Power Supply and Power Generation Systems
 Diesel System
 Seawater Lifting and Filtration
 Fresh water
 Fire water
 Instrument Air
 Nitrogen Generation and Backup System
 Drainage System
The subjects of my study were also a number of analytical devices, various process
instrumentation and detectors used both in the gas processing and supporting processes.
 Gas Moisture Analysis
 Gas Chromatography
After familiarizing with most of the systems and process instrumentation used in the production
and transportation of gas I was ready to become a valuable member of the Kinsale Energy
Limited Engineering and Maintenance Department team.
Abreast guided and supervised by Mr Paul Dowling, Control System Engineer I took part in
several interesting projects:
 Glycol Regeneration System Upgrade Project
 Fire and Gas Detection System Tagging and Drawings Update Project
 Flame Detectors Field of View Adjustment Project
The full report of my work placement activities was presented in this document.

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3. PSE Kinsale Energy Limited
PSE Kinsale Energy Limited [1], (formerly Marathon Oil Ireland Limited), has been producing
natural gas from its facilities off the Old Head of Kinsale since 1978. The company was acquired
by PETRONAS in April 2009 and currently employs 59 people. PSE Kinsale Energy Limited
operates the Kinsale Head, Ballycotton and Seven Heads Gas Fields in the Celtic Sea and also
operates a natural gas storage field (Southwest Kinsale) [2].
3.1 Company History
Exploration for offshore oil & gas began in Ireland during the early 1970’s. The Kinsale Head Gas
Field was discovered in 1971 by the Marathon Oil Corporation and production began in 1978.
Peak production occurred in 1995 at 99 billion cubic feet [bcf] per year. The field is now in the
decline phase and current annual production is 8 bcf per year [3]. A number of satellite gas fields
were discovered and tied back to the platforms including Ballycotton in 1991, Southwest Kinsale
in 1999 and Seven Heads in 2003.
In 2001, the company redeveloped the Southwest Kinsale field into Ireland’s first gas storage
facility. The Kinsale Head Gas Field which is 50 kilometers off the coast of Co. Cork in 90
meters water depth and 915 meters beneath the floor of the Celtic Sea is still the largest single
hydrocarbon discovery in Ireland and PSE Kinsale Energy Limited is currently the only
company producing natural gas from Irish offshore waters. The natural gas in Kinsale Head is
produced to surface through two fixed steel production platforms: Alpha and Bravo, connected by
pipeline to an onshore terminal at Inch. The company was acquired by PETRONAS [2] in 2009,
following a decision by Marathon Oil Corporation to exit the Irish market. PETRONAS is a
major Fortune 500 oil and gas company [3].
3.2 Natural Gas
Hydrocarbons, such as natural gas and crude oil, are formed from the decay of plants and minerals
which have been buried for millions of years. They are found in porous rock formations in which
the gas or oil is stored in the spaces between the rock particles, like the pores in a sponge. Natural

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gas is generally composed of methane and other gases, such as ethane or propane [4].
The natural gas found at Kinsale Head is extremely pure consisting mainly of methane and
requires no processing, apart from separation of water, before piping to the natural gas grid [4].
3.3 Gas Production
The Kinsale Head, Ballycotton, Seven Heads and Southwest Kinsale Gas Fields lie
approximately 50 kilometers off the south coast of Cork. The gas bearing reservoirs are in layers
of porous sandstone rock about 750m below the seabed. These rock layers are relatively thin –
about 120 meters, but they cover a large area – the main Kinsale Head reservoir extends over 100
square kilometers. The rocks were formed in the Cretaceous geological era – around 100 million
years ago and the gas is contained in the sandstone under layers of shale and chalk, which are
impermeable to gas.
3.4 Gas Storage
Gas Storage is based on the principle of injecting gas into an under-ground reservoir during the
summer months when gas demand is low, and taking it out of storage during periods of high
demand in the winter [7]. The Southwest Kinsale Gas Reservoir is in the Upper Cretaceous
sandstones covering an area of 1,200 hectares in size, 800 meters below the sea bed. The
Southwest Kinsale Gas Field was redeveloped in October 2001, whereby gas could be taken from
nearby offshore gas fields and put into storage in the Southwest Kinsale reservoir. This allowed
the field to be used to meet the seasonal requirements of the Irish gas market. In 2006
modifications were made to enable gas taken from the onshore network to be stored in Southwest
Kinsale and the gas field was converted to a fully-fledged offshore storage facility with a
storage capacity of 230 million cubic meters (1 cubic meter of gas is equivalent to about 10 kW-
hours of energy) with a maximum withdrawal and injection rate of 2.6 mscm/ day and 1.7 mscm/
day respectively. The facility is licensed by the Commission for Energy Regulation (CER) [7].
2.5 The future of Gas Storage in Ireland
PSE Kinsale Energy Limited supports the development of further Gas Storage in Ireland. This will
not only help to meet Irish energy needs into the future, but will also offer additional security of
gas supply and electricity generation for the country [5].

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CHAPTER II
Natural Gas Processing
1. OFFSHORE GAS PRODUCTION
The gas found in the Kinsale Head area is exceptionally pure, consisting mainly of methane, and
only requires removal of associated water to ensure it meets the required quality levels [6]. This
conditioning is carried out offshore (See Fig 1) and the gas is then compressed to raise its pressure
for transport to the Kinsale Energy Inch Terminal near Midleton, Co. Cork. From the Inch
Terminal, the gas is then metered and transferred to Bord Gáis Éireann (BGÉ) for distribution
nationwide [6].
Figure 1 Platform Alpha Gas Processing Train
Note: Process gas flow unit mmscfd (million standard cubic feet of gas per day). 1 million
standard cubic feet of gas per day (MMSCFD) of gas flow = 1,179.87 cubic meters per hour
(m3/h) in flow rate.

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2. Subsea
Seven Heads subsea field has five subsea x-mas trees [8] (See Fig 4 and 5) and is connected to the
platform Alpha by a dedicated 18" subsea pipeline. Control of the subsea tree valves is via an
electro/hydraulic subsea umbilical from the Alpha control system with in-field umbilicals [9] (See
Fig 6) from the Seven Heads manifold to each of the wells (See Fig 2 and 3).
Figure 2 Kinsale Head Area Subsea (P&ID A-012-04-5010A)

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Figure 3 Subsea process flow schematic and operating ranges (P&ID A-012-04-5010B)
Table 1 Subsea equipment and operating ranges
2.1 X-mas Trees
Offshore platform x-mas tree [8] (See Fig 4) is an assembly of valves which controls the flow of
gas and separates the well from the production platform. The x-mas tree sits on the top of the well
head casing system and represents the interface between the well and the production facility. A
christmas tree typically consists of the following valves:
 MasterValve [8] - isolates the X-mas trees from the production tubing (normally has
upper master valve actuated type and lower master valve manually operated.
 Wing Valve [8] - a christmas tree may have one or two wing valves. One valve is actuated
type and connected to the process system. The other valve is manually operated.
 Swab Valve [8] - positioned directly above the master valve and permits entry into the
well when wire-line equipment is attached.

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Figure 4 offshore platform x-mas tree
The subsea production tree [8] is an arrangement of valves, pipes, fittings and connections placed
on top of a wellbore.
Figure 5 subsea x-mas tree
Umbilical [9] (See Fig 6) provide control, power, communications and chemical services between
a subsea production arrangement and the platform. Umbilicals may be used for production
control, chemical injection, subsea pumping and processing, gas lift and underground gas storage
among others.

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Figure 6 subsea umbilical
3. Seven Heads Gas Processing System
Gas from the Seven Heads riser enters the inlet separator V-8000 [10] (See Fig 8). The gas has
enough residence time in the separator for free water to separate out. It is then metered by using
the annubar flow meter [11] (See Fig 9) before co-mingling with Kinsale Gas in the Production
Manifold (See Fig 7).
Figure 7 Seven Heads process flow schematic (P&ID A-012-04-5030A)

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Table 2 7 Heads equipment and operating ranges
Gas and water separation
Separator/Scrubber - a pressure vessel used for separating gas and water [10] (See Fig 8). The
retention period is typically five minutes, allowing gas to bubble out, water to settle at the bottom
and oil to be taken out in the middle. The pressure is often reduced in several stages (high pressure
separator, low pressure separator, etc.) to allow controlled separation of volatile components. A
sudden pressure reduction might allow flash vaporization leading to instability and safety hazards.
The idea is to achieve maximum water separation. In this platform the water cut (percentage water
in the well flow) is almost 6%. In the first stage separator, the water content is typically reduced to
less than 1.5%.
Figure 8 3 - phase horizontal inlet separator

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Level measurement
Magnetic Level Gauge - employ two elementary principles [33]:
 the buoyancy of a body immersed in a liquid that is equal to the weight of displaced liquid
 phenomenon of attraction among dissimilar poles of permanent magnets
The magnetic gauge is designed so that the measured fluid is enclosed within the sealed chamber
and inside this chamber a float fitted with permanent magnet moves freely. As the fluid level
changes the magnetic float is tripping the indicator flags outside the chamber and also stimulates
any attached transmitters and switches, providing a signal back to the DCS/SCADA. The
advantages of Magnetic Level Gauge are greater control accuracy, improved reliability, lower
installation and start-up costs, less maintenance, eliminated fugitive emissions and risk of
explosion (See Fig 9) [33].
Figure 9 magnetic level gauge
Types of valve
Gate Valve – a linear motion valve used to start or stop fluid flow only. A partially open gate disk
tends to vibrate from the fluid flow. Most of the flow change occurs near shut-off with a relatively
high fluid velocity causing disk and seat wear and eventual leakage if used to regulate flow. For
these reasons, gate valves are not used to regulate or throttle flow (See Fig 10) [34].

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Figure 10 Gate valve
Globe Valve – a linear motion valve used to stop, start, and regulate fluid flow. The essential
principle of globe valve operation is the perpendicular movement of the disk away from the seat.
This causes the annular space between the disk and seat ring to gradually close as the valve is
closed. Good throttling ability, which permits its use in regulating flow (See Fig 11) [34].
Figure 11 Globe valve
Ball valve – is a rotational motion valve that uses a ball-shaped disk to stop or start fluid flow.
When the valve handle is turned to open the valve, the ball rotates to a point where the hole
through the ball is in line with the valve body inlet and outlet. When the valve is shut - the hole is
perpendicular to the flow openings of the valve body and the flow is stopped (See Fig 12) [34].

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Figure 12 Ball valve
Isolation Valve - Double Block and Bleed (DBB) Valve - the design incorporates two ball valves
and a bleed valve into one compact cartridge type unit with tapped flanged connections. The
primary function of a double block and bleed system is for isolation and the secondary function is
for intervention (See Fig 13) [35].
Figure 13 Double Block and Bleed (DBB) Valve
ValveActuators
Pneumatic valve actuator - adjust valve position by converting air pressure into linear or rotary
motion (See Fig 14). There are two main forms: the piston actuators and diaphragm actuators.
 Piston actuators are used when the stroke of a diaphragm actuator would be too short or
the thrust is too small. Compressed air is applied to a solid piston contained within a solid
cylinder. When the air pressure is removed, the shaft moves in the opposite direction due
to the reverse force spring. Piston actuators can also being double acting, meaning the air
can be fed into either side of the piston since there is not a return spring.
 Diaphragm actuators have a thin flexible membrane that actuates via a compressed air
supply. This type of actuator is single acting because the air is only supplied to one side of

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the diaphragm, and they can either be direct acting (spring-to-retract) or reverse acting
(spring-to-extend).
The advantages of pneumatic valve actuators are that they are strong, light, simple, and fast. The
disadvantage is that precise position control is not possible except at full stops [36].
Figure 14 pneumatic valve actuator
Current to pressure converter (I/P) - converts an analogue signal 4 to 20 mA to a proportional
linear pneumatic output 3 to 15 psig. Its purpose is to translate the analogue output from a control
system into a precise, repeatable pressure value to control pneumatic actuators/operators,
pneumatic valves, dampers, etc. (See Fig 15).
Figure 15 I/P Transducer
Krohne Magnetic Level Gauge – BM 26 - is a simple, rugged instrument designed to indicate
level or interface. It indicates level using a float magnetically coupled to an index or a column of
rotating flaps. It is ideal for aggressive media stored in tanks (See Fig 16) [37].

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Highlights
 Stainless steel design (optional NACE conformity)
 Ranges - Temperature: -200 to +300°C; Pressure: -1 to 120 bar; Density: 0.5 to 3 kg/l
 Stainless steel scale with wide choice of markings: m/cm, ft. /in, %, volume etc.
 Less risk of leakage than a sight glass - little or no maintenance needed
 Optional approvals for EEx i or EEx d applications
Figure 16“Krohne magnetic level gauge – BM 26 a Bypass Level Indicator”
Annubar Flow Meter - is a set of Pitot tubes mounted on a on a bar or rim across the pipe [11]
(See Fig 17). The principle of Pitot tube is that it measures differential pressure between and the
static pressure tap and the tap of full pressure of a stream. Thus, such differential is proportional to
fluid velocity squared. Pitot tube is designed in such a way that the full pressure chamber opening
is facing against the stream and the tip of the tube has conical aerodynamic profile. The static
pressure tap opening is made on the cylindrical surface of the tube. Having a set of tubes
(annubar) across the pipe allows good averaging of the velocity profile.
Figure 17 Annubar Flow Meter

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4. Wellhead & Separation
Gas from the wells (See Fig 18) is combined in the production manifold and flows into the inlet
separators. The separators [10] (See Fig 8) allow enough residence time to permit free water to
separate from the gas. Water flows out of the separators and on to the well water separator. Dry
gas continues on to the compression.
Figure 18 process flow schematic (P&ID A-012-04-5000A)
Table 3 Wellhead equipment and operating ranges and equipment list

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5. Gas Compression
As most compressors will not cover the full pressure range efficiently therefore, compression is
divided into several stages to improve maintenance and availability. The common shaft
centrifugal compressors [13] driven by a gas turbine are used to compress gas up to 42 bars [12].
For the compressor to operate efficiently, gas temperature should be low - the lower the
temperature, the less energy will be used to compress the gas for the given final pressure and
temperature. However, both gas from separators and compressed gas are relatively hot. To cool
down the compressed gas the heat exchangers are used to cool the gas. The separated gas may
contain mist and other liquid droplets that must be removed before it reaches the compressor. If
liquid droplets enter the compressor, they will erode the fast rotating blades. A scrubber is
designed to remove small fractions of liquid from the gas [12].
5.1 CompressionTrain1
Compression Train 1 - is used to boost platform Alpha gas export pressure (See Fig 19). The
export compression trains are installed on a structural cantilever at the east side of Alpha East
Platform. KC1000 is a three stage tandem common shaft centrifugal compression train [13] -
Low-Pressure Compressor (C-2000), Medium-Pressure Compressor (C-5000-1) and High-
Pressure Compressor (C-5000-2). Medium and High-Pressure Compressors consist of a two stage
back to back compressor. All compressor stages are driven by a single gas turbine which has its
own fuel gas skid. Each compressor has its own suction scrubber and fin-fan cooler on the
discharge side. The Scrubbers [10] (See Fig 8) remove any free water and the coolers decrease the
temperature of the gas after compression.

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Figure 19 Compression train 1 process flow schematic (P&ID A-012-04-5090A)
Table 4 Compression train 1 process operating ranges and equipment list
5.2 Compression Train 2 - It is a two stage tandem common shaft centrifugal compression train
[13] (Low & High-Pressure). Both compressor stages are driven by a single gas turbine which has
its own fuel gas skid. Each compressor has its own suction scrubber and fin-fan cooler on the
discharge side (See Fig 20).

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Figure 20 Compression train 2 process flow schematic (P&ID A-012-04-5006A)
Table 5 Compression train 2 operating ranges and equipment list
5.3 Compressor control
The main operating parameters for a compressor are the flow and pressure differentials [12][13].
The product defines the total loading, so there is a ceiling set by the maximum design power.
Furthermore, there is a maximum differential pressure (Max Pd) and choke flow (Max Q), the
maximum flow that can be achieved. At lower flow, there is a minimum pressure differential and
flow before the compressor will "surge" if there is not enough gas to operate. If variations in flow
are expected or differences between common shaft compressors occur, the situation will be
handled with recirculation. A high flow, high pressure differential surge control valve will open to

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let gas from the discharge side back into the suction side. The operating characteristics are defined
by the manufacturer. In the diagram [12] (See Fig 21), the blue lines mark constant speed lines,
the maximum operating limits are set by the orange line. The surge domain is the area to the left
of the red surge curve. The objective of compressor performance control is to keep the operating
point close to the optimal set point without violating the constraints by means of control outputs,
such as the speed setting. However, gas turbine speed control response is relatively slow, since
surge response must be in the 100 ms range. Anti-surge control will protect the compressor from
going into surge by operating the surge control valve.
Figure 21 Various points on the performance curve depending upon the flow rates and pressure difference
The basic strategy is to use distance between operating point and surge line to control the valve
with a slower response time, starting at the surge control line. Crossing the surge trip line will
cause a fast response opening of the surge valve to protect the compressor [12].
Compressor control strategies include:
 Set point adjustment - if rapid variations in load cause surge valve action, the set point
will be moved to increase the surge margin.
 Equal margin - the set point is adjusted to allow equal margin to surge between several
compressors.
 Model based control - outside the compressor itself, the main parameter for the surge
margin is the total volume from the surge valve to the compressor suction inlet, and the
response time for the surge valve flow. A model predictive controller could predict surge
conditions and react faster to real situations while preventing unnecessary recirculation.

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6. Gas Dehydration
The Alpha Platform Dehydration System removes any absorbed water present in the gas in
order to meet export pipeline gas specifications (See Fig 22). The gas coming from the discharge
of export compression flows into the inlet scrubber V-101 to remove free water from the gas. The
gas flows to the glycol absorber, X-100 and it is contacted with a counter flow of glycol. As the
glycol passes through the gas it absorbs the moisture. Dry gas leaves the top of the absorber and
flows through a gas/glycol heat exchanger X-100/2 which cools the in-flowing glycol. This glycol
is further cooled to as close to the gas temperature as possible by the glycol trim cooler, X-100/3.
The glycol trim cooler has 2 VSD fans which are controlled on the inlet glycol temperature to the
absorber. Wet glycol leaves the bottom of the absorber and the water is boiled off in the glycol
regeneration package before being re-circulated. The dehydrated gas continues to gas metering.
Figure 22 Dehydration process flow schematic (P&ID A-012-04-508A)
Table 6 Dehydration process operating ranges and equipment list

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6.1 Gas Dehydration Principles
Natural gas extracted from underground sources is saturated with liquid water. The presence of
water vapour in concentrations above a few tens of parts per million has potentially disastrous
consequences. The lifetime of a pipeline is governed by the rate at which corrosion occurs which
is directly linked to the available moisture in the gas which promotes oxidation. In addition, the
formation of hydrates can reduce pipeline flow capacities. Such hydrates (See Fig 23) are the
combination of excessive water vapour with liquid hydrocarbons, which may condense out of the
gas in the course of transmission, to form emulsions that, under process pressure conditions, are
solid masses [22].
Figure 23 the formation of hydrates in pipeline
The most common processing technique for drying natural gas is that of simple mechanical
separator, to divide the gas from the liquids of the two phase flow coming from the gas field,
followed by glycol dehydration. This process allows achieving a moisture content of less than 3
pounds of moisture per million standard cubic feet of gas under normal operating conditions.
Dehydration is usually done by absorption, although other processes like adsorption, membrane
processes and refrigeration may be used. About 95% of existing offshore installations currently
use TEG (Triethylene glycol) technology.
Advantages:
 TEG is more easily regenerated to a higher degree of purity
 Vapor losses are lower
 Operating costs are lower

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Figure 24 the glycol contractor/absorber
Lean glycol (typically 99.0 to 99.9% of weight) is fed to the top of an absorber (glycol contactor),
inside which it mixes with and dehydrates (by physical absorption) the wet natural gas stream
(See Fig 24). The contactor contains several bubble-cap trays providing suitable surface area
within the column (See Fig 25).
Figure 25 the contractor tray with bubble-caps

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Lean glycol is pumped into the upper portion of the contactor, above the top tray but below the
mist eliminator. The trays are flooded with glycol that flows down from tray to tray in down
sections. The gas rises through the bubble caps and is dispersed as bubbles through the glycol on
the trays. This provides the intimate contact between the gas and the glycol. Wet glycol leaving
the contactor at the base is called rich glycol. The dry natural gas leaves the top of the contactor
column via a mist eliminator (usually wire mesh type or axial cyclone).
Figure 26 the TEG (Triethylene glycol) unit
After leaving the contactor (See Fig 26), the rich glycol is routed to a regeneration system for
purification. It is preheated in a reflux condenser at the top of the still column of the reboiler and
the lean/rich heat exchanger. Then, the rich glycol enters a flash vessel for a three-phase
separation of gas, glycol and condensate. Since the glycol may contain impurities due to glycol
degradation, corrosion or scaling, filters are required before the rich glycol is distilled. This
distillation system consists of a still column, a reflux condenser and a reboiler. The glycol is
boiled to remove excess water and regain glycol purity around 99.0% wt. Stripping by dry gas is
often used after the reboiler in a separate stripping column to boost the TEG concentration up to
99.8% or more. The hot lean glycol is cooled using a heat exchanger with rich glycol entering the
regenerator. As the glycol pump boosts the pressure of the lean glycol to the contactor pressure
and at the high temperature glycol loses its ability to hold water the temperature, pressure and
glycol level inside the contractor is monitored constantly [22].

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7. Injection & Compression
The Injection/Boost Compression System (See Fig 27) is used to inject gas into the South West
Kinsale (SWK) well for storage during the summer months. The compressor barrel is changed out
for Boost Operation which increases the pressure of the stored gas for supply to BGE in winter. It
is a single stage compressor driven by a gas turbine which has its own fuel gas treatment unit. The
system has a suction scrubber to remove any free water and an after-cooler to cool the gas.
Figure 27 Injection & Compression process flow schematic (P&ID A-012-04-508A)
Table 7 Injection & Compression operating ranges and equipment list

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8. Metering & Pigging
The Gas Metering Skid (See Fig 28) accurately measures the gas flow rate prior to export from
platform Alpha. The measurement principle is based on the flow across an orifice plate.
Figure 28 Metering and pigging process flow schematic (P&ID A-012-04-509A)
Table 8 Metering operating ranges and equipment list
Pigging - sending a pig down a pipeline [14]. Pig (See Fig 29) is intelligent robotic device that is
propelled down pipelines to evaluate the interior of the pipe: test pipe thickness, roundness, check
for signs of corrosion and detect minute leaks and any other defect along the interior of the
pipeline that may either restrict the flow of gas or pose a potential safety risk for the operation of
the pipeline. The export facility must contain equipment to safely insert and retrieve pigs from the
pipeline as well as depressurization, referred to as pig launchers and pig receivers.
Figure 29 a pig in a pipeline

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9. Inch Onshore Metering Terminal
The Inch Onshore Terminals primary function is to provide fiscal metering and custody transfer of
the gas to BGE. The plant also knocks out and collects any liquid which is entrained in the gas
stream before metering. The facility consists of a pig receiver, slug catchers, three metering
streams, liquid separators and a flash drum to remove any dissolved gas from the liquid and liquid
storage tanks (See Fig 30).
Figure 30 Inch Metering process flow schematic (P&ID A-012-04-5200A)
Table 9 Inch Metering operating ranges and equipment list

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9.1 GAS FISCAL METERING
All calculated invoices, taxes and payments are based on the actual product shipped out. Also the
custody transfer takes place at this point, which means transfer of responsibility or title from the
producer to a customer. The Inch Onshore Terminal facility consist three metering streams (See
Fig 30 and 31); each stream with an orifice flow meter (Daniel Dual-Chamber Orifice Fitting –
Senior or Junior) [15] (See Fig 32 and 33), absolute and differential pressure transmitter and
temperature sensor with the transmitter. Gas chromatograph [17] (Daniel Danalyzer Gas
Chromatographs 700 (See Fig 37 and 38)) provide gas analysis necessary for fiscal calculations
made by the flow computer (Emerson FloBoss™ S600+ Flow Computer [16] (See Fig 34)).
Figure 31 Inch Onshore Terminal facility metering stream
9.2 Flow measurement using the Orifice Flow Meter
The basic operating principle of the Orifice Flow Meters [12] is based on the premise that the
pressure drop across the meter is proportional to the square of the flow rate. Used the orifice flow
meters are mass meters but requiring a density value as part of the flow rate calculation. Density
can be calculated from an on-line chromatograph analysis or a fixed value could be used
determined from periodic spot sampling. The uncertainty in measured density from on-line
chromatograph determined composition would typically be no greater than ±0.4% relative. This
includes pressure and temperature measurement uncertainty. The mass flow uncertainty of a fiscal
orifice meter in not greater than ±1.0%.

33
This is based on the flowing requirements:
 the use of an orifice flanges installed to the requirements of ISO 5167-2:2003
 the use of a correctly specified, installed and calibrated line pressure (PT) and temperature
(TT) transmitter (PT connected to the upstream differential pressure tapping),
 annual calibration of the differential pressure transmitter and line pressure transmitter,
 annual calibration of the temperature transmitter to a tolerance of ± 0.5 oC,
 inspection for orifice plate - 2 yearly, recalibration for orifice plate - 4 yearly,
 inspection and recalibration frequency for associated instruments - 4 yearly,
 life expectancy 15 years,
 measured or calculated density (from chromatograph analysis) to an uncertainty ±0.4%,
Daniel Dual-Chamber Orifice Fitting “senior” – (See Fig 32) the most widely used means of
measurement for natural gas. It provides a fast and simple method of changing orifice plates under
pressure without flow interruption. In addition, the dual-chamber design eliminates the bypass
piping, valves and other fittings required with conventional orifice flange installations [15].
Futures:
o quick and easy plate replacement
o field repairable
o special trim available
Figure 32 Daniel Dual-Chamber Orifice Fitting “Senior”

34
Daniel Single Chamber Orifice Fitting “Junior” - (See Fig 33) safe, simple and reliable
measurement at large meter stations. The single-chamber fitting is engineered to make orifice
plate changing quick and easy [15].
Features:
 Rack-and-pinion configuration ensures fast plate changing
 Versatility of line sizes from 10 to 42 inches
 Saves time without flange spreading
 All parts can be replaced on location without removing the fitting from the line
Figure 33 Daniel Single Chamber Orifice Fitting “Junior”
FloBoss™ S600+ Flow Computer – (See Fig 34) a panel-mounted flow computer designed
specifically for hydrocarbon liquid and gas measurement. The standard features of the S600+
make it ideal for fiscal measurement, custody transfer, batch loading, and meter proving
applications. The FloBoss S600+ offer advanced measurement technology, fast digital signal
processing, versatile data communication and high capacity storage. It calculates data, saves and
prints in form of the reports all data from metering system (See Fig 35 and 36) [16].
Figure 34 Emerson FloBoss™ S600+ Flow Computer

35
Figure 35 flow computer current report
Figure 36 flow computer daily report
Note: Natural gas is bought and sold based on the level of its energy content.

36
9.3 Natural Gas Analysis - Gas Chromatography
Gas chromatography - analytical separation techniques used to analyse volatile substances in the
gas phase [17]. In gas chromatography, the components of a sample are dissolved in a solvent and
vaporized in order to separate the analytes by distributing the sample between two phases: a
stationary phase and a mobile phase. The mobile phase is a chemically inert gas that serves to
carry the molecules of the analyte through the heated column. A naturally occurring mixture of
gaseous hydrocarbons, natural gas consisting primarily of methane but can include other
hydrocarbons (C1-C4 chain length hydrocarbons) and small amounts of other impurities (O2, N2,
CO2, H2, He and sulphur containing hydrocarbons). Gas Chromatograph evaluates chemical
composition of natural gas and the by-products resulting from natural gas processing.
Daniel Danalyzer Model 700 Gas Chromatograph
Features:
 one package for fiscal metering or gas quality at ambient temp -30° C to 60°C
 custody transfer analysis C6+ to C9+ and contaminant monitoring H2S, CO2, O2, etc.;
 highest stated precision ±0.25 BTU/1000 for broad ambient temp
 wide dynamic range from % to trace level components
Figure 37 Daniel Danalyzer 700

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Gas chromatograph principles of work
Figure 38 Daniel Danalyzer - Model 700 Gas Chromatograph - Functional Block Diagram.
A sample of the gas to be analysed (taken from the process stream by a sample probe installed in
the process line) passes through a sample line to the sample conditioning system where it is
filtered or otherwise conditioned [18]. After conditioning, the sample flows to the analyser for
separation and detection of the components of the gas. A precise volume of sample gas is injected
into one of the analytical columns that contain a stationary phase (packing) that is either an active
solid (adsorption partitioning) or an inert solid - support that is coated with a liquid phase
(absorption partitioning). The gas sample is moved through the column by means of a mobile
phase (carrier gas Helium). Selective retardation of the components of the sample takes place in
the column that causes each component to move through the column at a different rate. This
action separates the sample into its constituent gases and vapours. A detector located at the outlet
of the analytical column senses the elution of components from the column and produces
electrical outputs proportional to the concentration of each component. Outputs from the analyser
detectors are amplified in the analyser electronics and then transmitted to the Controller for
further processing (See Fig 38). Output from the Controller is normally displayed on a remotely
located personal computer (PC) or a printer. Connection between the Controller and the PC can be
accomplished via a direct serial line, the Modbus-compatible communication interface, modem or
Ethernet card [18].

38
The Danalyzer detector subsystem is a thermal conductivity detector that consists of a balanced
bridge network with heat-sensitive thermistors in each leg of the bridge. Each thermistor is
enclosed in a separate chamber of the detector block. One thermistor is designated the reference
element and the other the measurement element. Prior to injecting a sample both legs of the bridge
are exposed to pure carrier gas. In this condition, the bridge is balanced and the bridge output is
electrically nulled. When the sample is moved through the column by the continuous flow of
carrier gas successive components elute from the column - the temperature of the measurement
element changes and that unbalances the bridge and produces an electrical output proportional to
the component concentration. The differential signal developed between the two thermistors is
amplified by the preamplifier (See Fig 39 and 40) [18].
Figure 39 chromatograph electrical output proportional to the component concentration
a) detector Bridge balanced
b) first component begins to elute from column and sensed by the measurement thermistor
c) peak concentration of first component
d) second component begins to elute from column and sensed by the measurement thermistor
e) peak concentration of second component
Figure 40 natural gas sample analyzing

39
9.4 Natural Gas Analysis - Gas Moisture Analysis
Figure 41 Dew Points of Aqueous Triethylene Glycol Solutions at Various Contact Temperatures
The efficiency of the dehydration is measured on the water contents in the dry gas. The dew-point
temperature (DPT) for the water in the gas is often a more useful parameter than the total water
contents. DPT must be below the minimum pipeline temperature to avoid liquid in the gas
pipeline (See Fig 41) (6 to 11 °C below the desired dew-point is used to insure against non-ideal
situations) [19].
Figure 42 water and hydrocarbon dew point envelope
Temperature, o
C
Pressure,Bara
H2O Dewpoint
HC Dewpoint
-40 -30 -20 -10 0 +10
0
10
20
30
40
50
60
70
80

40
For natural gas there are two dew-point temperatures of relevance, the water dew point and the
hydrocarbon dew-point [19] (See Fig 42). Manual visual cooled mirror dew-point meter, and any
other type of automated, condensing dew-point analyser, may give confusing results when used
for water dew-point measurement in natural gas. This is because of the difficulty in observing the
water dew point separately from that of hydrocarbons and glycol that are highly likely to condense
on the mirror surface at a higher temperature than the water dew point. The use of a sensor based
on a non-condensing measurement principle avoids this difficulty as it does not employ a
condensation measurement technique [19].
Moisture Analyser with Aluminum Oxide sensor [20] (See Fig 30).
Figure 43 Moisture Analyser with Aluminum Oxide sensor
Aluminum Oxide probe principle [20] (See Fig 43) is adsorption desorption of water molecules
into a hygroscopic layer between two conductive electrical plates. A substrate layer beneath and a
porous top plate exposed to the flowing sample and through which moisture molecules freely
permeate to maintain a natural equilibrium of moisture content. The variation of moisture
adsorbed into the hygroscopic layer results in a corresponding change in the dielectric between the
conductive plates and thus the ability to use this principle for continuous on-line measurement.

41
Figure 44 Aluminum Oxide probe
Advantages of use the Aluminum Oxide probe for a gas moisture measurement:
The pressure of natural gas is typically 4 to 8 MPa in processing plant and on-shore transmission
whilst gas entering offshore pipelines is often compressed to 16 MPa or higher. In any dew-point
analysis the influence of gas pressure must be considered. The aluminum oxide probe adsorbs
moisture in equilibrium with the gas sample flow to which it is exposed and thus exhibits a
response to variations in water vapour pressure. Water vapour pressure is directly related to dew
point, which enables such sensors to be calibrated accurately and easily in the parameter of dew
point. The relationship between partial pressure of water vapour and dew point remains consistent
irrespective of total gas pressure and the composition of the dry gas components. Thus such a
sensor calibrated by the instrument manufacturers on known dew point calibration gases, usually
performed at atmospheric pressure, can be applied to accurately determine the dew point of any
process gas at any chosen analysis pressure [20].
The aluminum oxide probe can be installed on remote sampling (See Fig 45) or directly ‘in-line’
into the process pipeline. The advantages of this installation arrangement are that the gas remains
in the pipeline and the speed of response is extremely fast but a major disadvantage is the
difficulty involved in removing the sensor probe assembly from the pipeline that is required for
periodic maintenance of the sensor calibration. A further disadvantage is the lack of protection to
glycol contamination that is afforded by such direct insertion also application of a moisture
analyser for sour gas measurement requires a sample conditioning system [20].

42
Figure 45 moisture analyser and aluminum oxide probe installed on remote sampling system
Moisture Analyser
The microprocessor-based moisture analyser [20] accurately tracks fast-changing process
conditions and displays the moisture content as dew/frost temperature or as parts per million by
volume. Two alarm relays provide indication of when high and low limits are exceeded. Moisture
analyser features a real time clock and data logging to allow performance monitoring and
enhanced trouble-shooting. The electronics are self-calibrating, ensuring long-term stability.
Sensor calibration data is stored in a non-volatile memory so data entry is automatic. Installation
is simple, with connection to the analyser by means of an inexpensive, unshielded twisted pair
cable, which can be up to 0.9 km in length. Both the moisture content in natural gas and
temperature or pressure readings can be easily introduced to the SCADA system which allows
controlling the process from the control room [20].

43
CHAPTER III
1 Safety Systems
1.1 Fire & Gas Detection System
Fire and gas (F&G) detection and mitigation system is the key to maintaining the overall safety
and operation of the offshore platform. Offshore platform operators are faced with potential
hazards ranging from toxic gas release to gas explosion, high temperatures, high pressures, etc.
The fire and gas system is divided into fire areas by geographical location. Each fire area is
designed to be self-contained, in that it detecting fire and gas by several types of sensors, and
control fire protection and fire-fighting devices to contain and fight fire within the fire area [23].
Fire detection:
 Gas detection: combustible, electro-catalytic or infra-red (IR) detectors
 Flame detection: ultraviolet (UV) or infra-red (IR) optical detectors
 Fire detection: Heat and ionic smoke detectors
 Manual pushbuttons
Fire-fighting, protection:
 Gas-based fire-fighting (such as CO2)
 Foam-based fire-fighting
 Water-based fire-fighting: sprinklers, mist (water spray) and deluge
 Protection: interface to emergency shutdown and HVAC fire dampers.
 Warning and escape: PA systems, beacons/lights, fire door and damper release
For fire detection, coincidence and logic are used to identify false alarms. In such schemes,
several detectors in the same area are required to detect a fire condition or gas leakage for
automatic reaction. This will include different detection principles, e.g., a fire, but not welding or
lightning strike. Action is controlled by a fire and gas system (F&G) which action is specified in a
cause and action chart called the Fire Area Protection Datasheet (See Fig 37). This chart shows all
detectors and fire protection systems in a fire area and how the system will operate [23].

44
Figure 46 F&G Cause and Effect Chart

45
The F&G system (See Fig 38) provides supervisory functions, either in the F&G or the
information management system (IMS) to handle such tasks as maintenance, calibration or
replacement and hot work permits (one or more fire and gas detectors or systems are overridden
or bypassed). Logic solver is the central control unit of the overall F&G detection and control
system. The controller receives alarm and status from field monitoring devices required for fire
and gas detection and handles the required actions to initiate alarms and mitigate the hazard [23].
Figure 47 F&G detection and control system
F&G detection systems are generally Programmable Electronic Systems type (See Fig 39) with
high safety availability and mitigation effectiveness. F&G system is tightly integrated with the
overall process safety strategy, mitigation either takes place via the emergency shutdown (ESD)
system or directly from the F&G system itself [23].
Figure 48 programmable electronic systems (PES)

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1.2 Gas Detection Principles
Detection based on absorption of infrared (IR) radiation at certain wavelengths as it passes
through a volume of gas. Devices using this technology have a light source and a light detector
and measure the light intensity at two specific wavelengths, one at an absorption (active)
wavelength and one outside of the absorption (reference) wavelength. If a volume of gas passes
between the source and detector, the amount of light in the active wavelength falling on the
detector is reduced, while the amount of light in the reference wavelength remains unchanged.
Any failure of the source or detector, or blockage of the signal by dirt, is detected immediately as
a malfunction. For this reason, IR detectors are also considered to be fail-to-safe. IR gas detectors
can be used for “point” (single location) or “open path” (line of sight) applications.
Advantages:
 Immune to all chemical poisons and does not need oxygen or air to detect gas
 Can work in continuous exposure gas environments
 Fail-to-safe technology
 Internal compensation virtually eliminates span drift
Sieger Searchline Excel Infra-red Open Path Gas Detector System - for hydrocarbon gases is
designed to monitor a hydrocarbon gas release or cloud as it passes through an invisible infra-red
detection beam (operates over distances of 5 to 200 meters). Open Path Gas Detection is a highly
effective means of monitoring flammable gas with significant advantages over point gas detectors
which rely on gas reaching a detector at one given point or location. A high intensity light source
pulsed at a special coded frequency generates a much stronger infra-red beam enabling it to
penetrate further through fog and rain. Output: 4-20 mA; Modbus RS485 multi drop [24].
Figure 49 Sieger Searchline Excel Infra-red Open Path Gas Detector System

47
Searchpoint Optima Plus Point Infrared Gas Detector - is an infrared point hydrocarbon gas
detector certified for use in potentially explosive atmospheres (See Fig 41). The unit’s infrared
detection principle offers the fastest speed of response and fail-to-safe operation. Reduced routine
maintenance, when compared with conventional electro-catalytic based gas detectors, provides
low on-going cost of ownership. Output: 4-20mA; Multidrop Modbus RS485; HART® over 4-
20mA output [25].
Figure 50 Searchpoint Optima Plus Point - Infrared Gas Detector
Combustible Gas Sensor Pellistor employs catalytic combustion to measure combustible gases
or vapours in air up to the Lower Explosive Limit (LEL) of the gas (See Fig 42). Sensor consists
of a matched pair of elements: detector and compensator (reference element). The detector
comprises a platinum wire coil embedded within a bead of catalytic material. The compensator is
similar except that the bead does not contain catalytic material and as a consequence is inert. Both
elements are normally operated in a Wheatstone bridge circuit that will produce an output only if
the resistance of the detector differs from that of the compensator. The bridge is supplied with a
constant dc voltage that heats the elements to 500-550°C. Combustible gases are oxidised only on
the detector element, where the heat generated increases its resistance, producing a signal
proportional to the concentration of combustible gas. The compensator helps to compensate for
changes in ambient temperature, pressure, and humidity, which affect both elements equally [26].
Note: The LEL of a gas is the minimum concentration of that gas in air at which an ignition
source will cause an explosion.

48
Figure 51 Pellistor
Catalytic Poisons - some compounds (organic lead and silicon compounds) will decompose on
the catalyst and form a solid barrier over the catalyst surface. This action is cumulative and
prolonged exposure will result in an irreversible decrease in sensitivity.
Inhibition - certain other compounds, especially H2S and halogenated hydrocarbons, are absorbed
or form compounds that are absorbed by the catalyst and normal reactions are inhibited. The
resultant loss of sensitivity is temporary and in most cases a sensor will recover after a period of
operation in clean air [26].
Ultrasonic Gas Leak Detector - instead of measuring a concentration level in LEL as traditional
gas detectors (point and open path detectors) the ultrasonic gas leak detectors listening for
ultrasound emitted from pressurised gas leaks. When gas moves from a high-pressure area to a
low-pressure area through a hole, it expands very rapidly and produces a turbulent flow, resulting
in an audible "hissing" sound - broadband acoustic sound, which ranges from the audible
frequency range (20 Hz to 20 kHz) into the ultrasonic frequency range (16 kHz to 10 MHz). The
ultrasonic gas leak detectors (See Fig 43) do not have to wait until the gas concentration has
accumulated to a potentially dangerous gas cloud, they react instantaneously. This makes
detection more reliable and efficient as it is possible to verify the performance of the detection
system.

49
Figure 52 the Gassonic Surveyor Ultrasonic Gas Leak Detector
Heat detector - use one or a combination of detection principles, including fixed temperature,
rate-of-rise and rate compensated.
Fixed temperature detector is designed to respond when the operating element reaches a
predetermined temperature.
Rate-of-rise detectors respond when the rise in temperature exceeds a predetermined value [28].
Rate Compensation Heat detector improves performance by offsetting thermal lag. A slow rate
of temperature rise allows the heat to penetrate the inner expansion struts. The tubular shell and
the struts expand slowly until the total device has been heated to its rated temperature level. At
this point, the silver contact points close and an alarm is initiated. When subjected to a rapid rate
temperature rise, there is not as much time for heat to penetrate the inner strut. However, the rapid
lengthening of the shell allows the struts to come together at a lower level. When the surrounding
air temperature returns to below the rated level, the shell contracts and forcing the contacts to
open (automatically resetting the sensor) [28].
1.3 Flame Detection Principles
Most flame detectors identify flames by optical methods like ultraviolet (UV) and infrared (IR)
spectroscopy and visual flame imaging. Flame detectors are designed to detect the absorption of
light at specific wavelengths, allowing them to discriminate between flames and false alarm
sources. There are four primary optical flame-sensing technologies in use: ultraviolet (UV),
ultraviolet/infrared (UV/IR); multi-spectrum infrared (MSIR) and visual flame imaging. They are

50
all based on line-of-sight detection of radiation emitted in the UV, visible and IR spectral bands
by flames. Technologies may be selected to suit the requirements of flame monitoring
applications, including detection range, Field of View (FOV) (See Fig 44), response time, and
particular immunity against certain false alarm sources [29].
Figure 53 polar diagram shows the directional sensitivity of the detector using a 0.1m2 n-heptane fire
Multi-Spectrum Infrared Flame Detectors - use multiple infrared spectral regions to further
improve differentiation of flame sources from non-flame background radiation. These flame
detectors are well suited to locations where combustion sources produce smoky fires. They
operate at moderate speed with a range of up to 60 m from the flame source — both indoors and
outdoors. These instruments exhibit relatively high immunity to infrared radiation produced by arc
welding, lightning, sunlight, and other hot objects that might be encountered in industrial
backgrounds [29].
S200 Triple IR Solar Blind Flame Detector Thorn S261f+ – is solar blind and multi-channel
flame detector with low power consumption and high false alarm immunity. Available in both
Intrinsically Safe and Flameproof versions that provides a relay interface for alarm and fault
condition (See Fig 45) [30].

51
Figure 54 S200 Triple IR Solar Blind Flame Detector Thorn S261f+
S200+ Features:
 Triple waveband infrared solar blind flame detection for optimum false alarm immunity
 Unrivalled black body rejection over a wide range of source temperatures
 Range adjustable to 50 metres for a 0.1m2 petrol pan fire
 Discrimination of optical faults (dirty windows) from other faults
 Housing designed for easy installation of cabling; flexible mounting and angular adjustment
 ATEX and IECEx certified and approved to EN54 Pt10
 Compatible with 4-20mA or MODBUS output
Ultraviolet Flame Detection System Detector/Controller U7602 - is a completely unitized
ultraviolet (UV) flame detection device (See Fig 46) that incorporates all detection, electronic, and
switching components in a single, explosion-proof enclosure. It is designed for use in hazardous
locations and is particularly suitable for use in outdoor applications because it is not affected by
wind or rain, and is insensitive to solar radiation. A current output is provided to indicate the
status of the U7602. The U7602 is equipped with the Automatic Optical Integrity (oi) feature,
which provides a continuous check of detector optical surfaces and detector/controller circuitry.
Failure of the oi test results in the normally energized Fault Relay being de-energized.

52
Figure 55 the U7602 Detector/Controller
1.4 SMOKE DETECTION
Optical - beam Smoke Detector - work on the principle of light obscuration, where the presence
of smoke blocks some of the light from the beam, typically through either absorbance or light
scattering. Once a certain percentage of the transmitted light has been blocked by the smoke, a fire
is signaled (See Fig 47) [31].
Features:
 intelligent fire detector with decentralized intelligence
 automatic function self-test and emergency mode,
 alarm display and storage of alarm and operating data,
 Max. Output current (Io): 10 mA; alarm current @ 9 V DC: typ. 18 mA
Figure 56 Optical - beam Smoke Detector

53
1.5 Emergency shutdown and process shutdown
The emergency shutdown (ESD) and process shutdown (PSD) systems will take action when the
process goes into a malfunction or dangerous state. For this purpose, the system maintains four
sets of limits for a process value, Low-Low (LL), Low (L), High (H) and High-High (HH). L and
H are process warning limits which alert to process disturbances. LL and HH are alarm conditions
and detect that the process is operating out of range and there is a chance of undesirable events
and malfunction [32].
Figure 57 Separator with limit switches
Separate transmitters are provided for safety systems. One example is the LTLL (level transmitter
Low-Low) or LSLL (level switch Low-Low) alarm for the oil level (See Fig 48). When this
condition is triggered, there is a risk of blow-by, which means gas leaks out of the oil output and
causes high pressure in the next separation stage or other following process equipment.
Emergency shutdown actions are defined in a cause-and-effect chart based on a HAZOP of
the process (See Fig 49). This study identifies possible malfunctions and how they should be
handled. On the left of the chart, we have possible emergency scenarios. On top, we find possible
shutdown actions. The primary response is to isolate and depressurize. In this case, the typical
action would be to close the inlet and outlet sectioning valves (EV 0153 20, EV 0108 20 and EV
0102 20 in the diagram), and open the blow-down valve (EV 0114 20). This will isolate the
malfunctioning unit and reduce pressure by flaring of the gas [32].

54
Figure 58 Emergency Shutdown Cause and Effect Chart

55
2. Platform Utilities
A number of platform utilities are provided to support platform operations. These utilities are
described in the following sections.
2.1 Power generation
The power generation provides electrical power for the production operations and all of the
platform utility systems. The principal power supply is three gas turbine generators each capable
of generating 800 kW of electrical power ([39] Caterpillar Solar Turbines). The generators operate
with dry fuel gas generated by the platform fuel gas system. In case of failure of the gas
generators the diesel generator (capable of generating 525 kW of electrical power) will provide
the electrical power to the platform essential services. The Uninterruptible Power Supply (Gutor -
UPS System [38]) provides power during the time needed to start the diesel generator (5
seconds). In case of failure of the gas and diesel generators the battery system will supply the
process instrumentation, communication and fire and gas detection systems (See Fig 50).
Figure 59 Platform Alpha Power Distribution System

56
2.2 Diesel System
In addition to providing fuel for the back-up power generation system, the diesel system provides
fuel to crane, emergency fire-pump and lifeboats. Diesel is transferred to the platform by hose
from supply boats. From storage tank, the diesel is pumped to the users via the diesel treatment
package (the coalescing filter system and centrifuge to remove all impurities from the diesel).
2.3 Instrument Air
A large volume of compressed air is required for control of pneumatic valves and actuators, tools
and purging of cabinets. It is produced by two electrically-driven screw compressors (CompAir
DELCOS 3000) [41] and further treated to be free of particles, oil and water (Domnick Hunter Air
Dryer DX106P) [42].
2.4 Nitrogen Generation and Backup
Inert Gas (Nitrogen) is generated on demand by a membrane package using dry compressed air
(Flowserve N2 Genpac) [40]. A backup inert gas supply system is also provided. Inert gas users
include gas turbines seals, compressor seals, cooling medium expansion drum and utility stations,
storage tanks blanketing and pressure transfer of products between storage vessels.
2.5 Seawater Lifting and Filtration
Seawater is drawn directly from the platform seawater lift pump two caissons using two seawater
lift pumps. Following lifting and filtration to remove particles greater than 150 microns, a
proportion of the seawater is dosed with an anti-fouling additive in order to prevent the build-up
of organic matter. Once treated, the seawater is passed to the various users e.g. Heating -
Ventilation and Air-Conditioning (HVAC), fresh water generator, firewater ring.
2.6 Fresh Water
The fresh water system utilise a reverse osmosis process to desalinate seawater [43]. It includes
the sand filter, carbon filter and six membranes stack to clean the seawater (Salt Separation
Services). The water purity is tested by the conductivity measurement (typically 400 µs/ cm).
System has a capacity to produce 1200 l/ hour of fresh water. Saline effluent from the fresh water
maker is directed overboard. The fresh water is stored in a fresh water tank.
Note: Reverse Osmosis is a process of demineralization or deionization water by pushing it under
pressure through a semi-permeable Reverse Osmosis Membrane. The desalinated water that is
demineralized or deionized, is called permeate (or product) water. The drain stream that carries
the concentrated contaminants that did not pass through the RO membrane is called the reject (or
concentrate) stream.

57
2.7 Fire Water
Firewater is supplied by two pumps (one electric driven main pump and one backup diesel driven)
and electric driven jockey pump located on the cellar deck and provides a dedicated firewater
supply for the platform from the seawater lift system. The distribution system supplies firewater to
general area deluge systems, hose reels/ hydrants and monitors. Deluge protection is provided to
the majority of gas processing areas. The film forming foam concentrate system is also provided
to enhance the effectiveness of deluge water spray protection.
2.8 Fuel Gas
Fuel gas is diverted from the High Pressure gas process train downstream of the main export
compression and passed on to the fuel gas system where liquid condensate is removed in the fuel
gas knock out drum and returned to the Low Pressure separator train for processing. Gas is then
heated and filtered in order to meet the gas turbine generator quality specifications.
2.9 Drainage System
The drainage systems on the platform consist of non-hazardous open drains as well as a closed
drain system. Open drains waters is routed to the open drains caisson and passed through a
skimmer in the caisson to draw of any oil prior to discharge. Closed drain waters is directed to the
low pressure and high pressure closed drain degassing drum and back to the low pressure
separator for re-treatment.

58
CHAPTER V
Work Placement Projects
1. SKID 5 Modernization Project
1.1 Project Introduction
The glycol level control during the glycol regeneration process is crucial. The level gauges (sight
glasses) and an isolation valve suffered considerable degradation over the years and was necessary
to upgrade the system. Also for a better control the process - performed modifications allows
introducing of the glycol level data to SCADA system.
1.2 Project Assumptions
 glycol level measurement system upgrade
 glycol regeneration system valves upgrade
 glycol level data introduction to SCADA
1.3 Project Summary
My role during the project was to control the quality and compliance supplied parts, supervise the
timeliness of deliveries and to prepare the scope of work documentation.
Before I attempted to my tasks I had to familiarise with the Alpha platform gas dehydration
system, system components (See Chapter II 6) and involved theory (See Chapter II 6.1). I had to
familiarize with used in the installation types and principles of work of the valves, level gauges
(See Fig 60) and transducers (See Chapter II 3). I discovered my knowledge gained during the
CIT course was very accurate and helpful.
During the project the Glycol Degassing, Re-boiler, Sump and Storage - vessels level gauges (See
Fig 60) will be replaced with the magnetic level gauges (See Chapter II 3) [33]; level transmitter
will be replaced with the new; new P/I and I/P Transducer installed; corroded valves, also the
isolation valves and piping elements will be replaced with the new (See Fig 61).

59
Figure 60 Glycol Reboiler vessel old sight glasses
Figure 61 Glycol Regeneration system bean valves

60
2. Fire and Gas Detection System Tagging and Drawings Update Project
The aim of this project was to update the Fire and Gas Equipment Layout drawings and Fire and
Gas System SCADA mimics, and to check the detectors current condition and proper tagging.
The platform Alpha, platform Bravo and Inch Metering and Pigging installations equipment
layout changes in time frequently so it necessary to periodically update the equipment layout
drawings and SCADA mimics. In addition, adverse weather conditions often cause degradation of
the detectors tagging as well as detectors.
Project outcomes ensure that:
 the detectors are in a good visual condition and properly tagged
 the drawings and SCADA mimics reflecting the present and real detectors layout
2.3 Project Summary
My first task was to study the important role of the fire and gas detection system. I had to
familiarize with types of the detection; gas, smoke, flame and heat detectors principles of work;
particular detectors models used in installations (See Chapter III 1.1 ).
Next I had to visit each plant (Alpha offshore platform and Inch Metering and Pigging plant) to:
 locate the detectors on site
 check the visual condition of the detector and detector wiring
 check the correctness of the detectors tagging and location
 identify and record the detector type and model
 locate newly installed detectors
 prepare the detectors list (See Fig 62)
 apply the changes to Fire and Gas Equipment Layout drawings (See Fig 63)
 report the necessity of changes to Fire and Gas System SCADA mimics
As a result of the actions taken the actual "Fire and Gas Equipment Layout" drawings are more

61
specific and consists more details regarding the detector type, principle of works and model. The
present, physical Fire and Gas System detectors layout is reflected both on the Fire and Gas
Equipment Layout drawings and Fire and Gas System SCADA mimics.
Figure 62 Platform Alpha gas detectors list fragment (example)
Figure 63 Platform Alpha - Gas Compression Fire & Gas Equipment Layout (G – gas; H – heat; F – flame; MA – manual switch)

62
3. Flame Detectors Field of View Adjustment Project
The aim of this project was to investigate the flame detectors field of vision (See Chapter III 1.3 )
and if necessary adjustment of the above to gain the maximum effectiveness of the detection (See
Fig 54).
The installations equipment layout changes and that cause the changes in safety system layout and
arrangement. The flame detectors cone of vision must be adjusted periodically to cover the critical
areas. Project outcomes ensure that the flame detectors cone of vision is not disturbed by any
obstruction and detectors covers desired areas.
3.3 Project Summary
To begin the project as first I had to familiarize with flame detectors principles of work, particular
flame detectors models used in installations (See Chapter III 1.3 ) and these detectors datasheets.
Next I had to visit Alpha platform to:
 locate the detectors on site
 identify the detector model (See Fig 55 and 56)
 by identifying the direction and angle determine the field of vision of the detector
 prepare the flame detection coverage drawings for the all areas (See Fig 64)
 prepare the adjustment suggestions report for Offshore Installation Manager
 after acceptance by OIM I supervised the adjustment of the flame detectors (See Fig
65,66 and 67)
 report all changes in the flame detection system to Instrumentation Department
 prepare the report for Instrumentation Department that provide data to introduce the
flame detectors cone of vision to the Fire and Gas Layout drawings

63
Example with Sample Data
Example of the flame detection coverage drawing:
On the Process Hall F&G Equipment Layout drawing (See Fig 64) the cone of vision is marked
for each sensor. Figure showing the coverage of the flame detection with noticeable high
concentration on the high risk area (methanol tank TK-100).
NOTE: Typical Response of the S200 PLUS flame detector - sensitivity to flame with the ability
to detect a fully developed 0.1m2 n-heptane pan fire at up to 50m. Three normal standard ranges.
Maximum range is 50 m, default range is 25 m and there is a short range of 12.5 m.
Figure 64 Platform Alpha – Process Hall Flame Detection
Example of the flame detectors adjustment performed during the project.
The wellhead area is a high risk area so the proper fire detection is crucial for the safety. Before
the adjustment one of flame detectors pointed along the blast wall and second along the platform
edge. That was causing a large area was out of sight of the flame detectors (See Fig 65). After the
adjustment (approved by OIM) the flame detectors (See Fig 66) - pointing straight to Wellhead

64
area and now the detectors cone of vision covers the whole area (See Fig 67).
Figure 65 Platform Alpha Main Deck Wellhead area flame detection area before adjustment
Figure 66 Platform Alpha Main Deck Wellhead area flame detectors view direction adjusted
Figure 67 Platform Alpha Main Deck Wellhead area flame detection area after adjustment

65
REFERENCES
[1] Kinsale Energy Limited General Information
http://www.kinsaleenergy.ie/
[2] Kinsale Energy Limited Activities Information
http://www.kinsale-energy.ie/about-us.html
[3] Kinsale Energy Limited History
http://www.kinsale-energy.ie/history.html
[4] Natural Gas Information
http://www.kinsale-energy.ie/useful-information.html
[5] Study on Common Approach to Natural Gas Storage and Liquefied Natural Gas on an All
Island Basis Executive Summary (November 2007)
http://www.dcenr.gov.ie/nr/rdonlyres/8ad0eddb-3237-4157-b230-
2d467a3c1f9c/0/4dcenrgasstorageexecutivesummary.pdf
[6] Kinsale Energy Limited Gas Production Process information
http://www.kinsale-energy.ie/gas-production.html
[7] Kinsale Energy Limited Gas Storage Process information
http://www.kinsale-energy.ie/gas-storage.html
[8] Subsea valves specification
http://www.piping-world.com/xmastree_01.html
[9] Subsea control, umbilicals
http://www.2b1stconsulting.com/umbilical/
[10] Offshoreteknikk - Gas/water separation principles
http://offshoreteknikk.com/2013/10/14/separasjon-av-olje-gass-og-vann/

66
[11] Emerson - Annubar Flow Meter specification
http://www2.emersonprocess.com/en-us/brands/rosemount/flow/dp-flow-products/compact-annubar-
flowmeters/pages/index.aspx)
[12] OIL AND GAS PRODUCTION HANDBOOK Håvard Devold © 2006 ABB ATPA Oil and
Gas Edition 1.3 Oslo, June 2006
http:www.itk.ntnu.noansatteOnshus_TorOil and gas production handbook ed1x3a5 comp.pdf
[13] Wikipedia – centrifugal compressor specification.
http://en.wikipedia.org/wiki/Centrifugal_compressor
[14] Wikipedia – pipeline pigging principle
http://en.wikipedia.org/wiki/Hydraulically_activated_pipeline_pigging
[15] Emerson - Orifice Flow Meters
http://www2.emersonprocess.com/en-US/brands/daniel/Flow/differential-pressure-flowmeter/Pages/Differential-
Pressure.aspx
[16] Emerson FloBoss s600 flow computer specification
http://www2.emersonprocess.com/en-us/brands/remote/liquids_flow_computers/s600/pages/s600.aspx
[17] Chemwiki - Gas Chromatography principles
http://chemwiki.ucdavis.edu/Analytical_Chemistry/Instrumental_Analysis/Chromatography/Gas_Chromatography
[18] Emerson - Danalyser 700XA Gas Chromatograph Hardware Reference Manual
http://www2.emersonprocess.com/siteadmincenter/PM%20Danalyzer%20Documents/DANGC_Manual_3-9000-
537_M500.pdf
[19] Moisture measurement principles
http://www.michell.com/uk/support/advances-optical-whitepaper.htm
[20] General Electric - Moisture Probe and Analyser – Datasheet
http://www.ge-mcs.com/microsites/dewiq/ExploreDewIQ
[21] Basic Offshore Safety Induction & Emergency Training details

67
http://www.nmci.ie/index.cfm/page/course/courseId/25
[22] Natural Gas Dehydration
http://petrowiki.org/Dehydration_with_glycol
[23] Fire and Gas Detection Systems information
https://www.honeywellprocess.com/library/marketing/whitepapers/FireGasSystem_Whitepaper_April09.1.pdf
[24] Sieger Searchline Excel Infra-red Open Path Gas Detector System
http://www.hydrocarbononline.com/doc/performance-and-reliability-in-open-path-gas-0001
[25] Searchpoint Optima Plus Point Infrared Gas Detector
http://www.honeywellanalytics.com/en/products/Searchpoint-Optima-Plus
[26] Pellistor principles
https://www.citytech.com/loader/frame_loader.asp?page=https://www.citytech.com/technology/pellistors.asp
[27] Ultrasonic Gas Leak Detection principles
http://www.gassonic.com/products/
[28] Heat Detection principles
http://saba.kntu.ac.ir/eecd/ecourses/instrumentation/projects/reports/smoke%20detector/new_page_4.htm
[29] Flame Detection principles
http://www.gmigasandflame.com/downloads/white-papers/Flame-Detection-Technologies.pdf
[30] S200 Triple IR Solar Blind Flame Detector Thorn S261f+
http://www.thornsecurity.net/Products/Fire/TSLdetectors/TSLflameTripleIR.asp
[31] Smoke Detection
https://www.esser-systems.com/en/produkte/details/automatic-detectors/intrinsically-safe/803371ex-optical-smoke-
detector-iq8quad-ex-i-wo-isolator.html
[32] Emergency shutdown and process shutdown
http://oilandgasproductionhandbook.blogspot.co.uk/2014/02/8-utility-systems-this-chapter-

68
contains.html#Fire_and_gas_system
[33] Magnetic Level Gauge principles
http://www2.emersonprocess.com/siteadmincenter/pm%20magtech%20documents/00803-0100-6156.pdf
[34] Valve types and work principles
http://encyclopedia2.thefreedictionary.com/full-way+valve
[35] DBB valve work principles
http://www.vovalve.com/DBB-valves.html
[36] Pneumatic valve actuator
http://www.globalspec.com/learnmore/flow_transfer_control/valve_actuators_positioners/pneumatic_valve_actuators
[37] Krohne Magnetic Level Gauge – BM 26 A Bypass Level Indicators
http://cdn.krohne.com/dlc/TD_BM26-Bas-Adv_en_121011_4000305705_R05.pdf
[38] Gutor - UPS Systems
http://www.schneider-electric.com/products/ww/en/8300-industrial-specialized-ups-and-power-conversion/8310-
ups/61352-gutor-pxw/
[39] Caterpillar Solar Turbines
http://www.caterpillar.com/en/company/brands/solar-turbines.html
[40] Nitrogen generator Flowserve N2 Genpac information and datasheet
http://www.flowserve.com/Products/Seals/Accessories/N2-Genpac,en_US
[41] CompAir compressor manual
http://www.google.ie/url?sa=t&rct=j&q=&esrc=s&frm=1&source=web&cd=4&ved=0CDMQFjAD&url=http%3A%
2F%2Fcomprforum.ru%2Fdownload%2Ffile.php%3Fid%3D702&ei=rZlUVe_-
Cu6s7Aa9g4DYBQ&usg=AFQjCNFFXo6D5IUNv_j6OGcX2z7mmiuAlA&sig2=tzAbL9xra8WxDqxtcf5sCQ
[42] Domnick Hunter compressed air dryer
http://www.parker.com/portal/site/PARKER/menuitem.7100150cebe5bbc2d6806710237ad1ca/?vgnextoid=f5c9b5bb
ec622110VgnVCM10000032a71dacRCRD&vgnextfmt=EN&vgnextcatid=7912948&vgnextcat=DOMNICK+HUNT

69
ER+DESICCANT+AIR+DRYERS
[43] Reverse osmosis fresh water system
http://www.saltsep.co.uk/

70
Figures and Tables
Figure 1 Platform Alpha Gas Processing Train.........................................................................................9
Figure 2 Kinsale Head Area Subsea(P&ID A-012-04-5010A)...................................................................10
Figure 3 Subsea process flow schematic and operating ranges (P&ID A-012-04-5010B)...........................11
Figure 4 offshore platform x-mas tree..................................................................................................12
Figure 5 subsea x-mas tree..................................................................................................................12
Figure 6 subsea umbilical....................................................................................................................13
Figure 7 Seven Heads process flow schematic (P&ID A-012-04-5030A)...................................................13
Figure 8 3 - phase horizontal inlet separator.........................................................................................14
Figure 9 magnetic level gauge .............................................................................................................15
Figure 10 Gate valve ...........................................................................................................................16
Figure 11 Globe valve..........................................................................................................................16
Figure 12 Ball valve.............................................................................................................................17
Figure 13 Double Block and Bleed (DBB) Valve......................................................................................17
Figure 14 pneumatic valve actuator.....................................................................................................18
Figure 15 I/P Transducer.....................................................................................................................18
Figure 16“Krohne magnetic level gauge – BM 26 a Bypass Level Indicator”............................................19
Figure 17 Annubar Flow Meter............................................................................................................19
Figure 18 process flow schematic (P&ID A-012-04-5000A).....................................................................20
Figure 19 Compression train 1 process flow schematic (P&ID A-012-04-5090A)......................................22
Figure 20 Compression train 2 process flow schematic (P&ID A-012-04-5006A)......................................23
Figure 21 Variouspointsonthe performance curve dependinguponthe flow ratesandpressure
difference ..........................................................................................................................................24
Figure 22 Dehydration process flow schematic (P&ID A-012-04-508A)...................................................25
Figure 23 the formation of hydratesin pipeline....................................................................................26
Figure 24 the glycol contractor/absorber .............................................................................................27
Figure 25 the contractor tray with bubble-caps....................................................................................27
Figure 26 the TEG (Triethylene glycol) unit...........................................................................................28
Figure 27 Injection & Compression process flow schematic (P&ID A-012-04-508A).................................29
Figure 28 Metering and pigging process flow schematic (P&ID A-012-04-509A)......................................30
Figure 29 a pig in a pipeline.................................................................................................................30
Figure 30 Inch Metering process flow schematic (P&ID A-012-04-5200A)...............................................31
Figure 31 Inch Onshore Terminal facility metering stream.....................................................................32
Figure 32 Daniel Dual-Chamber Orifice Fitting “Senior”.........................................................................33
Figure 33 Daniel Single Chamber Orifice Fitting “Junior” .......................................................................34
Figure 34 Emerson FloBoss™ S600+ Flow Computer .............................................................................34
Figure 35 flow computer current report...............................................................................................35
Figure 36 flow computer daily report...................................................................................................35
Figure 37 Daniel Danalyzer 700............................................................................................................36
Figure 38 Daniel Danalyzer- Model 700 Gas Chromatograph - Functional Block Diagram. ......................37
Figure 39 chromatographelectrical output proportional to the component concentration.....................38
Figure 40 natural gas sample analyzing................................................................................................38
Figure 41 Dew Points of Aqueous Triethylene Glycol Solutions at Various Contact Temperatures............39
Figure 42 water and hydrocarbon dew pointenvelope .........................................................................39

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