piotr blaut student placement report

2015

Piotr Blaut

Department of Physical Sciences

Kinsale Energy Limited Cork

AbstractThis 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

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Contents1. 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 Dehydration Principles............................................................................................................26

7. Injection & Compression......................................................................................................................29

8. Metering & Pigging..............................................................................................................................30

9. Inch Onshore Metering Terminal.........................................................................................................31

Piotr Blaut IP3 Student Placement Report

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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

Gas Dehydration and Glycol Regeneration


http://www.nmci.ie/index.cfm/page/course/courseId/25

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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.

3. PSE Kinsale Energy Limited


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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

gas is generally composed of methane and other gases, such as ethane or propane [4].


http://www.kinsale-energy.ie/useful-information.html

http://www.kinsale-energy.ie/history.html

http://www.kinsale-energy.ie/about-us.html



http://www.kinsaleenergy.ie/

http://www.kinsale-energy.ie/

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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 ProductionThe 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 StorageGas 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 IrelandPSE 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].


http://www.dcenr.gov.ie/nr/rdonlyres/8ad0eddb-3237-4157-b230-2d467a3c1f9c/0/4dcenrgasstorageexecutivesummary.pdf

http://www.kinsale-energy.ie/gas-storage.html



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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.

2. Subsea


http://www.kinsale-energy.ie/gas-production.html


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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)


http://www.2b1stconsulting.com/umbilical/

http://www.piping-world.com/xmastree_01.html

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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 TreesOffshore 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:

Master Valve [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.




https://oilandgastechnologies.wordpress.com/2012/08/09/subsea-trees/

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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)


http://www2.emersonprocess.com/en-us/brands/rosemount/flow/dp-flow-products/compact-annubar-flowmeters/pages/index.aspx)

http://offshoreteknikk.com/2013/10/14/separasjon-av-olje-gass-og-vann/


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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

Level measurement




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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].


http://www2.emersonprocess.com/siteadmincenter/pm%20magtech%20documents/00803-0100-6156.pdf

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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].


http://encyclopedia2.thefreedictionary.com/full-way+valve

http://encyclopedia2.thefreedictionary.com/Globe+valve

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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

Valve Actuators

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


http://pixshark.com/ball-valve.htm

http://www.vovalve.com/DBB-valves.html


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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].


http://www.globalspec.com/learnmore/flow_transfer_control/valve_actuators_positioners/pneumatic_valve_actuators

https://www.isa.org/standards-and-publications/isa-publications/intech-magazine/2005/april/supplement-calibration-working-control-value/

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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



http://cdn.krohne.com/dlc/TD_BM26-Bas-Adv_en_121011_4000305705_R05.pdf


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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 Compression Train 1

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.



http://en.wikipedia.org/wiki/Centrifugal_compressor


22


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).



23


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 controlThe 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



24


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.


http://3.bp.blogspot.com/-v5XHvPFlXr4/UvFhL-usZsI/AAAAAAAABGE/cwI-AVR-djE/s1600/0057_Compressor_State_Diagram.png

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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 PrinciplesNatural 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


http://petrowiki.org/Dehydration_with_glycol

27


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


http://www.google.ie/url?sa=i&rct=j&q=&esrc=s&frm=1&source=images&cd=&cad=rja&uact=8&ved=0CAcQjRw&url=http://blog.hy-bon.com/air-pollution-and-glycol-dehydration&ei=Z88TVYfSKMLuPMvggIAP&psig=AFQjCNFy-rEBMpQ0m35UWWl_b2fK10tKgQ&ust=1427448025737064

http://www.glp.com.au/internals/trays/

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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].



http://www.ogj.com/articles/print/volume-97/issue-25/in-this-issue/gas-processing/pc-program-estimates-teg-circulation-rate-number-of-trays.html

29


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


30


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


http://en.wikipedia.org/wiki/Hydraulically_activated_pipeline_pigging

http://ndtservice.net/services/pipeline-inspection-services/intelligent-pigging/

31


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


32


9.1 GAS FISCAL METERINGAll 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 MeterThe 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%.

This is based on the flowing requirements:


http://www2.emersonprocess.com/en-us/brands/remote/liquids_flow_computers/s600/pages/s600.aspx

http://chemwiki.ucdavis.edu/Analytical_Chemistry/Instrumental_Analysis/Chromatography/Gas_Chromatography

http://www2.emersonprocess.com/en-US/brands/daniel/Flow/differential-pressure-flowmeter/Pages/Differential-Pressure.aspx

33


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 ChromatographyGas 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



http://www2.emersonprocess.com/en-us/brands/danalyzer/gc/model-700xa/pages/index.aspx

37


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].


http://www2.emersonprocess.com/siteadmincenter/PM%20Danalyzer%20Documents/DANGC_Manual_3-9000-537_M500.pdf


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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].

Temperature, oC

Pres

sure

, Bar

a H2O Dewpoint

HC Dewpoint

-40 -30 -20 -10 0 +100

10

20

30

40

50

60

70

80

Figure 42 water and hydrocarbon dew point envelope


http://www.michell.com/uk/support/advances-optical-whitepaper.htm

http://dowac.custhelp.com/app/answers/detail/a_id/16639/~/teg---dew-points-of-aqueous-solutions-at-various-temps

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.


http://www.ge-mcs.com/microsites/dewiq/ExploreDewIQ





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].




http://www.systechillinois.com/en/aluminium-oxide-moisture-sensor--_15.html

42


Figure 45 moisture analyser and aluminum oxide probe installed on remote sampling system

Moisture AnalyserThe 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].

CHAPTER III




43


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].


https://www.honeywellprocess.com/library/marketing/whitepapers/FireGasSystem_Whitepaper_April09.1.pdf


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)






46


1.2 Gas Detection PrinciplesDetection 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


http://www.hydrocarbononline.com/doc/performance-and-reliability-in-open-path-gas-0001


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.


https://www.citytech.com/loader/frame_loader.asp?page=https://www.citytech.com/technology/pellistors.asp

http://www.honeywellanalytics.com/en/products/Searchpoint-Optima-Plus

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 PrinciplesMost 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

all based on line-of-sight detection of radiation emitted in the UV, visible and IR spectral bands


http://saba.kntu.ac.ir/eecd/ecourses/instrumentation/projects/reports/smoke%20detector/new_page_4.htm


http://www.gassonic.com/products/

50


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].


http://www.thornsecurity.net/Products/Fire/TSLdetectors/TSLflameTripleIR.asp

http://www.gmigasandflame.com/downloads/white-papers/Flame-Detection-Technologies.pdf



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


https://www.esser-systems.com/en/produkte/details/automatic-detectors/intrinsically-safe/803371ex-optical-smoke-detector-iq8quad-ex-i-wo-isolator.html


53


1.5 Emergency shutdown and process shutdownThe 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].


http://oilandgasproductionhandbook.blogspot.co.uk/2014/02/8-utility-systems-this-chapter-contains.html#Fire_and_gas_system


http://3.bp.blogspot.com/-CbiTkoqvoGk/UvFjBTDNxyI/AAAAAAAABLA/6Kn85MhbzeE/s1600/0096_P&ID_Possible_Shutdown_Actions.png

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 generationThe 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


http://www.schneider-electric.com/products/ww/en/8300-industrial-specialized-ups-and-power-conversion/8310-ups/61352-gutor-pxw/

http://www.caterpillar.com/en/company/brands/solar-turbines.html

56


2.2 Diesel SystemIn 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 AirA 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 BackupInert 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 FiltrationSeawater 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 WaterThe 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.


http://www.saltsep.co.uk/

http://www.flowserve.com/Products/Seals/Accessories/N2-Genpac,en_US

http://www.parker.com/portal/site/PARKER/menuitem.7100150cebe5bbc2d6806710237ad1ca/?vgnextoid=f5c9b5bbec622110VgnVCM10000032a71dacRCRD&vgnextfmt=EN&vgnextcatid=7912948&vgnextcat=DOMNICK+HUNTER+DESICCANT+AIR+DRYERS

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

57


2.7 Fire WaterFirewater 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 GasFuel 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 SystemThe 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 IntroductionThe 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 SummaryMy 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

2.1 Project IntroductionThe 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.

2.2 Project AssumptionsThe 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 SummaryMy 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

specific and consists more details regarding the detector type, principle of works and model. The


61


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)

3. Flame Detectors Field of View Adjustment Project


62


3.1 Project IntroductionThe 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).

3.2 Project AssumptionsThe 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 SummaryTo 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


64


adjustment (approved by OIM) the flame detectors (See Fig 66) - pointing straight to Wellhead

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


[2] Kinsale Energy Limited Activities Information


[3] Kinsale Energy Limited History


[4] Natural Gas Information


[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


[7] Kinsale Energy Limited Gas Storage Process information


[8] Subsea valves specification


[9] Subsea control, umbilicals


[10] Offshoreteknikk - Gas/water separation principles


[11] Emerson - Annubar Flow Meter specification
























66


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.no\ansatte\Onshus_Tor\Oil and gas production handbook ed1x3a5 comp.pdf

[13] Wikipedia – centrifugal compressor specification.


[14] Wikipedia – pipeline pigging principle


[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


[17] Chemwiki - Gas Chromatography principles


[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


[20] General Electric - Moisture Probe and Analyser – Datasheet


[21] Basic Offshore Safety Induction & Emergency Training details


[22] Natural Gas Dehydration























http://www2.emersonprocess.com/en-us/brands/rosemount/flow/dp-flow-products/compact-annubar-flowmeters/pages/index.aspx

http://www2.emersonprocess.com/en-us/brands/rosemount/flow/dp-flow-products/compact-annubar-flowmeters/pages/index.aspx

67



[23] Fire and Gas Detection Systems information


[24] Sieger Searchline Excel Infra-red Open Path Gas Detector System


[25] Searchpoint Optima Plus Point Infrared Gas Detector


[26] Pellistor principles


[27] Ultrasonic Gas Leak Detection principles


[28] Heat Detection principles


[29] Flame Detection principles


[30] S200 Triple IR Solar Blind Flame Detector Thorn S261f+


[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-

contains.html#Fire_and_gas_system

[33] Magnetic Level Gauge principles




























68


[34] Valve types and work principles


[35] DBB valve work principles


[36] Pneumatic valve actuator


[37] Krohne Magnetic Level Gauge – BM 26 A Bypass Level Indicators


[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


[40] Nitrogen generator Flowserve N2 Genpac information and datasheet


[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=f5c9b5bbec622110VgnVCM10000032a71dacRCRD&vgnextfmt=EN&vgnextcatid=7912948&vgnextcat=

DOMNICK+HUNTER+DESICCANT+AIR+DRYERS

[43] Reverse osmosis fresh water system









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_-%20Cu6s7Aa9g4DYBQ&usg=AFQjCNFFXo6D5IUNv_j6OGcX2z7mmiuAlA&sig2=tzAbL9xra8WxDqxtcf5sCQ



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
















69


Figures and TablesFigure 1 Platform Alpha Gas Processing Train...............................................................................................9Figure 2 Kinsale Head Area Subsea (P&ID A-012-04-5010A).......................................................................10Figure 3 Subsea process flow schematic and operating ranges (P&ID A-012-04-5010B).............................11Figure 4 offshore platform x-mas tree.........................................................................................................12Figure 5 subsea x-mas tree..........................................................................................................................12Figure 6 subsea umbilical............................................................................................................................13Figure 7 Seven Heads process flow schematic (P&ID A-012-04-5030A)......................................................13


70


Figure 8 3 - phase horizontal inlet separator...............................................................................................14Figure 9 magnetic level gauge.....................................................................................................................15Figure 10 Gate valve....................................................................................................................................16Figure 11 Globe valve..................................................................................................................................16Figure 12 Ball valve......................................................................................................................................17Figure 13 Double Block and Bleed (DBB) Valve............................................................................................17Figure 14 pneumatic valve actuator............................................................................................................18Figure 15 I/P Transducer..............................................................................................................................18Figure 16“Krohne magnetic level gauge – BM 26 a Bypass Level Indicator”...............................................19Figure 17 Annubar Flow Meter....................................................................................................................19Figure 18 process flow schematic (P&ID A-012-04-5000A).........................................................................20Figure 19 Compression train 1 process flow schematic (P&ID A-012-04-5090A)........................................22Figure 20 Compression train 2 process flow schematic (P&ID A-012-04-5006A)........................................23Figure 21 Various points on the performance curve depending upon the flow rates and pressure difference....................................................................................................................................................24Figure 22 Dehydration process flow schematic (P&ID A-012-04-508A).......................................................25Figure 23 the formation of hydrates in pipeline..........................................................................................26Figure 24 the glycol contractor/absorber....................................................................................................27Figure 25 the contractor tray with bubble-caps..........................................................................................27Figure 26 the TEG (Triethylene glycol) unit..................................................................................................28Figure 27 Injection & Compression process flow schematic (P&ID A-012-04-508A)...................................29Figure 28 Metering and pigging process flow schematic (P&ID A-012-04-509A)........................................30Figure 29 a pig in a pipeline.........................................................................................................................30Figure 30 Inch Metering process flow schematic (P&ID A-012-04-5200A)..................................................31Figure 31 Inch Onshore Terminal facility metering stream..........................................................................32Figure 32 Daniel Dual-Chamber Orifice Fitting “Senior”..............................................................................33Figure 33 Daniel Single Chamber Orifice Fitting “Junior”.............................................................................34Figure 34 Emerson FloBoss™ S600+ Flow Computer...................................................................................34Figure 35 flow computer current report......................................................................................................35Figure 36 flow computer daily report..........................................................................................................35Figure 37 Daniel Danalyzer 700...................................................................................................................36Figure 38 Daniel Danalyzer - Model 700 Gas Chromatograph - Functional Block Diagram.........................37Figure 39 chromatograph electrical output proportional to the component concentration.......................38Figure 40 natural gas sample analyzing.......................................................................................................38Figure 41 Dew Points of Aqueous Triethylene Glycol Solutions at Various Contact Temperatures.............39Figure 42 water and hydrocarbon dew point envelope...............................................................................39Figure 43 Moisture Analyser with Aluminum Oxide sensor.........................................................................40Figure 44 Aluminum Oxide probe................................................................................................................41Figure 45 moisture analyser and aluminum oxide probe installed on remote sampling system.................42Figure 46 F&G Cause and Effect Chart.........................................................................................................44Figure 47 F&G detection and control system..............................................................................................45Figure 48 programmable electronic systems (PES)......................................................................................45Figure 49 Sieger Searchline Excel Infra-red Open Path Gas Detector System..............................................46Figure 50 Searchpoint Optima Plus Point - Infrared Gas Detector...............................................................47Figure 51 Pellistor........................................................................................................................................48


71


Figure 52 the Gassonic Surveyor Ultrasonic Gas Leak Detector...................................................................49Figure 53 polar diagram shows the directional sensitivity of the detector using a 0.1m2 n-heptane fire...50Figure 54 S200 Triple IR Solar Blind Flame Detector Thorn S261f+..............................................................51Figure 55 the U7602 Detector/Controller...................................................................................................52Figure 56 Optical - beam Smoke Detector...................................................................................................52Figure 57 Separator with limit switches......................................................................................................53Figure 58 Emergency Shutdown Cause and Effect Chart.............................................................................54Figure 59 Platform Alpha Power Distribution System..................................................................................55Figure 60 Glycol Reboiler vessel old sight glasses........................................................................................59Figure 61 Glycol Regeneration system bean valves.....................................................................................59Figure 62 Platform Alpha gas detectors list fragment (example).................................................................61Figure 63 Platform Alpha - Gas Compression Fire & Gas Equipment Layout (G – gas; H – heat; F – flame; MA – manual switch)...................................................................................................................................61Figure 64 Platform Alpha – Process Hall Flame Detection...........................................................................63Figure 65 Platform Alpha Main Deck Wellhead area flame detection area before adjustment..................64Figure 66 Platform Alpha Main Deck Wellhead area flame detectors view direction adjusted...................64Figure 67 Platform Alpha Main Deck Wellhead area flame detection area after adjustment.....................64

Table 1 Subsea equipment and operating ranges........................................................................................11Table 2 7 Heads equipment and operating ranges......................................................................................14Table 3 Wellhead equipment and operating ranges and equipment list.....................................................20Table 4 Compression train 1 process operating ranges and equipment list................................................22Table 5 Compression train 2 operating ranges and equipment list.............................................................23Table 6 Dehydration process operating ranges and equipment list............................................................25Table 7 Injection & Compression operating ranges and equipment list......................................................29Table 8 Metering operating ranges and equipment list...............................................................................30Table 9 Inch Metering operating ranges and equipment list.......................................................................31

ACKNOWLEDGEMENTS

The work placement opportunity I had with the Kinsale Energy Limited was a great chance for

learning and professional development. Therefore, I consider myself as a very lucky individual as

I was provided with an opportunity to be a part of it. I am also grateful for having a chance to

meet so many wonderful people and professionals who led me though this work placement period.


72


I express my deepest thanks to Mr. Steve Davis, Engineering and Maintenance Manager of

Kinsale Energy Limited for taking part in useful decision & giving necessary advices and

guidance and arranged all facilities to make life easier.

I would like to show my gratitude to the Control System Engineer of Kinsale Energy Limited

Mr. Paul Dowling who in spite of being extraordinarily busy with his duties, took time out to hear,

guide and keep me on the correct path and allowing me to carry out my projects at their esteemed

organization and extending during the training.

I am also immensely grateful to all the Kinsale Energy Limited company crew for their help and

patience.

I perceive as this opportunity as a big milestone in my career development. I will strive to use

gained skills and knowledge in the best possible way, and I will continue to work on their

improvement, in order to attain desired career objectives. Hope to continue cooperation with all of

you in the future.
