Heavy oil Extraction Project

8/22/2019 Heavy oil Extraction Project

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06/12/2012

NAIR, ROHIT CHANDRASEKHARAN | 51231896

SON, CHANG HWAN | 51231722

SURESH KUMAR, TILAK | 51232891

GROUP17 PROJECTPEGASUS


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CAPITAL EXPENDITURE REQUEST

PROJECT DATA

CER Number: 1EPCM2012

Title: Project Pegasus

Cost: USD 123,050,000

Expenditure Flow: USD 60,015,000(1st Year)USD 63,035,000(2nd Year)

Project Category: Pilot Scale

Date: 05/12/2012

Location: Aberdeen

Completion Date: 25/07/2014

Business Team: Penguin Engineering

Business Project: Engineering,Procurement &Construction

Management (EPCM)

SUMMARY PROJECT DESCRIPTION

Project Pegasus is a pilot scale project for recovering the heavy oil from the block 25/11 ofGrane Field. The project shall involve engineering, procurement and construction managementof developing the facilities associated with the project. Statoil has awarded Project Pegasus toPenguin Engineering. Penguin Engineering is an engineering, procurement and constructioncompany operating predominantly with the offshore industry based in North Sea. The companyhas been contracted for developing a pilot scale facility in the view of extracting heavy oil fromGrane field in block 25/11 which is at 180km off Norwegian coast at water depth 127m in North

Sea. Grane field has been developed with 31 production well and 4 injection wells, with aproduction rate of more than 200,000 bbl / day. The pilot facilities shall be tested in the well 36,which is scheduled to be drilled by the Statoil in 2013 such that the well is available for

production of heavy oil using the pilot facilities. Business case had been developed based onevaluation of key factors schedule, feasibility, cost, risk, technology and applicability for heavyoil recovery enhancing.

SUMMARY PROJECT BENEFIT

Internal Rate of Return and Net Present Value have been evaluated for the period of 17 years.

Internal Rate of Return: 22%

Net Present Value: USD 38,113,092

APPROVALS

This project has complied with all the environmental and safety criterias in accordance with thecodes and standards of the company, regulation bodies, and the government policies.

05/12/2012 Issued for Approval Project Team Project Manager CEO

DATE DESCRIPTION PREPARED REVIEWED APPROVED


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CONTENTS

1. BACKGROUND ..................................................................................................................... 5

2. BUSINESS CASE .................................................................................................................... 6

2.1. PROJECT SCOPE ................................................................................................................................................................... 6

2.2. STRATEGIC CONTEXT ........................................................................................................................................................ 6

2.3. COMMERCIAL CASE ............................................................................................................................................................ 6

2.4. OPTIONS CONSIDERED ..................................................................................................................................................... 6

2.5. CAPITAL COST ...................................................................................................................................................................... 6

2.6. HIGH LEVEL PROGRAM MILESTONE ............................................................................................................................ 6

2.7. HIGH LEVEL RISK ................................................................................................................................................................ 7

2.8. HSE 7

2.9. PROJECTS TARGETS ........................................................................................................................................................... 7

2.10. PROJECT RISKS ..................... .................... ..................... ...................... .................... ..................... ..................... ................ 7

2.11. CRITICAL SUCCESS FACTOR:......................................................................................................................................... 7

3. OPTION GENERATIONS AND APPRAISAL .............................................................................. 8

3.1. TECHNOLOGY APPRAISAL AND SELECTION .............................................................................................................. 8

3.1.1. IN-LINE SUBSEA SEPARATION UNIT ......................................................................................................................... 8

3.1.2. SUBSEA SEPARATOR UNIT ........................................................................................................................................... 8

3.1.3. APPRAISAL AND SELECTION ....................................................................................................................................... 9

3.2. FIELD SELECTION ............................................................................................................................................................. 10

3.2.1. SEALION FIELD ROCKHOPER ................................................................................................................................ 10

3.2.2. GRANE FIELD STATOIL ............................................................................................................................................ 10

3.2.3. APPRAISAL AND SELECTION .................................................................................................................................... 11

3.3. OPTION APPRAISAL ........................................................................................................................................................ 13

4. STAKE HOLDERS ................................................................................................................. 14


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5. PROJECT EXECUTION PLAN ................................................................................................ 16

5.1. PROJECT DESCRIPTION ................................................................................................................................................. 16

5.2. PROJECT OBJECTIVES ..................................................................................................................................................... 16

5.3. PROJECT SCOPE ................................................................................................................................................................ 16

5.4. PROCUREMENT STRATEGY .......................................................................................................................................... 16

5.5. SCHEDULING PLAN .......................................................................................................................................................... 16

5.6. ORGANIZATIONAL CHART ............................................................................................................................................ 17

5.7. QUALITY ASSURANCE MANAGEMENT ...................................................................................................................... 17

5.8. HSE MANAGEMENT ......................................................................................................................................................... 17

6. RISK MANAGEMENT STRATEGY ......................................................................................... 18

6.1. RISK IDENTIFICATION ................................................................................................................................................... 18

6.2. RISK ANALYSIS .................................................................................................................................................................. 18

6.3. RISK MITIGATION ............................................................................................................................................................ 19

6.4. RISK REVIEW ..................................................................................................................................................................... 19

7.

PROJECT WORK BREAKDOWN STRUCTURE......................................................................... 20

8. PROJECT SCHEDULE ........................................................................................................... 21

9. ESTIMATED BUDGET .......................................................................................................... 22

10. RISK REGISTER ................................................................................................................. 24

11. REFERENCE ...................................................................................................................... 25


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LIST OF FIGURES

Figure 1: Total World Oil Reserves ..................................................................................................... 5Figure 2: Light Oil Production from North Sea ................................................................................... 5

Figure 3: A Typical Inline Phase Splitter ............................................................................................. 8Figure 4: A Typical Subsea Separator ................................................................................................. 8Figure 5: Sealion Field ....................................................................................................................... 10Figure 6: Grane Field ......................................................................................................................... 11Figure 7: Probability Tree Diagram ................................................................................................... 12Figure 8: Stakeholders Matrix .......................................................................................................... 14Figure 9: Grane Field Development Organizational Chart ................................................................ 17Figure 10: Risk Matrix ....................................................................................................................... 19Figure 11: Mitigated Risk Matrix ...................................................................................................... 19Figure 12: Work Breakdown Structure .............................................................................................. 20

Figure 13: Project Schedule ............................................................................................................... 21Figure 14: Estimated Budget.............................................................................................................. 22

LIST OF TABLES

Table 1: MVDM For In-Line Separation Units ................................................................................... 9Table 2: MVDM For Subsea Separator ............................................................................................... 9Table 3: Sealion Field Information .................................................................................................... 10

Table 4: Grane Field Information ...................................................................................................... 10Table 5: Field Pros & Cons Evaluation ........................................................................................... 11Table 6: Development cost of projects .............................................................................................. 11Table 7: Decision Tree for Selected Options ..................................................................................... 12Table 8: Summary of Technology Evaluation ................................................................................... 13Table 9: Summary of Field Evaluation .............................................................................................. 13Table 10: Stakeholder Analysis ......................................................................................................... 15Table 11: Risk Identification.............................................................................................................. 18Table 12: Risk Probabilities ............................................................................................................... 18Table 13: Risk Impact ........................................................................................................................ 18Table 14: NPV & IRR Calculation .................................................................................................... 23Table 15: Risk Register ...................................................................................................................... 24


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1. BACKGROUNDLight crude oil resources are decreasing throughout the world, especially in North Sea and Gulf ofMexico, which were are developed in the early days. This causes operators to implement enhancedoil recovery techniques to maintain production rates of their respective fields. This has forced theoperators to explore other opportunities. Heavy oil and extra heavy oil constitute for 40% of the

total world oil reserves. But extracting this heavy oil has always been a difficult task. Presentlythermal recovery techniques are being used successfully to recover heavy oil. But using thistechnology has its own disadvantages. Thermal recovery technique is not environmental friendly asit pollutes its surrounding environment and also it is difficult to implement this technology offshore,causing the operators to look for a better technology. The major problem the operators encounterwhile extracting heavy oil is that the viscosity of heavy oil is very high and it doesnt flow as easilyas the light crude oil does. Also the processing and separation of heavy oil is another difficult task.It requires high capacity separators topside, which is less feasible economically.

Figure 1: Total World Oil Reserves

Figure 2: Light Oil Production from North Sea


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2. BUSINESS CASE2.1.PROJECT SCOPEThe scope of our project is to identify the best technology available for recovering the vast reserves

of heavy oil available. It also involves setting up the pilot scale facility at a feasible location to testthe efficiency of the technology being used as quickly as humanly possible.

2.2.STRATEGIC CONTEXTThe global energy demand is on the rise and majority part of this energy demand is expected tocome from fossil fuels. The resources of heavy oil are twice that of conventional light crude oil.Penguin Engineering in tie up with FMC technologies have come with a new and innovativetechnology, which will be implemented to a pilot scale facility to establish the feasibility of heavyoil extraction

2.3.COMMERCIAL CASEThe project has to make use of a new and innovative technology for heavy oil extraction inintegration with an already existing topside facility. The light crude oil resources are gettingdepleted and there is an increase in demand of heavy oil around the world. Using the technology,Penguin engineering expects to increase the oil production rate by 1000 bbl/day.

2.4.OPTIONS CONSIDEREDThe project has considered technological and field options, which were thoroughly evaluated andthe best among them was selected for developing the pilot scale facility.

The field options that were considered are:

Sea Lion Field off the coast of Falkland Islands Grane Field in the Norwegian Continental Shelf.

The technological options that were evaluated are:

In-line Subsea Separation Unit Subsea Separator

After detailed evaluation it was determined that Grane field fits the company strategy best and In-line Subsea separation technology was the best suited for the development of the project.

2.5.CAPITAL COSTThe cost of the project has been estimated to be around USD 88,050,000 with a contingency of afurther 35,000,000.

2.6.HIGH LEVEL PROGRAM MILESTONEKey completion dates should be maintained for achieving complete project in time.

Completion of System Engineering 25/ 04/ 2013 Letter of Award for In-Line Separator 24/ 05/ 2013 Completion of System Integration Test 25/ 04/ 2014 Completion of Installation 04/ 07/ 2014 Hand-over 25/ 07/ 2014


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2.7.HIGH LEVEL RISKThe use of new technology for the recovery of Heavy oil is a critically important aspect of this

project. As the evaluation of the recovery and profits associated with it is highly debatable due tolack of field proven data. The calculations are estimated on based on assumptions that the

technology is highly reliable for the recovery of oil and the facilities commissioned would deliverexpected recovery.

2.8.HSETo provide and maintain safe, healthy working conditions for delivering highly reliable, zero harm,operationally safe engineering solutions.

2.9.PROJECTS TARGETS Set up the pilot scale facility within 20 months of sanctioning project Increase production 1,000 bbl/day Project CAPEX is maximum USD 123.05 New available technologies would be deployed to tackle problems experienced in previous

projects.

2.10. PROJECT RISKS CostLow: The accuracy of estimated costs are low as limited engineering data is available.

This means that the total cost of the project has low percentage accuracy and therefore will bemore susceptible to variation in cost.

Time High: Scope change and problems with technology acquirement and reaching aconclusive agreement among stakeholders. QualityHigh: Subsea project require for high level of quality due to huge cost in work over.

2.11. CRITICAL SUCCESS FACTOR: The entire project to be carried out in environmental friendly manner and shall be a zero harm

work area.

Project execution to be as per the planned project schedule. Quality of the project and reliability of the product & equipments to be of high standards. Facilities to demonstrate a complete operational capability. Increase in the recovery of oil.


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3. OPTION GENERATIONS AND APPRAISAL3.1.TECHNOLOGY APPRAISAL AND SELECTIONVarious technological options were considered and after careful evaluation and analysis twotechnologies were selected. Various decision-making tools are being employed for selecting the

best technology among them.

3.1.1.IN-LINE SUBSEA SEPARATION UNITAn Inline subsea separation unit is considered because of its wide scale applicability and flexibility.It can be easily incorporated into an existing field. It is cost effective. Different in-line units are

being used for the separation of water sand and gas from the oil. This considerably reduces theviscosity and increases the flow rate. Different inline separation units being used are- Inline Desanderit is used for removing the sand from the flow line. Sand removal reduces

the viscosity to a great extent and thus helps in easier flow of hydrocarbons through theflowline.

Inline Phase Splitter- it is used for separation gas from the hydrocarbon mixture. The gas thatis separated is then injected into the reservoir for increasing reservoir pressure and thusincreasing the flow rate. After all the oil has been recovered, all the gas injected can berecovered and then sold.

In-line Electrocoalescer- Separates water from the oil mixture. The oil separated istransported for storage. Separated water is sent for water injection in the well reservoir.

Figure 3: A Typical Inline Phase Splitter

3.1.2.SUBSEA SEPARATOR UNITSubsea separator unit is another technology option that is considered. The main function of thesubsea separator unit is to separate the gas, sand, and water from the oil and pump it up to topsideunit. It is an all in one integrated unit and is a relatively new technology.

Figure 4: A Typical Subsea Separator


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3.1.3.APPRAISAL AND SELECTIONMulti-variable decision-making tool is being employed for finding the best technological option for

project PEGASUS.

Table 1: MVDM For In-Line Separation Units

Attributes Sub attributes Weights(a)

Score (b) Score (b) OverallScore

10 30 50 70 90

Strategic Fit 0.5 60 30

Programme 0.5 X 25

Time 0.5 X 35

Risk 0.1 60 6

Cost 0.2 X 10

Time 0.5 X 35

Quality 0.3 X 15

Cost ofDevelopment

0.1 X 5 5

Benefits 0.3 X 21 21

Total 62

Table 2: MVDM For Subsea Separator

Attributes Sub attributes Weights(a)

Score (b) Score(b)

OverallScore

10 30 50 70 90

Strategic Fit 0.5 50 25Programme 0.5 X 15

Time 0.5 X 35

Risk 0.1 50 5

Cost 0.2 X 14

Time 0.5 X 15

Quality 0.3 X 21

Cost ofDevelopment

0.1 X 3 3

Benefits 0.3 X 21 21

Total 54


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3.2.FIELD SELECTION3.2.1.SEALION FIELD ROCKHOPER

Table 3: Sealion Field Information

Location Off Falkland island coastBlock No. 14/10-2

Water Depth 2700m

Discovered Rockhopper in 2010

Estimated Recovery 355.6 million barrels

Cost for Developing USD 875,000,000

Plateau Oil Production Rate Estimated up to 70,000bbl/d

Peak Oil Production Rate -

Participants Rockhopper (100%)

Figure 5: Sealion Field

3.2.2.GRANE FIELD STATOILTable 4: Grane Field Information

Location 185 Km west of Haugesund

Block No. Block 25/11

Water Depth 350m

Discovered By Hydro in 1991

Estimated Recovery 700 million barrels of oil

Cost for Developing 150 to 200 million

Plateau Oil Production Rate 200,000bbl/d

Peak Oil Production Rate 243,000bbl/d

Participants Stat oil (36.67%) Petoro (28.94%),ExxonMobil Exploration & Production

Norway (28.22%) ConocoPhillipsSkandinavia (6.17%)


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Figure 6: Grane Field

3.2.3.APPRAISAL AND SELECTIONTwo field options were evaluated based on the pros & cons, cost of development and the profits

based recovering the cost of development by the additional recovery of oil using the inlineseparation technology are as shown below.

Table 5: Field Pros & Cons Evaluation

Table 6: Development cost of projects

GRANE FIELD SEALION FIELD

PROs:

Existing topside and subsea facilitiesLower logistic costsAvailability of field data for comparisonApplicability of EOR techniquesScheduleLow CAPEX

PROs:

Unlimited design specifications as it isa relative green field

CONs:

Production loss due to interventionDesign limitations

CONs:

Political tensionTopside and subsea facility needs to be

constructed

No data for establishing the benefit oftechnologyLonger schedulesHigher logistic costHigher CAPEXTechnical limitation due to water depth

Project Development Cost Additional Recovery

Grane Field USD 82,400,000 1,000 bbl/day

Sealion Field USD 882,400,000 1,000 bbl/day


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Table 7: Decision Tree for Selected Options

Project Best Case Base Case Worst Case

Grane Field

Income: (1,100 bbl/day x16 years x 365 x price

per barrel)=US$ 655.2 million

Probability:0.2

Income: (1,000 bbl/day x16 years)=

US$ 595.68 millionProbability:0.6

Income: (900 bbl /day x16 years x 365 x price per

barrel)=US$ 536.11 million

Probability:0.2

Sealion Field


per barrel)=US$ 1,023.82 million

Probability:0.2


per barrel)=US$ 930.75 million

Probability:0.6

Income: (900 bbl/day x25 years x 365 x price per

barrel)=US$ 837.67 million

Probability:0.2

Note: Oil production data for both Field is assumed due to lack of available data. Oil price is

102 USD/bbl available inwww.oil-price.net

Figure 7: Probability Tree Diagram

The figure above shows the probability tree diagram and the comparative studies, which are beingused to determine the best field option for project development shows Grane field as the mostfeasible option among the two. Thus Penguin Engineering is planning to develop its pilot scalefacility at Grane Field.
http://www.oil-price.net/http://www.oil-price.net/http://www.oil-price.net/http://www.oil-price.net/


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3.3.OPTION APPRAISALAfter employing various analysis tools for determining the best technological and field option forsetting up the pilot scale facility, the best among them was selected using the summary ofappraisals.

Table 8: Summary of Technology Evaluation

In-line separation unit Subsea separator unit

Cost 40 million 90 million

Efficiency10-15 % increase in reservoir

output5-10 % increase in reservoir

output

Technological status Newly developed Relatively new technology

Inspection and Maintenance ROV ROV

Flexibility Highly FlexibleRelatively low on flexibility

because of its bulky natureSafety issue No potential safety issue No potential safety issue

Lead time 7 months 12 months

Table 9: Summary of Field Evaluation

Project Attribute Sealion Field Grane Field

Estimated increase oil recovery 1000bbl/d 1000 bbl/d

Estimated cost USD 923,050,000 USD 123,050,000

Estimated schedule 21 months* 21 months

Risk associated

- Political Factor- Reservoir Data YESUNKNOWN NOKNOWN

3rd party involvement Yes Yes

Estimated value $ 930.75 million $ 595.68 million

Benefit to company

- Increase production- Generate profit YesYes YesYes

Does it fit for Companys

strategies Yes Yes

* align with field development schedule in 2016.


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4. STAKE HOLDERSThe important stakeholders who influence the project were identified in the matrix given below.The stakeholders position in the matrix shows the importance and the influence they have in the

project.

Strategy for each group also included. Key player group should be involved with project andmonthly meeting with each party will be held. Shareholders in the project field are categorized withactive consultation group due to their importance in the project. They should be included in theinformation loop and their feedback will be clarified or rectified as much as possible. Projectmanagement team will maintain interest in subcontractors. Their work progress will be monitoredregularly; package lead and inspector will report any commercial / technical issue. Norwegiangovernment and local community will be informed when it is required

Figure 8: Stakeholders Matrix

Maintain Interest1. Umbilical Manufacturer

2. Pipeline Manufacturer3. Installation Vessel Contractor4. Insurance Company

5. Subcontractors

Key Players1. Stat oil2. Penguin Engineering

3. FMC4. Verification AgencyActive Consultations1. Mitchel Thevor2. Conoco Phillips3. Petoro4. Exxon Mobil

Keep Informed1. Norwegian Fisherman

Federation2. Coastguard3. Norwegian Government4. Media/Technical Societies

ImportanceLOW HIGH

HIGH

Impact


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The table below shows what each stakeholder expect from the project and how it is going to beaddressed by PENGUIN Engineering.

Table 10: Stakeholder Analysis

STAKEHOLDER % OWNERSHIP NEED EXPECTATION

Statoil 60% Highly reliabletechnical solutionswith goal zero practicein project execution.

Effective planning andscheduling of projectmanagement.

Commercially viableevaluation of thetechnology for future

project.

Recovery of Heavy Oilefficiently, timely &environmentallyfriendly

Michel Thevor 20% Recovery of Heavy Oilefficiently, timely &environmentallyfriendly

Conoco Philips 10% Recovery of Heavy Oilefficiently, timely &

environmentallyfriendly

Exxon Mobil 10% Recovery of Heavy Oilefficiently, timely &environmentallyfriendly

Penguin Engineering NA Highly reliable andtimely projectexecution.

Complete projectwithin time and budget

FMC NA Dispatch project teamto site

Delivery the product intime

NorwegianGovernment

NA Field developmentplan will be submittedfor approval

Develop the projectwithin regulation

NorwegianEnvironmentalProtection Agency

NA All safety standardswill be adhered to.

No Environmentalpollution

NorwegianFishermens

Federation

NA Related issue(EnvironmentalImpact) will be sharedand discussed

Minimize impact intheir industry

Coastguard NA Required information

(offshore workschedule) will beshared and discussed

Prevent any kind of

offshore accident

Installation Contractor NA Work progress to bemonitored closely

Complete the work intime

Subcontractors NA Work progress to bemonitored closely

Delivery the product intime

Verification Agency NA Any feedback to beclarified

Verify engineeringwork

Insurance Company NA Required information

to be shared

Project information to

be sharedMedia/TechnicalSocieties

NA Required informationto be shared

Project information tobe shared occasionally


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5. PROJECT EXECUTION PLAN5.1.PROJECT DESCRIPTIONThe reserves of untapped heavy oil reserves are huge and our project aims at evaluating the best

possible technique to extract heavy oil using the most advanced technology options available in themarket and to conduct a feasibility study for future expansion of the field. Our project is a pilotscale facility in the Grane field 185km from the city of Haugesund, Norway. The project will beable to demonstrate the benefit of using the proposed technology and also the scope of futureexpansion of a field. For this project an existing topside facility of the contracting company will beused and the subsea technology proposed will be integrated into an already existing field.

5.2.PROJECT OBJECTIVESThe principal objectives of the project team are hiring unproven technology and incorporating intoexisting facilities for enhancing the production in mature fields. Key objectives are addressed as

below.

Building a pilot scale facility for extraction of heavy oil Using new and innovative technology incorporating with an existing topside facility. Integrating the technology to an already existing subsea facility Commissioning of project with maximum CAPEX $ 123.05 million Completing the project as fast as humanly possible Increasing the production by 1000 bbl/d

5.3.PROJECT SCOPEThe principal scope of the project team is to engineering, procurement, test, installationmanagement, commissioning and provide for assistance in start-up and maintenance for the pilot-facilities. Key activities of project scope are addressed as bellows;

Evaluating the field options available for building the pilot scale facility Selecting the best possible technology option for pilot scale facility development Procurement of technology and other essential requites (Umbilicals, risers, pumps) Installing pilot scale facility Modifying topside as per requirement Commissioning the project

5.4.PROCUREMENT STRATEGYProcurement activities for Project PEGASUS shall be handled by Project group. They will performthe requisition, budding and commercial evaluations. Technical evaluations will be performed byengineering group. All activities are supported by the QA/QC and HSE group. The Long Lead-Equipments will be tracked to complete in time. The subcontract requirements will be defined bythe Project team in early stage and will be included as activities in the project schedule. Especially,in-line separator package, pipeline and umbilical will be closely monitored and managed by the siterepresentative together with the QA / QC group and respective engineering group.

5.5.SCHEDULING PLANThe Long Lead-Equipment will be scheduled depends on progress monitoring so that criticalactivity could be completed in time. Due to the challenging delivery schedule, it is important forPenguin Engineering to ensure key milestones on the agreed dates. A tendering schedule is

described in section 7.0. It is important to forecast milestone activities and ensure they arecompleted on time.


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5.6.ORGANIZATIONAL CHARTThe project organizational chart for Project FEGASUS is portrayed in figure below. The chart helpsto understand each groups role and decision structure. The project directorensures that the projectlink to corporate management, ensure project key resources to be allocated to achieve the projectobjectives. The project management team will consist of a Project Manager, Project Deputy

Manager, QA/QC Manager, HSE Manager and Installation Manager. They will maintain the overallproject control and resolving internal / external conflicts. Commissioning team will be involvedearly stage of the project to minimize production downtime.

Figure 9: Grane Field Development Organizational Chart

5.7.QUALITY ASSURANCE MANAGEMENTThe quality of the product delivered is of the highest importance and Penguin Engineeringmaintains and operates a quality assurance management system fully compliant with the intent ofISO 9001:2008 standards. Quality Assurance Plan and Inspection Test Plans will be developedspecifically for Project PEGASUS.

5.8.HSE MANAGEMENTHealth, Safety and Environmental performance are core values and will be managed as an integral

part of our project to benefit stakeholders. Health, Safety and Environmental will be managed basedon the Project HSE Philosophy as below.

Carry out monitoring tentative various hazards and safety issue to eliminate all incidents. Comply with all environmental, health and safety laws and regulations Make health, safety and environmental friendly ways with the primary aim of project

execution


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6. RISK MANAGEMENT STRATEGYA comprehensive risk management strategy has been developed to ensure that the key parameters tothe success of the project are not just overlooked. This also ensures that the evaluation of the

potential risks, their effects and their impact using three steps:

Risk Identification.

Risk Analysis.Risk Mitigation.

6.1.RISK IDENTIFICATIONThe potential risks were identified during the project based on the evaluation of the various

parameters such as technicality, financial, project resources, etc. involved within the project overthe range of cost, time and quality.

Table 11: Risk Identification

Tender / Contract Engineering Fabrication Installation Commissioning1. Schedule.2. Scope of

Supply.3.Delay in Funds4. Inflation & Oilprice.

5. Regulations.

1. Schedule.2. Lack of field data.3. Interfacemanagement.4. Human Resources.5. Design errors.

1. Schedule.2. Quality.3. HSE.4. Test failure.

1. Schedule.2. Weatherdowntime.3. Topsidemodification.4. Accidents.5. VesselMobilization.

1. Schedule.2.Topsidemodification3.HumanResources4. HSE.5. Technicalerrors.

6.2.RISK ANALYSISThe risk analysis is carried by assigning values for the risk identified to determine the category ofimpact and probability. These values were multiplied to give the resultant risk i.e. Exposure =Probability x Impact. A measure to manage each risk is applied to develop a mitigated risk value.The original and mitigated risks are presented on a block diagram of impact versus probability.

The categories that the risk impact and probabilities are shown below:

Table 12: Risk Probabilities

Table 13: Risk Impact

Category Cost Time Safety Assigned Value

High > 2 million > 2months > 5 LTIs 3

Medium 500K to 2million 1 to 2 months 3-5 LTIs 2

Low


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Risk matrix after risk assessment has been carried out as shown below:

Figure 10: Risk Matrix

Impact

H 0 0 0

M 0 2 7

L 1 5 9

L M H

Probability

6.3.RISK MITIGATIONRisk mitigation has been effectively worked out to keep the as low as reasonably practicable(ALARP). A matrix with the mitigated risk has been developed as shown below.

Figure 11: Mitigated Risk Matrix

Mitigated

Probability

H 0 0 0

M 1 4 0

L 4 15 0

L M H

Mitigated

Impact

6.4.RISK REVIEWIt is very important to carry out risk reviews regularly to evaluate the risks associated with the

project and if new risks are identified, they need to be evaluated for their impact and theirconsequences. The risks that were identified at the beginning of the project have to be reevaluatedto looked if it was initial evaluated effectively and have been successfully mitigated. This activityshall be carried out quarterly with an objective reduce the possibilities of an event.

A risk register has been developed for this project at Section 9.0


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7. PROJECT WORK BREAKDOWN STRUCTUREThe work breakdown structure has been used for arranging project schedule and estimating budgetwithin execution plan.

Figure 12: Work Breakdown Structure


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8. PROJECT SCHEDULEThe schedule has been developed as shown below and the critical path has been identified and shaded in RED.

Figure 13: Project Schedule


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9. ESTIMATED BUDGETThe cost breakdown of the project is shown in the table below. The main costs are the engineeringcosts, installing and commissioning costs. The sum total of the above mentioned three would giveyou the CAPEX of the project.

Figure 14: Estimated Budget

Unit Grane Field Total Cost

Engineering 5 % of OverallProject Cost

$ 4 million $ 4.2 million

Subsea Separation Unit

- In-Line Desander- In-Phase Separator- In-Line Electrocoalescer

Lump Sum111

1

$ 40 million $ 40 million

Pipeline Carbon Steel X65 13 km $ 1.3 million $ 1.3 million

Riser $ 750,000 $ 750,000

Umbilical

- Umbilical Termination Unit 10km $ 850,000/km $ 8.5 millionFlying Leads 5Nos, 30m $ 125,000 $ 125,000

Topside Control Equipment

- Subsea Control Unit- Subsea Power

Communication Unit

- Hydraulic Power Unit- Topside Umbilical

Termination Unit

Lump Sum $ 13 million $ 13 million

Logistics Lump sum $ 4.9 million $ 4.9 million

Installation (40 Days)

- Pipe laying Vessel- Installation Vessel- Vessel Mob/Demob Cost ($)- ROV

1 Vessel / day1 Vessel / day

per each trip1 Work Class/day1 Observation/day

$200,000/DAY$200,000/DAY$ 1 million$45,000$15,000

$ 4 million$ 4 million$ 4 million$ 2.4 million

Commissioning

- Topside Control- Hydrostatic Testing

Lump Sum $900,000 $900,000

Total $ 88.05 million

Contingency - 40% $ 35 million

Estimated Budget with contingency $ 123.05 million


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Table 14: NPV & IRR Calculation

Year Fixed CostVariable

CostTotal Cost

Production(bb/day)

RevenueTaxableIncome

Book Valueof Asset

DepreciationValue ofCapital

AllowanceIncome Tax

Netcash flow

2013 0 US$123,050,000 US$0 US$123,050,000 0 US$0 US$0 US$123,050,000 US$30,762,500 US$0 US$0 (US$123,050,000)

2014 1 US$0 US$20,000 US$20,000 1,000 US$9,307,500 US$9,287,500 US$92,287,500 US$23,071,875 US$9,228,750 US$0 US$9,287,500

2015 2 US$0 US$20,000 US$20,000 1,000 US$37,230,000 US$37,210,000 US$69,215,625 US$17,303,906 US$6,921,563 (US$6,442,500) US$43,652,500

2016 3 US$0 US$20,000 US$20,000 1,000 US$37,230,000 US$37,210,000 US$51,911,719 US$12,977,930 US$5,191,172 US$4,241,438 US$32,968,563




2020 7 US$0 US$20,000 US$20,000 1,000 US$37,230,000 US$37,210,000 US$16,425,192 US$4,106,298 US$1,642,519 US$8,972,974 US$28,237,0262021 8 US$0 US$20,000 US$20,000 1,000 US$37,230,000 US$37,210,000 US$12,318,894 US$3,079,724 US$1,231,889 US$9,520,481 US$27,689,519

2022 9 US$0 US$20,000 US$20,000 1,000 US$37,230,000 US$37,210,000 US$9,239,171 US$2,309,793 US$923,917 US$9,931,111 US$27,278,889



2025 12 US$0 US$20,000 US$20,000 1,000 US$37,230,000 US$37,210,000 US$3,897,775 US$974,444 US$389,778 US$10,643,297 US$26,566,703





Oil Price 102 USD/bbl

Production daysper year

365 days/year

Income TaxRate

30% Net Present Value USD 38,113,092

Depreciation 25%Internal Rate ofReturn

22%

Discount Rate 15%


25/26

24 PENGUIN EPCM

10.RISK REGISTERAfter the various risks associated with project PEGASUS were identified, a risk assessment was carried out. After assessment, various mitigationtechniques were used for reducing.

Table 15: Risk Register

Ref. No. Description of Risk Risk Assessment Risk Management Mitigated Risk Assessment

P I E MP MI MR

Time

1. Delay in Tendering L M 2 Proper tendering schedule and procedures L L 1

2. Weather Downtime L M 2 Proper Planning Considering Weather L L 1

3. Accidents L H 3 Incentive for LOW LTI L M 24. Late Delivery of Equipments M H 6 Dispatch expediter L M 2

5. Delay in Approvals M H 6 Proper Identification & Documentation M M 4

6. Vessel Mobilization Delay L H 3 Contact in advance L M 2

7. Poor Management M H 6 Frequent Project Management Review L M 2

Cost

1. Inflation L L 1 Contingency L L 1

2. Oil Price L M 2 Evaluation of the project based on an average oil price L M 2

3. Accuracy in Cost Estimation M M 4 Routine Assessment L M 2

4. Unexpected Cost M M 4 Contingency L M 2

5. Delay in Funds L M 2 Alternative Financial Source L M 2

6. Project Delay M H 6 Monitoring Project Progress M M 4

7. Accidents L H 3 Insurance L M 2

8. Change in Scope L H 3 Add Reimbursable Man-hour L M 2

9. Fabrication defect L M 2 Quality Inspection Procedure / 3rd Party Inspection L L 1

10. Installation defect L H 3 Marine Warranty Surveyor L M 2Safety

1. Human Errors M H 6 Detailed Commissioning Procedures M M 4

2. Oil spill L H 3 Emergency Response Plan L M 2

3. Safety Equipment failure L H 3 Redundancy in Safety Equipment L M 2

4. Loss of integrity M H 6 Integrity Management M M 4

5. Blowout L H 3 SSIV L M 2

6. Pipeline/Riser failure L H 3 Integrity Management L M 2

7. External factors M H 6 Protection Structure M M 4


26/26

11.REFERENCE BASS, R.M., 2006. Subsea Processing and Boosting-Technical Challenges and

Opportunities, Offshore Technology Conference, - 2006.

CAVANAGH, J., 2012. Project Management Lecture Note. Aberdeen: John Cavanagh. COWIE, D., SCHMOLL, J.K., SUTTON, J.E., ROBERTSON, D.S. and ROBINSON, S.A., 1994.Investigation Of A Novel Facility Design Concept For Heavy-Oil North Sea

Development, Offshore Technology Conference, - 1994.

EUPHEMIO, M., OLIVEIRA, R., NUNES, G., CAPELA, C. and FERREIRA, L., 2007. SubseaOil/Water Separation of Heavy Oil: Overview of the Main Challenges for the Marlim

Field-Campos Basin, Offshore Technology Conference, - 2007.

FMC TECHNOLOGIES, Available:http://www.fmctechnologies.com/en/SeparationSystems/Technologies/InLineTechn

ologies.aspx.

GILL, H., ALNAHDI, A.A., FARID, U., MORRIS, R.D. and OMIDIYA, A.B., 2011. Engineeringa Successful Sour, Heavy Oil Test in a Sensitive Offshore Environment in Saudi Arabia,

SPE Heavy Oil Conference and Exhibition, 12-14 December 2011, Society of Petroleum

Engineers.

HANNISDAL, A., WESTRA, R., AKDIM, M.R., BYMASTER, A., GRAVE, E. and TENG, D.T.,2012. Compact Separation Technologies and Their Applicability for Subsea Field

Development in Deep Water, Offshore Technology Conference, - 2012.

SUBSEA SEPARATION AND PROCESSING OF OIL, GAS & PRODUCED WATER PAST,PRESENT AND FUTURE WHY WE NEED IT NOW, . Available:

http://www.forum.rice.edu/past-events/past-forums/.
http://www.fmctechnologies.com/en/SeparationSystems/Technologies/InLineTechnologies.aspxhttp://www.fmctechnologies.com/en/SeparationSystems/Technologies/InLineTechnologies.aspxhttp://www.fmctechnologies.com/en/SeparationSystems/Technologies/InLineTechnologies.aspxhttp://www.forum.rice.edu/past-events/past-forums/http://www.forum.rice.edu/past-events/past-forums/http://www.forum.rice.edu/past-events/past-forums/http://www.fmctechnologies.com/en/SeparationSystems/Technologies/InLineTechnologies.aspxhttp://www.fmctechnologies.com/en/SeparationSystems/Technologies/InLineTechnologies.aspx

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