Champion-7 Full Report.pdf

[FACILITIES ENGINEERING PROJECT] CHAMPION-7 FIELD OFFSHORE BRUNEI

NAME

: AKMAL WAFI BIN ADLY HAZRAMI 2014205384 AIN NUR ATIQA BINTI AZMI 2014230846 FATEN AMIRA BINTI HAMIDI 2014404804 NUR AMANINA BINTI AHMAD NIZAMUDDIN 2014260632 NURUL FADZILAH BINTI MOHD FIRDAUS 2014229456

GROUP

: EH243 6B

DATE OF SUBMISSION

: 21 / 06 / 2017

LECTURER’S NAME

: MR FAZRIL IRFAN BIN AHMAD FUAD

Table of Contents ACKNOWLEDGEMENT ............................................................................................................................ 3 CHAPTER 1 : INTRODUCTION ................................................................................................................. 4 CHAPTER 2 : PROJECT BACKGROUND .................................................................................................... 5 2.1 Organization Chart ........................................................................................................................ 6 CHAPTER 3 : PRODUCTION FORECAST ................................................................................................... 7 3.1 Number of Wells ........................................................................................................................... 7 3.2 Calculation of Plateau Rate ........................................................................................................... 8 3.3 Well Spacing .................................................................................................................................. 8 3.4 Type of Casing ............................................................................................................................... 9 3.5 Size of Drill Bits ............................................................................................................................ 10 3.6 Cementing ................................................................................................................................... 10 3.7 Drilling Platform .......................................................................................................................... 10 3.8 Drilling Techniques ...................................................................................................................... 12 3.9 Injection Wells............................................................................................................................. 14 3.10 Drilling Costing .......................................................................................................................... 16 CHAPTER 4 :SUBSURFACE DEVELOPMENT PLANT............................................................................... 18 4.1 Scenario 1 : Satellite Platform to CPP and to COT Via Tanker .................................................... 18 4.1.1 Selection of Platform ........................................................................................................... 19 4.1.2 Design of Platform ............................................................................................................... 20 4.1.3 Jacket Platform .................................................................................................................... 22 4.1.4 Satellite Platform/Wellhead Platform ................................................................................. 23 4.1.5 Injection Platform ................................................................................................................ 23 4.1.6 Process Design ..................................................................................................................... 24 4.1.7 Layout of Platform ............................................................................................................... 25 4.1.8 Tanker .................................................................................................................................. 28 4.1.9 Seria Crude Oil Terminal ...................................................................................................... 28 4.2 Scenario 2 : Satellite Platform to FPSO and to COT Via Tanker .................................................. 29 4.2.1 Floating, Production, Storage and Offloading (FPSO) .......................................................... 30 4.2.2 FPSO Design ......................................................................................................................... 31 4.2.3 Process Design ..................................................................................................................... 33 4.2.4 Layout of Platform ............................................................................................................... 35 4.3 Scenario 3 : Satellite Platform to CPP and to COT Via Pipeline .................................................. 37

4.3.1 Crude Oil Pipeline ................................................................................................................ 38 4.3.2 Process Design ..................................................................................................................... 38 4.3.3 Layout of Platform ............................................................................................................... 40 CHAPTER 5 : ECONOMIC....................................................................................................................... 43 5.1 Summary for Scenario 1, Scenario 2 and Scenario 3 .................................................................. 44 5.2 CAPEX : Scenario 1 ...................................................................................................................... 45 5.3 OPEX : Scenario 1 ........................................................................................................................ 46 5.4 CAPEX : Scenario 2 ...................................................................................................................... 47 5.5 OPEX : Scenario 2 ........................................................................................................................ 48 5.6 CAPEX : Scenario 3 ...................................................................................................................... 49 5.7 OPEX : Scenario 3 ........................................................................................................................ 50 5.8 Comparison of CAPEX and OPEX ................................................................................................. 51 5.9 OPEX Planned Maintenance- General......................................................................................... 52 CHAPTER 6 : HEALTH, SAFETY AND ENVIRONMENT ........................................................................... 53 CHAPTER 7 : CONCLUSION ................................................................................................................... 61 REFERENCES .......................................................................................................................................... 62 APPENDICES .......................................................................................................................................... 63

ACKNOWLEDGEMENT We would like to express our deepest gratitude to our lecturer, Mr Fazril Irfan bin Ahmad Fuad who had been a big helping hand since we started this mini project, and for continually and convincingly conveyed a spirit of adventure in Facilities Engineering and foremost in the Oil and Gas Industry for this particular project. Without his guidance and persistent help in this matter, this report would not have been possible. The gratitude also extends to each person of this group members; Akmal Wafi bin Adly Hazrami, Ain Nur Atiqa binti Azmi, Faten Amira binti Hamidi, Nur Amanina binti Ahmad Nizamuddin and Nurul Fadzilah binti Mohd Firdaus for always helping out each other and making each other’s work a lot easier by discussing, analysing and for giving a remarkable idea on this mini project. Due to fact that each person had been a great help, this report is successfully written. Besides, warmest thanks to whole classmates for their genuinely kindness and honesty in delivering their perspectives and ideas in making this project a success. Last but not least, we would like to thank our parents for always supporting and guiding us throughout this journey.

CHAPTER 1 : INTRODUCTION Champion-7 Field is located offshore Brunei in the Kuala Belait Delta Province, approximately 100 km from Kuala Belait in some 80 m water depth and was discovered in 2016. The field is a simple, low relief, domal structure bounded by two E-W trending, north heading growth sealing faults, covering an area of 6km x 3km. One of the prospective reservoirs in Champion-7, C7-Rx 2.80 has been proposed to be developed for commercialization. A feasibility study will be carried out basically to determine the maximum recovery with minimum cost while assessing the techno commercial viability of developing the field. The study will consider: i.

drilling requirements e.g. number of wells, well spacing, drilling program, completion strategy etc

ii.

production techniques and policy anticipated e.g. artificial lift needed, pressure maintenance, etc

iii.

facilities required for drilling and production

iv.

development time, cost expected and production forecast This paper will provide three alternatives for field development scheme together with

the economic analysis for each alternative made. The three alternatives are: i.

Scenario 1: Satellite Platform to CPP and to COT Via Tanker

ii.

Scenario 2 : Satellite Platform to FPSO and to COT Via Tanker

iii.

Scenario 3 : Satellite Platform to CPP and to COT Via Pipeline

CHAPTER 2 : PROJECT BACKGROUND The C-7 2.80 reservoir has a sizable gas cap and the original reservoir pressure is assumed as at bubble point pressure. The main drive mechanism of the reservoir is depletion drive supplemented by a weak aquifer and the gas cap whereby the energy for the transport and production of reservoir fluids is provided by the expansion of gas either in the gas cap or inside the oil phase, or from water moving in from the aquifer below and displaces the oil. The aquifer and gas cap drives become strong at the later stage of the reservoir life due to water injection scheme and thus become the primary drive mechanisms. However, due to continuous depletion, both water injection and gas injection will be exercised to produce 300 MMstb stock tank oil initially in place (STOIIP) with expected recovery of 120 MMstb. From a survey conducted, C-7 Rx 2.80 has the following properties: Depth: 7830 ft. ss

Oil specific gravity: 42 API

Reservoir temperature: 180

Permeability: 70 mD

Reservoir thickness: 200 ft

Oil viscosity: 0.3 cP

Initial reservoir pressure: 3420 psi

Initial volume factor: 1.55

Porosity: 18% To assess the techno-commercial viability of developing C-7-Rx 2.80, we had carried out the necessary Engineering Feasibility Studies where we looked into the design process, equipment, design layout, economic consideration; CAPEX AND OPEX for every scenario.

2.1 ORGANISATION CHART Below is the organisation chart of our team.

CHAPTER 3 : PRODUCTION FORECAST

PRODUCTION FORECAST Production of Oil (MMstb/year)

16 14

14.6 13.5

12

12

10

11 10

8

9 8

6 4

8

8

7 5

5 4

2

3

0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 Year

Figure 1 : Graph of Production Forecast for Champion-7 Field The Champion-7 field is an under-saturated reservoir with its initial reservoir pressure being higher than the bubble point pressure. The stock tank oil initially in place (STOIIP) of Champion-7 field is 300 MMstb with expected recovery of 120 MMstb. From the production forecast profile, it can be seen that hydrocarbon started produced at the fourth year with production rate of 172 000 bbl/day. In the production forecast, it can be seen that the plateau achieved at the 13th year of production phase with the highest production of 14.6 MMbbl/year from the 20 wells. The plateau period is 4 years. Each well is said to produce 730 000 Mbbl/year.

3.1 NUMBER OF WELLS. Average flowrate = 100 000 bbl/day. = 36 500 000 bbl/year. Duration of production at Champion-7 = 43 years (1972-2015). Total number of wells at Champion-7 = 260 wells.

Average reserve produce per well = = 6.04 MMbbl/well, Number of well = = 19 ≈ 20 wells.

3.2 CALCULATION FOR PLATEAU RATE. The plateau rate is determined based on the maximum production of production wells with assumption that each well may produce the maximum of 2000 bbls/ day. Therefore, plateau rate is 14.6 MMbbl/year. Plateau rate = Maximum production of production wells x number of well = 2000 bbl/day x 20 = 40 000 bbl/day = 14.6 MMbbl/year

3.3 WELL SPACING. Well method of producing oil and gas is commonly used in the development and operation of oil and gas properties include well spacing in a given tract. Well spacing is depends on condition of reservoir. The method is based on fundamental of energy principle. This method focused on the state and change of state of fluids confined under pressure within porous and permeable reservoir to direct flow from reservoir in and out of drilled well with decrease of potential energy. The increased yield of well is not depends on number of wells added. However, the cost of development increases as increases number of wells per tract. Therefore, as we increases the number of wells to increase the quantity of oil produced , there is an economic limit to the number of wells to be added hence showed the importance well spacing to the oil production.

For Champion-7 oil fields we used typical well spacing offshore which are 0.5 to 1 km (0.3 to 0.6 miles) spacing between well.

3.4 TYPE OF CASING The Champion-7 oil field is highly compartmentalised, characterised by large areas of fault or dip closures, from the seabed downwards. Combined with the multi-layered nature of the stratigraphic succession, striking sub-parallel to most of the faults, the numerous hydrocarbon traps are relatively small and generally stacked. It also consists of heterogeneous reservoir, consisting of mainly fine grained shallow marine to coastal/delta plain sands. Due to the reservoir condition at Champion-7 oil field, types of casing use are surface casing, intermediate casing, production casing and liner. Surface casing is run first to protect the weak formations, water sands and hydrocarbon zone that are encountered at shallow depth from collapse. Intermediate casing is running second in order to isolate if there is a lost circulation zone, unstable shale zone and other troublesome formation between surface and production casing. Production casing is then run after the intermediate casing to isolate producing zone, provide reservoir fluid control and to permit selective production in multizone production. Last to be installed is the liner to support the production and intermediate casing to reduce the costs of drilling. The configuration of casings used in Champion-7 is as follows:

Surface casing ( size: 13-3/8” ), 1500ft. Intermediate casing ( size: 9-5/8” ), 3000ft. Production casing ( size: 7”), 5000ft.

Liner

3.5 SIZE OF DRILL BITS Due to the type of reservoir at Champion-7 oil field, two types of bits are used which are roller cone bits and diamond bits. The size of bits used was depends on size of the casing. Size of bits used for each casing is as follows: a. Surface casing : 14-3/4” b. Intermediate casing: 12-1/4” c. Production casing: 8-1/2”

3.6 CEMENTING Oil well cementing is a process of mixing slurry of cement and water and pumping it through the casing pipe into the annulus between the casing pipe and the drilled hole. Cement is used to prevent movement of fluids between permeable zones, to support the casing string in the borehole, to protect the casing from corrosive fluids in the formation and support for the wellbore walls to prevent collapse of formations. There are many types of cement in the oil industry that can be used depends on characteristics of the reservoir. For Champion-7 oil field, we decided to use cement class G because it most common cement used. Beside s that, it can be used up to 8000 ft depth, general purpose cement and can be modified using additives to suit application. Due to no specific condition for this case, there are no additives added to the cement.

3.7 DRILLING PLATFORM. For Champion-7 oil field with water depth of 80 m, Jacket platform was chosen to be used. This is because jacket platform fit the condition of water depth at the Champion-7 oil field which is not exceed than 500m. Besides that, jacket platform also have low capital as compared to other type of platform. These type of platform may be anchored directly to the seabed cause it to be a fixed platform. Their deck is supported by a steel tubular structure having its feet on the seabed. In order to fix the jacket onto the seabed, the jacket is equipped with thick steel piles of 2 meters

diameter that can penetrate the sea floor up to 100 meters deep. This helped to ensure the stability of the whole platform. Jacket platform have hundreds meters high and weight of thousand tonnes. The height of the jacket is defined by the water depth about 15 meters above the sea level. Furthermore, jacket platform been chosen because it can withstand multiple type of constraints such as weight of the processing equipment , waves impact, wind pressure, flow of sea water streams and tides, corrosion, fatigue effect, life cycle time and drilling techniques. This condition shows that jacket platform has a flexible characteristic that can conform into many type of offshore situations. Basically, in this platform, jacket act as a cage that protect all the piping going through to the seabed. Pipes also being protected from lateral load due to the space tubular frame. The deck legs are used to connect the deck structure to the jacket transferring efforts both ways. Jacket is designed with natural period of 2.5 seconds while the waves have a period of 14 to 20 seconds. This will prevent vibrations amplification under the waves effect. Therefore, jacket platform can be used for a long period of time with minimal effect on its performance.

Figure 2 Jacket Platform

3.8 DRILLING TECHNIQUES For Champion-7 oil field with several types of reservoir condition, two types of drilling technique were used which are vertical drilling and deviated drilling. Vertical drilling was done when the oil and gas reserves located directly beneath the surface access point. A vertically drilled well may go right through the reserve, tapping into only a portion of the available energy. Vertical drilling is less expensive as compared to other method thus it is known as a conventional method. However, vertical drilling was limited to be used. This is because vertical well have limited angles that make them less able to reach a wider section of underground territory. Since a vertical well can only access oil and natural gas reserves directly below, large field productive requires the drilling of many vertical wells. Vertical drilling impractical to be used in cases that involved thin layers of reserve located over a wide area. Because a vertical well can only be drilled in one direction, the exploration company must estimate the most productive portion of the reserve before start drilling to avoid loss. Another technique used is deviated drilling. Deviated drilling is a drilling technique that runs to allow the wellbore to incline from the original vertical path of the oil well. Generally, deviated drilling is carried out to improve the reservoir exposure and to access the resources in maximum ways. A wellbore can be drilled at a deviated angle by using different machinery such as bottomhole assembly, whipstocks, steerable motor assembly, and steerable rotary motors to name a few. These kinds of assembly enable the drill bits to change its direction towards target that is not directly beneath the surface access point. By opting to use deviated drilling, an oil manufacturing company can get increased exhibition to an oil reservoir that was less accessible in a vertical position. For Champion-7, in all scenarios, we have 8 deviated wells and 12 vertical wells.

Figure 3 Vertical and Deviated Drilling

3.9 INJECTION WELLS In Champion-7 oil field, we used two types of injection well which are water and gas injection well. Water and gas injection were used to enhance oil recovery during production phase. Water injection well is a well use to inject water in the reservoir. The principle of water injection system is the pumping of water into reservoir to maintain the reservoir pressure. Water then displaced the remaining oil in the reservoir. The oil escaped out from the reservoir towards the production well.

Figure 4 Water Injection

Gas injection well is used as a medium to inject gas into the reservoir. The gas will inject into the gas cap region in order to maintain the cap pressure. The gas cap will force the oil towards production well. In all scenarios we required one water injection well and one gas injection well.

Figure 5 Gas Injection

Therefore, in all scenarios of Champion-7 Oil Field, we needed two water injection well and one gas injection well to support the oil production.

3.10 DRILLING COSTING In this field, 12 wells are for vertical well and only 8 for deviated and it is all depends on the considerations as explained before. For cost per feet of a bit, the formula used to calculate it is as below:

C = [R(T + t) + B]/F where: C = drilling cost per foot ($/ft) R = rig operating cost per hour ($/hours) T = drilling time/ rotating time with the bit on bottom (hours) t = trip time (hours) B = bitcost ($) F = footage drilled (ft)

Assume that: R = 1320$/hours T = 58.1 hours t = 13.92 hours B = 7000$ F = 200 ft

Calculations:

Types Of Well

Vertical Well

Cost Per Foot

Cost Per Well

No. Of Well

Total Cost

( $/ ft )

($)

510

4 million

12

48 million

510

5 million

8

40 million

510

4 million

3

12 million

($)

@ 7830ft Deviated Well @ 9804ft Water and Gas Injection Well @ 7830ft Total drilling costs Table 1: Calculation of drilling costs.

100 million

Assumption: 5days to drill 1000ft well. Time Estimates= 5.0 days/1,000 ft * 7,830 ft = 39 days/well

CHAPTER 4 : SUBSURFACE DEVELOPMENT PLANT 4.1 SCENARIO 1: SATELLITE PLATFORM TO CPP AND TO COT VIA TANKER

Satellite Platform

CPP

Tanker

COT

In Champion-7 field, the original oil in place, STOIIP is 300 MMstb and the expected recovery is 120 MMstb. For Scenario 1, the transportation crude oil is from the satellite platform, to Central Processing Platform (CPP), then to Crude Oil Terminal (COT) via tanker. For Scenario 1, we decided to use three satellite platform (SP), one CPP, and one tanker once in a months. Central processing platforms are mostly 6 to 8 leg jacket installations platforms. They are typical four decks in process platforms like sub-cellar deck, cellar deck, mezzanine deck, top deck. Based on the Champion 7 field, the application of this jacket type for our CPP is practically possible because this platform economically feasible for installation in water depths up to about 1,700 feet (520 m) while our field depth is up about .This platform also designed for long term use and the leg installed can store oil. However, decommission and

jacking operation for the platform is quite expensive beside this platform is not flexible against deflection. 4.1.1 SELECTION OF PLATFORM For platform selection in Champion-7 field, we had choose jacket platform due to water depth and cost consideration. The factor that contributed to selection of jacket platform are: i)

Can be used in shallow water (up to 500m)

ii)

Easy installation

iii)

Support large deck loads

iv)

Limited structure

The design of an offshore platform involves consideration for both operational and environmental loads factors and practical to construct. Furthermore, the platform must be cost effective as well as provide a satisfactory return on investment. Factors of operational loads are : i)

Structure weight

: Weight of fixed platform body, the decks, piles, grouts, and etc.

ii)

Equipment weight

: Consists of the weight of the drilling and production equipment, as well as other infrastructure mounted on the basic platform.

iii)

Operating loads

: Imposed during operating conditions which are including loads of drilling fluid, water, produced fluids, injection fluids, and anchors.

iv)

Wellhead loads

: Include casing, tubing, wellheads, and etc. For subsea completions, these are replaced by the load due to production riser.

v)

Temporary phase

: fabrication, load-out, transportation, lifting, launching and positioning, piling and also grouting.

Factors of environmental loads are : i)

Waves

: Wave energy, period, height, etc.

ii)

Winds

: Wind velocities are ascertained for two conditions which are steady winds and sudden sharp gusts.

iii)

Currents

: The velocity at the surface.

iv)

Corrosion control : Using painting, metal wrap for splash zone and sacrificial anode or impressed current for jacket.

4.1.2 DESIGN OF PLATFORM In general, this jacket platform can be categorized into five modules which are; accommodation module, drilling module and power generator module (located at upper deck), production module and wellhead module (located at lower deck). Description of modules : i)

Accommodation Module

: This module consists of living quarters which can equipped for 160 personnel at once, galley which able to serve up to 80 personnel, recreations and medical service.

ii)

Drilling Module

: This module consists of all the equipment for drilling system and drilling works. This including a rotary rig, rotary motor, etc.

iii)

Power Generation Module : This module consists of two gas turbine generator units which produce 250 M Watt power. Produced gas is used as fuel to generate electricity. As a backup, diesel generator is used which the diesel used for fuel to generate electricity.

iv)

Production Module a. Separation Module

: This module consists of two of 2-phase separator ; One gas liquid vertical separator and one water-oil horizontal separator, and one of 3-phase horizontal separator.

b. Gas Treatment Module

: This module consists of gas sweetening, gas compression and gas dehydration which is used to removing common contaminants such as water, carbon dioxide (CO2), and hydrogen sulfide (H2S). Some of these contaminants have economic value and are further processed or sold.

c. Gas Compression Module: This module consists of gas compressor for gas injection system. Gas compressor is used for gas lift to improve the production, or a fuel for electricity generation. d. Water Treatment Module : Produced water contains contaminants that require removal before proper disposal or reuse. Some of the impurities or substances likely to be found in produced water include oil, naturally occurring radioactive materials (NORM), waxes, greases, sand, scales, H2S, dissolved salts and various metals. This module consists of desander cyclone, deoiler cyclone, gas filtration and nut shell filtration. e. Wellhead Module

: This module consists of several well slots that are installed at this area.

4.1.3 JACKET PLATFORM Jacket is steel frame supporting the deck and the topsides in a fixed offshore platform that usually use in the oil and gas exploration and production. Jacket platforms may be anchored to the seabed in the areas where the water depth does not exceed 500 meters. In order to piled the jacket onto the seabed, the jacket is equipped with thick steel piles of 2 meters diameter that can penetrate the seabed up to 100 meters deep to ensure the stability of the whole platform. The jacket may be hundreds meter high and weight thousands tonnes. The height of the jacket is defined by the water depth plus about 15 meters above the sea level. The jacket acting as a cage, which are protecting all the piping going through to the seabed as well as protecting from lateral load. The tubular structure of a jacket is designed to support multiple constrains: i)

Weight of the processing equipment (topsides)

ii)

Impact of waves

iii)

Pressure of the wind on the topsides

iv)

Flow of the sea water streams and tides

v)

Corrosion

vi)

Fatigue effect

vii)

Life cycle time

4.1.4 SATELLITE PLATFORM/WELLHEAD PLATFORM Satellite platform is a smaller platform only housed the wellhead for the production and the separators for well testing purpose. Satellite platforms mostly four legs unmanned platforms. For Champion 7 field, our satellite platforms consist of three decks in which all the piping, equipment, instrumentation, electrical apparatus and Christmas tree are arranged. The names of these three decks are mezzanine deck, cellar deck and helideck. A typical satellite platform may have around thirty wellheads located on the platform and directional drilling allows reservoirs to be accessed at both different depths and at remote positions up to 5 miles (8 kilometers) from the platform. For Champion 7 field each platform may have around six to seven wellhead located on the platform Many platforms also have remote wellheads attached by umbilical connections, these may be single wells or a manifold centre for multiple wells. Wellhead Platforms are designed to operate remotely under normal operations, only to be visited occasionally for routine maintenance or well work Or personnel visit the platform for well testing and other maintenance activities. Wells are drilled normally by Jack up Rigs that dock with the platform. Well servicing is done either by Jack up rigs or by Modular Rigs that are assembled over the platform.

4.1.5 INJECTION PLATFORM For Scenario 1, we decided to install one unit of water injection platform with two injection well and one unit of gas injection platform with one injection well. We choose jacket platform as injection platform and also it is unmanned platform. Total of wellheads for these platform is 3 wellheads. For both water and gas injection platform, the water injection system and also the gas injection system were installed separately. The water treatment system has been installed in order to treat the produced water for reinjection purpose.

4.1.6 PROCESS DESIGN A)

PFD OF CPP

B)

PFD OF SP

4.1.7 LAYOUT OF PLATFORM A) SATELLITTE PLATFORM

Figure 6 SP Main Deck

Figure 7 SP Mezzanine Deck

Figure 8 SP Cellar Deck

B) CENTRAL PROCESSING PLATFORM

Figure 9 CPP Main Deck

Figure 10 CPP Production Deck

Figure 11 CPP Mezzanine Deck

4.1.8 TANKER An oil tanker or known as petroleum tanker is a merchant ship that designed for the bulk transport of oil. Crude tankers and product tankers are two basic types of oil tanker. Crude tankers can move large quantities of unrefined crude oil from its point of extraction to refineries while product tankers are designed to move refined products from refineries to points near consuming markets. In Champion-7 field, the tanker that will be used is product tanker that classified as general purpose tanker. Product tanker can carry up to 185,000 barrels of crude oil. One unit of product tanker will be used in this project and this tanker will transport crude oil to crude oil terminal once per month.

4.1.9 SERIA CRUDE OIL TERMINAL (SCOT) Seria Crude Oil Terminal (SCOT) is functioning as to receive, collect, treat, store and export the crude oil produced from Champion-7 field before distributed to consumers. The storage capacity at the terminal is approximately half a million cubic meters. There are a few crude oil treatments that occur at SCOT such as dehydration, and oil refining. Dehydration process is the removal of water or water vapor from crude oil, by separating the oil from the water and the objectives of this process are to remove free water from the oil and also to break the oil emulsions to reduce the remaining emulsified water in the oil. Oil refining process is a process where crude oil processed and refined into more useful products such as gasoline, diesel fuel, kerosene and etc.. The primary end-products produced in oil refining may be grouped into four categories which are light distillates, middle distillates, heavy distillates and others.

4.2

SCENARIO 2: SATELLITE PLATFORM TO FPSO AND TO COT VIA

TANKER

Satellite Platform

FPSO

Tanker

COT

For Scenario 2, the transportation crude oil is from the satellite platform, to a Floating, Production, Storage and Offloading (FPSO), then to Crude Oil Terminal (COT) via tanker. For Scenario 2, we decided to use three satellite platform (SP), one FPSO, and one tanker once in a months. Based on the Champion 7 Field, the application of FPSO is practically possible although the depth seems to be considered as shallow environment. This is because FPSO are particularly effective at any water depth. The main advantage of the FPSO is its ability to operate without the need for a specific export infrastructure. It also can often be lease instead of bought, hence making very small fields economic. The cost for a FPSO vessel is cheap especially the one that is converted from an existing tanker.

4.2.1 FLOATING, PRODUCTION, STORAGE AND OFFLOADING (FPSO) A Floating, Production, Storage and Offloading (FPSO) is a floating vessel used by the offshore oil and gas industry for the production and processing of hydrocarbons, and for the storage of oil. A FPSO vessel is used to receive life crude oil or partly life for further stabilization or separation. The stabilized crude will be stored in the storage tank before it is received by a tanker for export. The transfer process of the stabilized crude oil from the FPSO to the tanker is called as offload which can be achieved by the facilities on board the FPSO. The major process system on FPSO are as below : i)

Production manifold

ii)

Crude oil separation and treatment

iii)

Crude oil stabilization

iv)

Crude oil transport, storage and offloading

v)

Produced water (treatment and stripping)

vi)

Lift gas/ Kick off gas compression

vii)

Gas dehydration

viii)

Fuel gas associated systems

ix)

H2S removal from gas

x)

Chemical injection

xi)

Flare, vent and blow down

Topside view of FPSO layout drawing

4.2.2 FPSO DESIGN FPSO has several important features in order to operate at its optimum capacity. A typical FPSO has accommodation area, offloading deck, gas compression module, power generation module, separation module, pumping system, mooring system and flare system. The description of each area and module are as below : i)

Accommodation area a. Living quarters

: Provide accommodation for offshore personnel and contain the temporary refuge (emergency), control rooms, offices, dining, and recreation lounges.

b. Helideck

: Located on top of the accommodation structure to provide a safe landing area for incoming helicopters.

ii)

Offloading deck

: A place that connecting the oil storage of FPSO to the platform or COT and it is located at the stern part of the vessel that houses the hose reel.

iii)

Gas Treatment Module

: This module consists of gas sweetening, gas compression and gas dehydration which is used to removing common contaminants such as water, carbon dioxide (CO2), and hydrogen sulfide (H2S). Some of this contaminants have economic value and are further processed or sold.

a. Gas Compression Module

: This module consists of gas compressor for gas injection system. Gas compressor are used for gas lift to improve the production, or a fuel for electricity generation.

iv)

Power generation Module : This module consists of two gas turbine generator units which produce 180 M Watt power. Produced gas is used as fuel to generates electricity. As a backup, diesel generator is used which the diesel used for fuel to generate electricity.

v)

Separation module

: This module consists of two of 2-phase separator ; One gas liquid vertical separator and one water-oil horizontal separator, and one of 3-phase horizontal separator.

vi)

Pumping system

: This system consists at least three centrifugal pump in order to provide enough energy during the delivery of crude oil.

vii)

Mooring system

: A mooring system is used for keeping of a ship or floating platform in place in all water depth. It is made up of a mooring line, anchor and also connectors. An anchor on the seabed is connected to a floating structure by using a mooring line.

viii)

Flare system

: Flare system is used to safely burn excess hydrocarbon gases in an environmentally-sound manner which cannot be recovered or recycled. The use of flares is minimized to the extent that is possible. However, flaring can occur during start-up and shut-down of any of our facilities for maintenance, and also during unplanned operational interruptions such as power outages. Generally, flare system is installed for safety purpose.

ix)

Water Treatment Module : Produced water contains contaminants that require removal before proper disposal or reuse. Some of the impurities or substances likely to be found in produced water include oil, naturally occurring radioactive materials (NORM), waxes, greases, sand, scales, H2S, dissolved salts and various metals. This module consists of desander cyclone, deoiler cyclone, gas filtration and nut shell filtration.

x)

Inert Gas Blanketing System: Crude storage tanks as used in a Floating Production Storage Offloading (FPSO) unit require blanketing medium on top of the stored crude oil to replace the

tank atmosphere and prevent air being drawn in and potentially forming explosive mixtures with the hydrocarbon (HC) gas in the tanks on top of the crude. Trading tankers transporting crude traditionally make this blanket by burning fuel oil or diesel in boilers or inert gas generators, and from the exhaust produce so-called inert gas. Most FPSOs have adopted this solution from the trading tanker industry. Boilers or Inert Gas Generators are straight forward in use, and have become the standard for blanketing on trading tankers.

4.2.3 PROCESS DESIGN A)

PFD OF SP

B)

PFD OF FPSO

4.2.4 LAYOUT OF PLATFORM A) SATELLITTE PLATFORM

Figure 12 SP Main Deck

Figure 13 SP Mezzanine Deck

Figure 14 SP Cellar Deck

B) FPSO

Figure 15 Top view of FPSO

4.3

SCENARIO 3 : SATELLITE PLATFORM TO CPP AND TO COT VIA

PIPELINE

Satellite Platform

CPP

Crude Oil Pipeline

COT

For Scenario 3, the crude oil is being produced from three satellite platform and being transferred to the Central Processing Platform (CPP) whereby the Central Processing Platform (CPP) involved be functioning and using for processing the hydrocarbon fluid which is coming through the riser from the wellhead/satellite platforms for further stabilization or separation. The stabilized crude oil then being transferred to the Seria Crude Oil Terminal through the 80 km subsea pipeline for further oil treatment and stabilization before being sell to the consumer.

4.3.1 CRUDE OIL PIPELINE In Champion-7 field, we decided to construct the pipeline network with 8.5 of outside diameter. All the design, fabrication, installation, testing and safety aspect of operation and maintenance of the pipeline will based on American National Standard Institution for Liquid Petroleum Transportation Piping System NASI/ASME B31.4. 4.3.2 PROCESS DESIGN A)

PFD OF CPP

B)

PFD OF SP

4.3.3 LAYOUT OF PLATFORM A) SATELLITTE PLATFORM

Figure 16 SP Main Deck

Figure 17 SP Mezzanine Deck

Figure 18 SP Cellar Deck

B) CENTRAL PROCESSING PLATFORM

Figure 19 CPP Main Deck

Figure 20 CPP Production Deck

Figure 21 CPP Mezzanine Deck

CHAPTER 5 : ECONOMIC Oil and gas economics has a vital role to play in the oil and gas industry and it lies at the heart of all decision making. Various techniques have evolved over time in determining and calculating economic inputs, evaluating investments, quantifying risk and generating feasible portfolios. Therefore, this development plan is a vital aspect in evaluating this C-7-Rx 2.80 reservoir whether it is profitable enough to be developed within the project life. In this section, the economic evaluation is done for three different options in order to determine which one is the best to give the most profit. Champion-7 field have OOIP of 300 MMstb and this economic evaluation will only focusing on oil development since the gas recovered is used for gas injection scheme to increase the recovery. There are a few assumptions that we made for this development. They are: i.

Oil Price in April 2017 = US $52.23

ii.

Exchange Rate = MYR 4.27 to US$ 1.00

Initially, we came up with three scenarios, Scenario 1, Scenario 2 and Scenario 3. After some evaluation, we have decided to proceed with Scenario 1 based on a few considerations. Firstly, based on the CAPEX evaluation, Scenario 1 came up with the lowest cost and could provide the maximum recovery. The comparison between CAPEX and OPEX of these scenarios is shown in Table. In terms of technical consideration, Scenario 1 comprises of one CPP, three WHP, one gas injection well, two water injection wells and an export tanker to export the production to Seria COT. The summary for all the scenarios is shown in Table 2. Jacket platform is used in Scenario 1. The advantages of using this jacket platform are it can be mobilized, have high stability when elevated, and as well as low cost and efficient. This type of platform is suitable for shallow water depth ranging from 90 m and up to 500 m. For the transportation of the production, we use an export tanker to export the product to the Seria COT. The advantage of using this export tanker instead of pipeline is that this tanker cost is much lower than pipeline cost. This can be seen in Scenario 3, which a 100 km –long pipeline is used to export the products to SCOT. The total CAPEX for Scenario 3 increases slightly due to the pipeline cost. In conclusion, Scenario 1 is selected as the best most economical scenario since it has the lowest CAPEX and affordable OPEX.

5.1 SUMMARY FOR SCENARIO 1, SCENARIO 2 AND SCENARIO 3

Unit/ Amount Items Scenario 1

Scenario 2

Scenario 3

1

-

1

3

3

3

-

1

-

Export Tanker

1

1

-

Oil Pipelines

-

-

100 km

Main facilities Central Processing Platform (CPP) Satellite Platform (SP) Floating, Processing, Storage & Offloading (FPSO)

Production and Operation

Production Wells

20 wells

20 wells

20 wells

Injection Wells

3 wells

3 wells

3 wells

Table 2: Summary for Scenario 1, Scenario 2, and Scenario 3.

5.2 CAPEX: SCENARIO 1 CAPEX 1: Main Facilities Cost/ Unit

Items

Unit

($USD)

Total Cost

Total Cost

($USD)

($USD Million)

CPP

65,000,000.00

1

65,000,000.00

65

SP

25,000,000.00

3

75,000,000.00

75

Export Tanker

43,000,000

1

43,000,000.00

43

4,000,000.00

3

12,000,000.00

12

195,000,000.00

195

Injection wellhead

Total

CAPEX 2: Production Facilities

Items

Cost/ Unit ($USD)

Total Cost ($USD)

Production facilities

70% of Drilling Cost

70,000,000.00

Total Cost ($USD Million) 70

CAPEX 3: Drilling Items Vertical Production Well Deviated Production Well

Cost/ Unit ($USD)

Unit

Total Cost

Total Cost

($USD)

($USD Million)

4,000,000.00

12

48,000,000.00

48

5,000,000.00

8

40,000,000.00

40

88,000,000.00

88

Total

Total CAPEX

$US 353,000,000.00

5.3 OPEX: SCENARIO 1

OPEX CALCULATION

DESCRIPTION

EXPENSES (US$ MILLION)

70% X Total Capex of Well Cost Production facility

= 70%X 100,000,000.00 = 70,000,000.00 Top side + Jacket

Sturucture/ jacket

For structure OPEX is 1% from total CAPEX = 10% X 353, 000,000.00 = 35,300,000.00 For well tangible OPEX is 10% from total

Well tangible

CAPEX = 10% X 353, 000,000.00 = 35,300,000.00 For compressors OPEX is 9% from total

Compressors

CAPEX = 9% X 353, 000,000.00 = 31,770,000.00

Total OPEX

US$ 172,370,000.00

5.4 CAPEX: SCENARIO 2 CAPEX 1: Main Facilities Cost/ Unit

Items

Unit

($USD)

Total Cost

Total Cost

($USD)

($USD Million)

FPSO

290,000,000.00

1

290,000,000.00

290

SP

25,000,000.00

3

75,000,000.00

75

Export Tanker

43,000,000.00

1

43,000,000.00

43

4,000,000.00

3

12,000,000.00

12

420,000,000.00

420

Injection wellhead

Total

CAPEX 2: Production Facilities

Items

Cost/ Unit ($USD)

Total Cost ($USD)

Production facilities

70% of Drilling Cost

70,000,000.00

Total Cost (US$ Million) 70

CAPEX 3: Drilling Items Vertical Production Well Deviated Production Well

Total Cost

Total Cost

(US$)

($USD Million)

12

48,000,000.00

48

8

40,000,000.00

40

88,000,000.00

88

Cost/ Unit (US$)

Unit

4,000,000.00

5,000,000.00

Total

Total CAPEX

$US 578,000,000.00

5.5 OPEX: SCENARIO 2

OPEX CALCULATION

DESCRIPTION

EXPENSES ($USD MILLION)

70% X Total CAPEX of Well Cost Production facility

=70% X 100,000,000.00 =70,000,000.00 Top side + Jacket

Sturucture/ jacket

For structure OPEX is 1% from total CAPEX = 10% X 578,000,000.00 = 57,800,000.00 For well tangible OPEX is 10% from total

Well tangible

CAPEX = 10% X 578,000,000.00 = 57,800,000.00 For compressors OPEX is 9% from total

Compressors

CAPEX = 9% X 578,000,000.00 = 52,020,000

Total OPEX

US$ 237,620,000.00

5.6 CAPEX: SCENARIO 3 CAPEX 1: Main Facilities Cost/ Unit

Items

Unit

($USD)

Total Cost

Total Cost

($USD)

($USD Million)

CPP

65,000,000.00

1

65,000,000.00

65

SP

25,000,000.00

3

25,000,000.00

25

129,090,000

100 km

129,090,000.00

129.09

4,000,00.00

3

12,000,000.00

12

231,090,000.00

231.09

8.5” Oil Pipelines Injection wellhead

Total

CAPEX 2: Production Facilities

Items

Cost/ Unit ($USD)

Total Cost ($USD)

Production facilities

70% of Drilling Cost

100,000,000.00

Total Cost ($USD Million) 70,000,000.00

CAPEX 3: Drilling Items Vertical Production Well Deviated Production Well

Cost/ Unit ($USD)

Unit

Total Cost

Total Cost

($USD)

($USD Million)

4,000,000.00

12

48,000,000.00

48

5,000,000.00

8

40,000,000.00

40

88,000,000.00

88

Total

Total CAPEX

$US 389,090,000.00

5.7 OPEX: SCENARIO 3

OPEX CALCULATION

DESCRIPTION

EXPENSES ($USD MILLION)

70% X Total Capex of Well Cost Production facility

= 70% X 100,000,000.00 = 70,000,000.00 Top side + Jacket

Sturucture/ jacket

For structure OPEX is 1% from total CAPEX = 1% X 389,090,000.00 = 3,890,900.00 For pipeline OPEX is 1% from total CAPEX

Pipeline

= 1% X 389,090,000.00 = 3,890,900.00 For well tangible OPEX is 10% from total

Well tangible

CAPEX = 10% X 389,090,000.00 = 38,909,000.00 For compressors OPEX is 9% from total

Compressors

CAPEX = 9% X 389,090,000.00 = 35,018,100.00

Total OPEX

US$ 151,708,900.00

5.8 COMPARISON OF CAPEX AND OPEX

Expenditure (US$ Million)

Scenario 1

Scenario 2

Scenario 3

CAPEX

353

578

389.09

OPEX

172.37

237.62

151.7089

Total

525.37

815.62

540.7989

Table X: Comparison of CAPEX and OPEX for all three scenarios.

5.9 OPEX PLANNED MAINTENANCE - GENERAL

No. Planned Inspection

Platforms

Total (000)

& Maintenance

CPP 1. 2

Key Rotating Equipment GTC Rotating Equipment Others

WHP-1

WHP-2

WHP-3

0

0

0

3240

81

81

81

3483

1,091,800

1,091,800

3

Static Equipment

1240

292

292

292

2116

4

Electrical

3780

1725

1725

1725

8955

5

Pipeline & Riser

178945

6

Structural

4200

515

515

515

5745

7

Piping

5220

765

765

765

7515

8

Instruments

12150

1620

1620

1620

17010

9

Telecommunication 45900

1350

1350

1350

49950

10

6175

1760

1760

1760

11455

11

Safety & Emergency Response Equipment Power Generation

290385

0

0

0

290385

12

Lifting

1350

135

135

135

1755

13

HVAC

540

135

135

135

945

1,644,925

8378

8378

8378

1,670,059

178945

1,670,059,000.00

CHAPTER 6 : HEALTH, SAFETY AND ENVIRONMENT Oil and gas activities can be divided into three main sectors which are upstream, midstream and downstream. The upstream stage of the production process involves searching for and extracting hydrocarbon. The upstream companies identify oil and natural gas deposits and engage in the extraction of these resources from underground. These firms are often called exploration and production companies. Downstream activities involve processing of hydrocarbon before being distributed to consumer or being commercialize. Midstream operations link the upstream and downstream entities. Midstream operations mostly include resource transportation and storage, such as pipelines and gathering systems. All sectors of oil and gas activities will produce a certain amount of waste that is hazardous and harmful to the health, safety and environment. Examples of wastes are as follows: 1. Well Drilling and Completion Stage Wastes Produced: 

Drilling Fluids (drilling muds)



Cuttings



Produced Water

2. Well Stimulation Stage (hydraulic fracturing) Wastes Produced: 

Fracturing Fluid Returns



Produced Water

3. Well Production Stage Wastes Produced: 

Produced Water

Some of the activities also involve burning and emission of toxic and flammable gas that may increase the risk of fire and explosion. Therefore, DOE regulation and NPFA are needed to controlled the amount of wastes and reduce the potential of unwanted events. DOE is known as Department of Energy. The Energy Department supports research and policy options to increase our domestic supply of oil while ensuring environmentally sustainable supplies domestically and abroad, and is investing in research, technology and processes to make oil drilling cleaner and more efficient including enhanced oil recovery and improved offshore drilling practices. The National Fire Protection Association (NFPA) is a United States trade association, albeit with some international members, that creates and maintains private, copyrighted standards and codes for usage and adoption by local governments. This includes publications from model building codes to the many on equipment utilized by fire fighters while engaging in hazardous material response, rescue response, and some fire fighting. The NFPA was formed in 1896 by a group of insurance firms with the stated purpose of standardizing the new and burgeoning market of fire sprinkler systems. The scope of the NFPA's influence grew from sprinklers and fire extinguishers to include building electrical systems (another new technology), and then into almost all aspects of building design and construction. NFPA is responsible for 380 codes and standards that are designed to minimize the risk and effects of fire by establishing criteria for building, processing, design, service, and installation in the United States, as well as many other countries. Examples of NPFA codes that widely used are: 

NFPA 54, National Fuel Gas Code: The safety benchmark for fuel gas installations.



NFPA 85: Boiler and Combustion Systems Hazards Code.



NFPA 101, Life Safety Code: Establishes minimum requirements for new and existing buildings to protect building occupants from fire, smoke, and toxic fumes.

Safety features for our project can be divided into physical feature and process feature. Physical feature and process feature includes:

Physical Feature

Process Feature



Safety route.



Alarm.



Escape plan.



Relief system.



Assembly point.



Cooling system.



Personal Protection Equipment



Contaminant removal.



Emergency rescue boat.



Safety jacket.



Fire suppression.



Position of living quarter.



Position of flaring and venting.



Equipment manual.

1. Safety route. Safety route is to provide the personnel that work on the platform the right pathway in everyday walking to do their work section. This route is important to avoid the personnel from dangerous equipment or process on every deck. The personnel need to follow this route to reduce potential risk of safety. 2. Escape plan. Each deck in every platform required escape plan. Escape plan shows the pathway needed when there is fire, explosion or any emergency event. This escape plan will provide personnel to the assembly point during emergency. Example of escape plan is:

3. Assembly point. Assembly point is an area where the personnel will gather during emergency. Assembly point must be safe enough and must be not affected during emergency. 4. Personnel Protection Equipment. Personnel protection equipment must be provided to every personnel and act as the last line of defensive system. Personnel protection equipment includes safety helmets, boots, goggles, gloves and ear protection. This will reduce the potential of injured and life loss.

5. Emergency Rescue Boat. Every platform must be provided with emergency rescue boat. Emergency rescue boat will helps the personnel to escape from platform during emergency. Amount of emergency rescue boat must be according to the number of personnel. Extra emergency rescue boats also needed in order to support if there is any unwanted incident. Emergency rescue boats must be placed around the platform.

6. Safety Jacket. Safety jacket was needed to support the safety boats. Safety jacket will the reduce amount of live loss during emergency. Amount of safety jacket is depends on the number of personnel on board.

7. Fire Suppression. The objective of fire suppression systems is to provide cooling, to control fire and to provide extinguishment of the fire incident. Some methods of fire suppression are Portable Fire Extinguishers, Sprinkler System, Water Deluge System, Water Spray System, Water Flooding, Steam Smothering and Water Curtains. Portable fire extinguisher is the common method to be used. Portable extinguishers are classified by expected application on a specific type of fire (A, B, C, or D) and the expected area of suppression. The four types of fires are grouped according to the type of material that is burning. For instance, Class A fires include those in which ordinary combustibles such as wood, cloth, and paper are burning. CIass B fires are those in which flammable liquids, oils, and grease are burning. Class C fires are those involving live electrical equipment. Class D fires involve combustible metals such as magnesium, potassium, and sodium.

Sprinkler systems commonly provided to indoor occupancies, such as warehouses, offices, etc. Considered essentially 100% effective for fire suppression if properly maintained and the hazard has not changed since the original design. Activated by the heat of the fire melting a tension loaded cap at the sprinkler head. Cap melts or falls away releasing water from the pipe distribution network. Thus they do not activate until a fire condition is absolutely real.

Water Deluge System activated by automatic means. Most systems provided at petroleum facilities are typically activated by heat detection. Water flooding is the principle to inject water into the interior of a storage tank for the purposes of preventing flammable or combustible liquids from being released from a leakage point or to extinguish a fire. The principle involves fill a vessel or tank so that the lighter density hydrocarbon fluids float on the water and only water is released from the container.

Steam Smothering are typically limited to fires that might occur as a result of a tube leak in a furnace or heater. The steam is most effective in smothering fires when they are located in relatively small confined areas. Steam extinguishes fire by the exclusion of free air and the reduction of available oxygen content to the immediate area, similar to other gaseous suppression agents

8. Position of living quarter. Living quarter must be placed farther from process that has high potential of fire and explosion risk. This is because when there is fire or explosion, personnel will have enough time to escape.

9. Position of flaring and venting. Flaring and venting process must be position far from the process platform (a few metres outside the platform). This will reduce the potential risk of fire and explosion.

10. Equipment manual. Every equipment on the platform must be provided with updated manual. Every personnel that in charged to work with equipment need to read the manual carefully before starts to operate the equipment. This will reduce the risk of personnel with dangerous equipment that will cause injuries or any emergency

11. Alarm. Every equipment especially pressurized vessel must be fitted with alarm. Alarm is use to alert personnel if there is any undesired condition on the equipment. The personnel than can take a corrective action to prevent any incidents from happen. 12. Relief system. Relief system is very important to the pressurized vessel. It is used to prevent the vessel from overpressure by venting a portion of vessel content. 13. Cooling System. Plants boil water to create steam, which then spins turbines to generate electricity. The heat used to boil water can come from burning of a fuel, from nuclear reactions, or directly from the sun or geothermal heat sources underground. Once steam has passed through a turbine, it must be cooled back into water before it can be reused to produce more electricity. Colder water cools the steam more effectively and allows more efficient electricity generation. 14. Contaminant Removal. Hydrocarbon production in oil and gas activities contains a lot of contaminant such as water, sulphur, carbon dioxide, dissolved salts and others. Contaminant removal process was highly needed on oil and gas industry in order to reduce many types of circumstances such as cavitation, corrosion, erosion and any equipment failures. Examples of contaminant removal process are hydrodesulfurization, dehydration, sweetening process, deaeration and others.

CHAPTER 7 : CONCLUSION Based on the feasibilities study, all the scenarios are acceptable. However, in order to determine the best option to run the project, facilities management is crucial in ensuring the profitability and success of the project. The economic evaluation should be done properly to ensure maximum production with maximum of reduction of cost incurred. From the study, we have decided the best option for Champion-7 field is Scenario 1. This is shown in Table 3.

Scenario 1 

1 unit Central Processing Platform (CPP)

Facilities Requirements

Drilling Requirements



3 units Satellite Platform (SP)



1 unit Export Tanker



2 units Injection Platform



20 Production Wells



1 Gas Injection Well



2 Water Injection Wells

Period of Production

27 years

Plateau Rate

14.6 MMstb/yr Table 3: Summary of Scenario 1.

For Scenario 1, the CAPEX value is US$ 353,000,000.00 while OPEX is US$ 172,000,000.00 which is the lowest and affordable among all the three scenarios. Therefore, Scenario 1 is selected as the most economical scenario.

REFERENCES 1. Shepherd, M., 2009, Well patterns, in M. Shepherd, Oil field production geology: AAPG Memoir 91, p. 239-240. DOI:10.1306/13161216M913372 2. http://www.drillingformulas.com/casing-size-selection-how-to-select-casing-size-tomatch-the-drilling-and-completion-goal/ 3. Crude Oil Processing on Offshore Facilities, http://www.pipingengineering.com/crude-oil-processing-offshore-facilities.html# 4. Central Processing Platform, http://www.thepiping.com/2015/08/central-processingplatforms-cpp.html 5. Crude Oil Dehydration and Desalting, http://www.gemwater.it/?q=fr/node/27 6. Hydrocarbon Blanketing System for FPSO Vessels, http://www.argoengineering.com/wp-content/uploads/2015/01/HydrocarbonGas Blanketing.pdf 7. 2006, Matthew Childs & Anthony Willem Sipkema, Hydrocarbon Gas Storage Tank Blanketing for FPSOs to Eliminate VOC Emissions, https://www.onepetro.org/conference-paper/SPE-98763-MS 8. 1975, A. P. Szilas, Production And Transport Of Oil And Gas, https://books.google.com.my/books?id=pw_uPWS7zQ4C&pg=PA11&dq=oil+and+g as+transportation+cost+model&hl=en&sa=X&ved=0ahUKEwiA6ZjA8MzUAhVFp4 8KHZ0eDRo4ChDoAQhJMAg#v=onepage&q=oil%20and%20gas%20transportation %20cost%20model&f=false 9. 2012, Jacket, https://www.2b1stconsulting.com/jacket/ 10. https://en.wikipedia.org/wiki/Oil_tanker 11. https://en.wikipedia.org/wiki/Pipeline_transport

APPENDICES OPEX : Scenario 1

1. Rotating Equipment Gas Turbine Compressor Equipment

Task

GTC Fuel Consumptio n TOTAL

Y14

Y5

Y6

Y7

CPP Y9

Y8

Inspection and changeout of Dry Gas Seal (6 yrs cycle)

12800

Major overhaul (6 yrs cycle)

44800

Gas compressor

Gas turbine

Y4

Hot section Changeout (6 yrs cycle) Major overhaul (6 yrs cycle) Inspection, Maintenance Provision for call-out Fuel consumption for 30 yrs

Y15

Y16

Y17

Y10

Y11

Y12

Y13

12000 24000 240

240

240

240

240

240

240

240

240

240

2000

2000

2000

2000

2000

2000

2000

2000

2000

2000

2240

2240

2240

2240

2240

59840

2240

2240

2240

2240

Y18

Y19

CPP Y20 Y21

Y22

Y23

Y24

Y25

Y26

Y27

12800

12800

12800

44800

44800

44800

12000

12000

12000

24000

24000

24000

240

240

240

240

240

240

240

240

240

240

240

240

240

240

2000

2000

2000

2000

2000

2000

2000

2000

2000

2000

2000

2000

2000

2000

2240

59840

59840

2240

59840

2240

2240

2240

2240

2240

59840

2240

2240

2240

Y28

Y29

CPP Y30 51,200

179,200 48,000 96,000 240

240

240

6480

2000

2000

2000

54,000 655,920

2240

2240

2240

1,091,800

2. Rotating Equipment – Others Equipment Rotating equipmentPumps, air compressor, blowers, etc.

Task Routine maintenance Air compressorAir-End Changeout

TOTAL

CPP Y15 40 80 120

Y16 40 80 120

CPP Y29 40 80 120

Y30 40 80 120

Y17 40 80 120

Y18 40 80 120

CPP Y4 40

Y5 40

Y6 40

Y7 40

Y8 40

Y9 40

Y10 40

Y11 40

Y12 40

Y13 40

Y14 40

80

80

80

80

80

80

80

80

80

80

80

120

120

120

120

120

120

120

120

120

120

120

Y19 40 80 120

Y20 40 80 120

Y21 40 80 120

Y22 40 80 120

Y23 40 80 120

Y24 40 80 120

Y25 40 80 120

Y26 40 80 120

Y27 40 80 120

Y28 40 80 120

1080 2160 3240

Equipment

Task

Rotating equipmentPumps. TOTAL

Routine maintenance

WHP-1 Y15 Y16 3 3 3 3

Y17 3 3

WHP-1 Y29 Y30 3 3 3 3

81 81

Y18 3 3

WHP-1 Y4 Y5 3 3

Y6 3

Y7 3

Y8 3

Y9 3

Y10 3

Y11 3

Y12 3

Y13 3

Y14 3

3

3

3

3

3

3

3

3

3

3

Y25 3 3

Y26 3 3

Y27 3 3

Y28 3 3

Y19 3 3

3

Y20 3 3

Y21 3 3

Y22 3 3

Y23 3 3

Assume WHP-1 = WHP-2 = WHP-3, therefore; Total = 81 X 3 = 243

Y24 3 3

3. Static Equipment Equipment Static equipmentPressure Vessels, Heat Exchangers, Tanks, Filters, PSV, etc TOTAL

CPP Y15 5 40 45

Y16 5 40 45

CPP Y29 5 40 45

Y30 5 40 45

Task Inspection

CPP Y4 5

Y5 5

Y6 5

Y7 5

Y8 10

Y9 5

Y10 5

Y11 5

Y12 5

Y13 10

Y14 5

PSV Testing

40

40

40

40

40

40

40

40

40

40

40

45

45

45

45

50

45

45

45

45

50

45

Y19 5 40 45

Y20 5 40 45

Y17 5 40 45

Y21 5 40 45

Y22 5 40 45

Y23 10 40 50

Y24 5 40 45

Y25 5 40 45

Y26 5 40 45

Y27 5 40 45

Y28 10 40 50

160 1080 1240

Equipment

Task

Static equipmentPressure Vessels, Heat Exchangers, Tanks, Filters, PSV, etc TOTAL

WHP-1 Y15 Y16 3 3 10 4 13 7

Y18 10 40 50

Inspection

WHP-1 Y4 Y5 3 3

Y6 3

Y7 3

Y8 8

Y9 3

Y10 3

Y11 3

Y12 3

Y13 8

Y14 3

PSV Testing

4

10

4

10

4

10

4

10

4

10

4

7

13

7

13

12

13

7

13

7

18

7

Y19 3 10 13

Y20 3 4 7

Y17 3 10 13

Y18 8 4 12

Y21 3 10 13

Y22 3 4 7

Y23 8 10 18

Y24 3 4 7

Y25 3 10 13

Y26 3 4 7

Y27 3 10 13

Y28 8 4 12

WHP-1 Y29 3 10 13

Y30 3 4 7

106 186 292

Assume WHP-1 = WHP-2 = WHP-3, therefore; Total = 292 X 3 = 876

4. Electrical Equipment Electrical equipmentSwitchgear, Transformer , SB, DB, UPS, cables, cable glands and etc. TOTAL

CPP Y15 60 60 20 140

Y16 60 0 200 260

CPP Y29 60 0 20 80

Y30 60 0 20 80

Equipment Electrical equipmentSwitchgear, Transformer , SB, DB, UPS, cables, cable glands and etc. TOTAL

Task

CPP Y4 60

Y5 60

Y6 60

Y7 60

Y8 60

Y9 60

Y10 60

Y11 60

Y12 60

Y13 60

Y14 60

Battery Bank Replacement

0

0

0

60

0

0

0

60

0

0

0

Protection Relays/ Calibration

200

20

20

20

200

20

20

20

200

20

20

260

80

80

140

260

80

80

140

260

80

80

Internal Inspection

Y17 60 0 20 80

Y18 60 0 20 80

Y19 60 60 20 140

Y20 60 0 200 260

Y21 60 0 20 80

Y22 60 0 20 80

Y23 60 60 20 140

Y24 60 0 200 260

Y25 60 0 20 80

Y26 60 0 20 80

Y27 60 60 20 140

Y28 60 0 200 269

1620 360 1800 3780

Task

WHP-1 Y4 Y5 10 10

Y6 10

Y7 10

Y8 10

Y9 10

Y10 10

Y11 10

Y12 10

Y13 10

Y14 10

Battery Bank Replacement

0

0

0

15

0

0

0

15

0

0

0

Protection Relays/ Calibration

50

5

5

5

200

5

5

5

200

20

5

60

15

15

30

210

15

15

30

210

30

15

Internal Inspection

WHP-1 Y15 Y16 10 10 15 0 5 5 30 15 WHP-1 Y29 10 0 200 210

Y30 10 0 5 15

Y17 10 0 200 210

Y18 10 0 5 15

Y19 10 15 5 30

Y20 10 0 5 15

Y21 10 0 200 210

Y22 10 0 5 15

Y23 10 15 5 30

Y24 10 0 5 15

Y25 10 0 200 210

Y26 10 0 5 15

Y27 10 15 5 30

Y28 10 0 5 15

270 90 1365 1725

Assume WHP-1 = WHP-2 = WHP-3, therefore; Total = 1725 X 3 = 5175 5. Pipeline and Riser Equipm ent

Task

Riser

Pipeline

TOTAL

Pipelines - All Facilities Y4

Y5

Y6

Y7

Y8

Y9

Y10

Y11

Y12

Y13

Y14

1-yearly Visual Inspections for Risers - above water 5-yearly Close-up Inspection for Risers - above water 5-yearly Undewater Inspection for Risers 5-yearly Intelligent Pigging 3-yearly Side Scan Sonar survey 5-yearly ROV surveys

35

35

35

35

35

35

35

35

35

35

35

0

0

0

250

0

0

0

250

0

0

0

0

0

0

3500

0

0

0

3500

0

0

0

0

0

0

20000

0

0

0

20000

0

0

0

0

0

500

0

0

500

0

0

500

0

0

0

0

0

3000

0

0

0

3000

0

0

0

Yearly Internal Corrosion Monitoring Routine Maintenance Yearly Inspection of Launchers/Receivers

200

200

200

200

200

200

200

200

200

200

200

50

50

50

50

50

50

50

50

50

50

50

250

250

250

250

250

250

250

250

250

250

250

535

535

103 5

27285

535

103 5

535

27285

103 5

535

535

Pipelines - All Facilities Y15

Y16

Y17

Y18

Y19

Y20

Y21

Y22

Y23

Y24

Y25

Y26

Y27

Y28

Y29

Y30

35

35

35

35

35

35

35

35

35

35

35

35

35

35

35

35

945

0

0

0

250

0

0

0

250

0

0

0

250

0

0

0

250

1500

0

0

0

3500

0

0

0

3500

0

0

0

3500

0

0

0

3500

21000

0

0

0

2000 0

0

0

0

20000

0

0

0

20000

0

0

0

20000

12000 0

0

0

500

0

0

500

0

0

500

0

0

500

0

0

500

0

4000

0

0

0

3000

0

0

0

3000

0

0

0

3000

0

0

0

3000

18000

200

200

200

200

200

200

200

200

200

200

200

200

200

200

200

200

5400

50

50

50

50

50

50

50

50

50

50

50

50

50

50

50

50

1350

250

250

250

250

250

250

250

250

250

250

250

250

250

250

250

250

6750

535

535

1035

2728 5

535

103 5

535

27285

1035

535

535

27285

103 5

535

1035

27285

17894 5

6. Structural

Equipment

Structural Topside & Underwater

Telecom / Flare Tower

Task

CPP Y4

Y5

Y6

Y7

Y8

Y9

Y10

Y11

Y12

Y13

Y14

Topside Visual Inspections

0

0

0

0

10

0

0

0

0

10

0

Inspections Underwater

0

0

0

0

800

0

0

0

0

800

0

Telecom Tower Inspection

0

0

0

0

10

0

0

0

0

10

0

Flare Tower Inspection Inspection

0

0

0

0

20

0

0

0

0

20

0

0

0

0

0

840

0

0

0

0

840

0

TOTAL

CPP Y Y16 15 0 0

Y 17 0

Y1 8 0

Y19

Y20

Y21

Y22

Y23

Y24

Y25

Y26

Y27

Y28

Y29

Y30

10

0

0

0

0

10

0

0

0

0

10

0

50

0

0

0

0

800

0

0

0

0

800

0

0

0

0

800

0

4000

0

0

0

0

10

0

0

0

0

10

0

0

0

0

10

0

50

0

0

0

0

20

0

0

0

0

20

0

0

0

0

20

0

100

0

0

0

0

840

0

0

0

0

840

0

0

0

0

840

0

4200

Equipment

Task

Structural Topside & Subsea

Topside Visual Inspections Inspections Underwate r

TOTAL

WHP-1 Y4 Y5 0 0

Y6 0

Y7 0

Y8 3

Y9 0

Y10 0

Y11 0

Y12 0

Y13 3

Y14 0

0

0

0

0

100

0

0

0

0

100

0

0

0

0

0

103

0

0

0

0

103

0

WHP-1 Y15

Y16

Y17

Y18

Y19

Y20

Y21

Y22

Y23

Y24

Y25

Y26

Y27

Y28

Y29

Y30

0

0

0

3

0

0

0

0

3

0

0

0

0

3

0

0

15

0

0

0

100

0

0

0

0

100

0

0

0

0

100

0

0

500

0

0

0

103

0

0

0

0

103

0

0

0

0

103

0

0

515

Assume WHP-1 = WHP-2 = WHP-3, therefore; Total = 515 X 3 = 1545

7. Piping Equipment

Structural Topside & Underwater

Task

CPP

3-yearly External Inspection

Y4

Y5

Y6

Y7

Y8

Y9

Y10

Y11

Y12

Y13

Y14

0

0

100

0

0

100

0

0

100

0

0

15 0

150

150

150

150

150

150

150

150

150

150

10

10

10

10

10

10

10

10

10

10

10

16 0

160

260

160

160

260

160

160

260

160

160

(Visual & NDT) 1-Yearly Internal Corrosion Monitoring Routine Maintenance TOTAL

CPP Y Y16 15 10 0 0 15 150 0

Y 17 0 150

Y1 8 10 0 15 0

Y19

Y20

Y21

Y22

Y23

Y24

Y25

Y26

Y27

Y28

Y29

Y30

0

0

100

0

0

100

0

0

100

0

0

100

900

150

150

150

150

150

150

150

150

150

150

150

150

4050

10

10

10

10

10

10

10

10

10

10

10

10

10

10

10

10

270

12 60

160

160

26 0

160

160

260

160

160

260

160

160

260

160

160

260

5220

Equipment

Structural Topside & Underwater

Task

WHP-1

3-yearly External Inspection

Y4

Y5

Y6

Y7

Y8

Y9

Y10

Y11

Y12

Y13

Y14

0

0

10

0

0

10

0

0

10

0

0

20

20

20

20

20

20

20

20

20

20

20

5

5

5

5

5

5

5

5

5

5

5

25

25

35

25

25

35

25

25

35

25

25

(Visual & NDT) 1-Yearly Internal Corrosion Monitoring Routine Maintenance TOTAL

WHP-1 Y 15 10

Y16

Y1 8 10

Y19

Y20

Y21

Y22

Y23

Y24

Y25

Y26

Y27

Y28

Y29

Y30

0

Y 17 0

0

0

10

0

0

10

0

0

10

0

0

10

90

20

20

20

20

20

20

20

20

20

20

20

20

20

20

20

20

540

5

5

5

5

5

5

5

5

5

5

5

5

5

5

5

5

135

35

25

25

35

25

25

35

25

25

35

25

25

35

25

25

35

765

Assume WHP-1 = WHP-2 = WHP-3, therefore; Total = 765 X 3 = 2295

8. Instruments Equipment

Task

Instruments F&G System, DCS Control System, Metering System, Others

CPP

Yearly Inspection F&G

Y4

Y5

Y6

Y7

Y8

Y9

Y10

Y11

Y12

Y13

Y14

100

100

100

100

100

100

100

100

100

100

100

50

50

50

50

50

50

50

50

50

50

50

200

200

200

200

200

200

200

200

200

200

200

100

100

100

100

100

100

100

100

100

100

100

450

450

450

450

450

450

450

450

450

450

450

System Yearly Inspection Process DCS Control System Yearly Inspection Metering/DCS Control Routine Maintenance - Other Instrumentati ons

TOTAL

CPP Y 15 10 0

Y16

Y18

Y19

Y20

Y21

Y22

Y23

Y24

Y25

Y26

Y27

Y28

Y29

Y30

100

Y 17 100

100

100

100

100

100

100

100

100

100

100

100

100

100

2700

50

50

50

50

50

50

50

50

50

50

50

50

50

50

50

50

1350

20 0 10 0 45 0

200

200

200

200

200

200

200

200

200

200

200

200

200

200

200

5400

100

100

100

100

100

100

100

100

100

100

100

100

100

100

2700

450

450

450

450

450

450

450

450

1215 0

450

450

450

450

450

450

100 450

Equipment

Task

Instruments F&G System, DCS Control System, Metering System, Others

WHP-1

Yearly Inspection F&G System Yearly Inspection Process DCS Control System Routine Maintenance - Other Instrumentati ons

TOTAL

Y4

Y5

Y6

Y7

Y8

Y9

Y10

Y11

Y12

Y13

Y14

20

20

20

20

20

20

20

20

20

20

20

15

15

15

15

15

15

15

15

15

15

15

25

25

25

25

25

25

25

25

25

25

60

60

60

60

60

60

60

60

60

60

25

60

WHP-1 Y 15 20

Y16

Y18

Y19

Y20

Y21

Y22

Y23

Y24

Y25

Y26

Y27

Y28

Y29

Y30

20

Y 17 20

20

20

20

20

20

20

20

20

20

20

20

20

20

540

15

15

15

15

15

15

15

15

15

15

15

15

15

15

15

15

405

25

25

25

25

25

25

25

25

25

25

25

25

25

25

25

25

675

60

60

60

60

60

60

60

60

60

60

60

60

60

60

60

60

1620

Assume WHP-1 = WHP-2 = WHP-3, therefore; Total = 1620 X 3 = 4860

9. Telecom Equipment

Task

Telecom Radio, Beacon, Meteorological , CCTV, PAGA & PABX Systems TOTAL

CPP Y4

Y5

Y6

Y7

Y8

Y9

Y10

Y11

Y12

Y13

Y14

Routine Maintenance

100

100

100

100

100

100

100

100

100

30

30

Corrective Maintenance

70

70

70

70

70

70

70

70

70

70

70

170

170

170

170

170

170

170

170

170

170

170

CPP Y15

Y16

Y17

Y18

Y19

Y20

Y21

Y22

Y23

Y24

Y25

Y26

Y27

Y28

Y29

Y30

100

100

100

100

100

100

100

100

100

100

100

100

100

100

100

100

27000

70

70

70

70

70

70

70

70

70

70

70

70

70

70

70

70

18900

170

170

170

170

170

170

170

170

170

170

170

170

170

170

170

170

45900

Equipment

Task

Telecom Radio, Beacon, CCTV & PABX Systems

WHP-1 Y4 Y5

Y6

Y7

Y8

Y9

Y10

Y11

Y12

Y13

Y14

Routine Maintenance

30

30

30

30

30

30

30

30

30

30

30

Corrective Maintenance

20

20

20

20

20

20

20

20

20

20

20

50

50

50

50

50

50

50

50

50

50

50

TOTAL

WHP-1 Y15 Y16

Y17

Y18

Y19

Y20

Y21

Y22

Y23

Y24

Y25

Y26

Y27

Y28

Y29

Y30

30

30

30

30

30

30

30

30

30

30

30

30

30

30

30

30

810

20

20

20

20

20

20

20

20

20

20

20

20

20

20

20

20

540

50

50

50

50

50

50

50

50

50

50

50

50

50

50

50

50

1350

Assume WHP-1 = WHP-2 = WHP-3, therefore; Total = 1350 X 3 = 4050

10. Safety Emergency Response Equipment

Task

Safety & Emergency Response Equipment

Portable Fire Extunguishers Inspection & Testing Routine Maintenance ER Equipment Corrective Maintenance ER Equipment Inflatable Liferaft & Ring Buoy Swing Rope Inspection & Replacement Life Saving Equipment

TOTAL

CPP Y4

Y5

Y6

Y7

Y8

Y9

Y10

Y11

Y12

Y13

Y14

50

50

50

70

70

70

70

70

70

70

70

30

30

30

30

30

30

30

30

30

30

30

50

50

50

80

80

80

80

80

80

80

100

5

5

5

15

15

15

15

15

15

15

15

5

5

5

10

10

10

10

10

10

10

10

5

5

5

20

20

20

20

20

20

20

20

145

145

145

225

225

225

225

225

225

225

245

CPP Y 15 70

Y16

Y18

Y19

Y20

Y21

Y22

Y23

Y24

Y25

Y26

Y27

Y28

Y29

Y30

70

Y 17 70

70

70

70

70

70

70

70

70

70

70

70

70

70

1830

30

30

30

30

30

30

30

30

30

30

30

30

30

30

30

30

810

10 0

100

100

100

100

100

100

100

100

100

100

100

100

100

100

100

2410

15

15

15

15

15

15

15

15

15

15

15

15

15

15

15

15

375

10

10

10

10

10

10

10

10

10

10

10

10

10

10

10

10

255

20

20

20

20

20

20

20

20

20

20

20

20

20

20

20

20

495

245

245

245

245

245

245

245

245

245

245

245

245

245

245

245

6175

24 5

Equipment

Task

Safety & Emergency Response Equipment

Portable Fire Extunguishers Inspection & Testing Routine Maintenance ER Equipment Corrective Maintenance ER Equipment Inflatable Liferaft & Ring Buoy Swing Rope Inspection & Replacement Life Saving Equipment

TOTAL

WHP-1 Y4 Y5

Y6

Y7

Y8

Y9

Y10

Y11

Y12

Y13

Y14

5

5

5

10

10

10

10

10

10

10

10

10

10

10

10

10

10

10

10

10

10

10

15

15

15

20

20

20

20

20

20

20

25

3

3

3

8

8

8

8

8

8

8

8

5

5

5

10

10

10

10

10

10

10

10

2

2

2

2

7

7

7

7

7

7

7

40

40

40

60

65

65

65

65

65

65

70

WHP-1 Y 15 10

Y16

Y18

Y19

Y20

Y21

Y22

Y23

Y24

Y25

Y26

Y27

Y28

Y29

Y30

10

Y 17 10

10

10

10

10

10

10

10

10

10

10

10

10

10

255

10

10

10

10

10

10

10

10

10

10

10

10

10

10

10

10

270

25

25

25

25

25

25

25

25

25

25

25

25

25

25

25

25

610

8

8

8

8

8

8

8

8

8

8

8

8

8

8

8

8

201

10

10

10

10

10

10

10

10

10

10

10

10

10

10

10

10

255

7

7

7

7

7

7

7

7

7

7

7

7

7

7

7

7

169

70

70

70

70

70

70

70

70

70

70

70

70

70

70

70

1760

70

Assume WHP-1 = WHP-2 = WHP-3, therefore; Total = 1350 X 3 = 4050

11. Power Generation Equipment

Task

Gas Turbine Generator 4 Nos

Emergency Diesel Generator

Fuel Consumption

CPP Y4

Y5

Y6

Y7

Y8

Y9

Y10

Y11

Y12

Y13

Y14

Annual PM & CM

150

150

150

150

150

150

150

150

150

150

150

Major Overhaul - 5 yrs cycle

0

0

0

0

2000

0

0

0

2000

0

0

Annual PM & CM

5

5

5

10

10

10

10

10

10

10

10

Major Overhaul - 5 yrs cycle

0

0

0

0

200

0

0

0

200

0

0

155

155

155

160

2360

160

160

160

2360

160

160

Fuel Consumption for 30yrs

TOTAL

CPP Y Y16 15 15 150 0

Y 17 150

Y1 8 15 0

Y19

Y20

Y21

Y22

Y23

Y24

Y25

Y26

Y27

Y28

Y29

Y30

150

150

150

150

150

150

150

150

150

150

150

150

4050

0

200 0

0

0

0

2000

0

0

0

2000

0

0

0

2000

0

0

1200 0

10

10

10

10

10

10

10

10

10

10

10

10

10

10

10

10

255

0

200

0

0

0

200

0

0

0

200

0

0

0

200

0

0

1200

16 0

236 0

160

16 0

160

2360

160

160

160

2360

160

160

160

2360

160

160

2728 80 2903 85

12. Lifting. Equipment

Task

Lifting Equipment Pedestal Crane, Monorail TOTAL

Inspection & PM

CPP Y4 Y5 50 50

Y6 50

Y7 50

Y8 50

Y9 50

Y10 50

Y11 50

Y12 50

Y13 50

Y14 50

50

50

50

50

50

50

50

50

50

50

50

CPP Y15

Y16

Y17

Y18

Y19

Y20

Y21

Y22

Y23

Y24

Y25

Y26

Y27

Y28

Y29

Y30

50

50

50

50

50

50

50

50

50

50

50

50

50

50

50

50

1350

50

50

50

50

50

50

50

50

50

50

50

50

50

50

50

50

1350

Equipment

Task

Lifting Equipment Jib Crane

Routine Maintenan ce

WHP-1 Y4 Y5 5 5

Y6 5

Y7 5

Y8 5

Y9 5

Y10 5

Y11 5

Y12 5

Y13 5

Y14 5

5

5

5

5

5

5

5

5

5

5

5

WHP-1 Y15

Y16

Y17

Y18

Y19

Y20

Y21

Y22

Y23

Y24

Y25

Y26

Y27

Y28

Y29

Y30

5

5

5

5

5

5

5

5

5

5

5

5

5

5

5

5

135

5

5

5

5

5

5

5

5

5

5

5

5

5

5

5

5

135

Assume WHP-1 = WHP-2 = WHP-3, therefore; Total = 135 X 3 = 405

13. HVAC Equipment

Task

HVAC & Fire Dampers

Inspection & PM

TOTAL

CPP Y4 Y5 20 20

Y6 20

Y7 20

Y8 20

Y9 20

Y10 20

Y11 20

Y12 20

Y13 20

Y14 20

20

20

20

20

20

20

20

20

20

20

20

CPP Y15

Y16

Y17

Y18

Y19

Y20

Y21

Y22

Y23

Y24

Y25

Y26

Y27

Y28

Y29

Y30

20

20

20

20

20

20

20

20

20

20

20

20

20

20

20

20

540

20

20

20

20

20

20

20

20

20

20

20

20

20

20

20

20

540

Equipment

Task

HVAC & Fire Dampers

Inspection & PM

WHP-1 Y4 Y5 5 5

Y6 5

Y7 5

Y8 5

Y9 5

Y10 5

Y11 5

Y12 5

Y13 5

Y14 5

5

5

5

5

5

5

5

5

5

5

5

WHP-1 Y15

Y16

Y17

Y18

Y19

Y20

Y21

Y22

Y23

Y24

Y25

Y26

Y27

Y28

Y29

Y30

5

5

5

5

5

5

5

5

5

5

5

5

5

5

5

5

135

5

5

5

5

5

5

5

5

5

5

5

5

5

5

5

5

135

Assume WHP-1 = WHP-2 = WHP-3, therefore; Total = 135 X 3 = 405