Assignment 2010 Rev B

8/8/2019 Assignment 2010 Rev B

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SETONIX OIL COMPANY BASIS OF DESIGN

PERTH CANYON DEVELOPMENT Doc No. 0902-84 Rev B

MASTER OF OIL AND GAS ENGINEERING SUBSEA TECHNOLOGY MODULE OENA 8554

Assignment 2010 rev B.doc 7 September 2010 page 1 of 14

Setonix

BASIS OF DESIGN

PERTH CANYON DEVELOPMENT

Rev Description By Check PE PM Date

A Issued for Engineering Check K Mullen 28 July 2010

B Issued for Use K Mullen 7 September 2010

1 Revised as Noted K Mullen

Revised and Updated


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CONTENTS

1. INTRODUCTION.................................................................................................... 31.1 General ................................................................................................................ 31.2 Seabed Topography ............................................................................................ 31.3 Field Location....................................................................................................... 41.4 Development Drilling............................................................................................ 41.5 Subsurface Challenges........................................................................................ 41.6 Design Intent........................................................................................................ 5

2. FIELD DESIGN PARAMETERS............................................................................ 62.1 Design Life ........................................................................................................... 62.2 Availability ............................................................................................................ 62.3 Hydrate Prevention and Remediation.................................................................. 62.4 Corrosion Inhibition .............................................................................................. 62.5 Gas Disposal........................................................................................................ 62.6 Well Test .............................................................................................................. 6

3. SUBSURFACE AND WELLS................................................................................ 73.1 Reservoir Data ..................................................................................................... 73.2 Well Productivity .................................................................................................. 73.3 Xmas Trees.......................................................................................................... 73.4 Drilling and Type of Wells .................................................................................... 7

4. FLUID PROPERTIES ............................................................................................ 94.1 Well Test Data ..................................................................................................... 94.2 Produced Oil Properties....................................................................................... 94.3 Produced Water ................................................................................................... 94.4 Crude Viscosities ................................................................................................. 9

5. METOCEAN AND ENVIRONMENTAL............................................................... 115.1 Water Depth....................................................................................................... 115.2 Metocean Conditions ......................................................................................... 115.3 Variation of Water Temperature with Depth ...................................................... 115.4 Soil Conditions ................................................................................................... 115.5 Environmental .................................................................................................... 11

6. COSTING AND SCHEDULE............................................................................... 116.1 Costing ............................................................................................................... 116.2 Schedule ............................................................................................................ 11

7. APPENDIX - CONVERSION FACTORS............................................................. 12

8. APPENDIX - COST DATABASE / RELIABILITY DATA.................................... 14


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1. INTRODUCTION

1.1 General

Setonix Oil Company (SOC) wishes to invite bidders to submit a tender for

the development of the Perth Canyon oil field.

The Perth Canyon oil field is located in a water depth of approximately1600 m. The Perth Canyon oil is a medium-light crude with anapproximate gravity of 47.2API containing a small amount of associatedgas, primarily methane, and increasing amounts of produced water. It isplanned to develop the field through subsea wells. Tenderers are torecommend development and export options for the field architecture.

The Perth Canyon oil field comprises a single reservoir with recoverablereserves of 80 million barrels.

1.2 Seabed Topography

The Perth Canyon is a relict of the Swan River drainage system, cuttinginto the shelf west of Perth and Rottnest Island. At the canyon head thedepth plunges from 200 m to 1000 m. The canyon mouth opens onto theabyssal plain at 4000 m. In between, the canyon curves sinuously over100 km, with a sharp bend halfway referred to as the dogleg, as shown inFigure 1. Two small branches are present on the south rim near thedogleg.

Figure 1 Perth Canyon


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1.3 Field Location

The layout of the Perth Canyon field is indicated in Figure 2 below.

Rottnest

Island

Rottnest

Island

Figure 2 Perth Canyon Reservoir

Reservoir dimensions: ~13 km x 4 km.Reservoir water depth: 1600 m.

Depth contours from the coast are [100, 200, 300, 500, 750, 1000, 1500, 2000, 2500,3000, 4000] m.

1.4 Development Drilling

From February 2008 to July 2009, SOC executed an exploration andappraisal program in the Perth Canyon resulting in the oil field discoveries.A total of nine wells were drilled over this period.

The oil discovery was made in February 2009, when the PC-7 explorationwell encountered a gross oil column of 24 m in the reservoir.

1.5 Subsurface Challenges

Appraisal wells were drilled and a high-resolution seismic survey wasacquired over the field to assist in planning the production program.


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The reservoir lies in the Perth Canyon which is an ancient river outfall. TheMiocene submarine fan / channel reservoir is located 1,700m below thebottom of the ravine, in a water depth of approximately 1600 m.

Subsurface presents extreme challenges for drilling due to debris flow and

fluvial deposits comprising boulder beds, sandstone, clay, marl, withblocky landslide material.

1.6 Design Intent

Tenderer shall:

Design a subsea system to produce oil from the Perth Canyon field.

Set production rates to optimise return on investment.

Determine an optimised subsea architecture, and justify equipmentsizing and field life.

Design equipment and provide an operating philosophy to permit

production from the field. Review economics of the field and design the production system togive the best return on investment.

Where it is felt that essential development information is missing, Tendereris invited to use reasonable engineering judgement and makeassumptions (These should be stated and justified). Process analysis isnot required.

Tenderer shall provide a description and justification for the following:

Well design ( vertical vs. deviated)

Horizontal or vertical trees

Initial number of wells, and any subsequent phases of drilling newwells, if needed

Number of manifolds, and location

Flowline jumper routing, and manifold valving arrangements

Well testing and monitoring facilities

Annulus monitoring and venting

Wax, hydrate and corrosion control

Location and size of production facility

Risers

Technology for operation and control of the field

Flowline route and materials

Flowline sizing1

Pigging and inspection philosophy

Outline Environmental Impact Assessment

Schedule, and time to First Oil

Production rate, and life of field

Use or disposal of associated gas and produced water

1http://www.freefuelforever.com/Pressure%20Drop%20Calculator.exe


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2. FIELD DESIGN PARAMETERS

2.1 Design Life

Facilities shall be designed for a life of 20 years.

2.2 Availability

Overall development availability shall be in excess of 95%.

Tenderer is to demonstrate how this availability will be achieved2.

The facilities shall be designed for operating flexibility in terms of beingable to continue production whilst equipment has failed or is degradedawaiting repair (e.g. through provision of bypasses, redundancy, etc.).

2.3 Hydrate Prevention and Remediation

For the anticipated operating, shut-in, start-up and ambient conditions ofthe subsea production and lift/injection gas systems, hydrate mitigationtechniques may be required to avoid operation inside the hydrate region.

Tenderer shall recommend whether hydrate inhibitor injection shall bemade only at start-up and shutdown, or on a permanent basis.

Tenderer shall make provision for clearing flowlines of a complete hydrateblockage by relieving pressure from both sides of the blockage for safedisposal.

2.4 Corrosion Inhibition

Tenderer shall make provision for the injection of corrosion inhibitor intoflowlines and subsea facilities where necessary.

2.5 Gas and Water Disposal

Gas and produced water disposal methods should be reviewed andconsidered by Tenderer.

2.6 Well Test

Production wells are to be individually tested at least once a month for 12to 24 hours.

2 By means of reliability modelling.

A useful tool is RAPTOR Version 4.0S available from http://www.barringer1.com/raptor.htm


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3. SUBSURFACE AND WELLS

3.1 Reservoir Data

Reservoir data is provided in the following table.

Parameter DesignOil In Place (MMbbl) 270Recoverable reserves (MMbbl) 80

FWHP -SIWHP -FWHT -Reservoir Initial Pressure (bara) 260 baraReservoir Temperature 120 C

The reservoir is located 1700 m below the canyon floor in a water depth of1600 m. The reservoir (shown in Figure 2) measures 4 km x 13 km,oriented in an east-west direction.

3.2 Well Productivity

Well characteristics are given in the table below:

Parameter DesignMaximum well production rate (per well)at start of field life

15,000 bbl per day

As oil is drawn from the reservoir, the maximum flow rate from each well

declines in proportion to the remaining recoverable reserves3

.

3.3 Xmas Trees

Tenderer shall determine whether horizontal or vertical trees are preferred.

3.4 Drilling and Type of Wells

Wells shall have 5" tubing.

Tenderer shall determine whether vertical or deviated wells are preferred(see Figure 3). Due to the difficult subsurface conditions, the maximum

deviation permitted by Drilling is 1.0 km.

3 For example, after three quarters of the oil has been extracted, and 20 MMbbl recoverable reserves remain in

the reservoir, the maximum flow rate of each well falls to (20/80)*15,000 = 3,750 bbl per day.


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1.25 km

1.7 km

0.9 km

0.8 km

1 km

1.25 km

Vertical Completion Deviated Completion

Figure 3 Vertical vs. Deviated Wells

Bottom hole locations shall not be closer together than 2.5 km, as wellsany closer than this would unduly interfere with one another. This placeslimitations on the top hole locations, as shown in Figure 4 below.

1.25 km

2.5 km

1.25 km1.25 km

1.25 km

2.5 km

500 metres

Figure 4 Distance between Bottom-Hole Locations


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4. FLUID PROPERTIES

4.1 Well Test Data

A well test report for the PC-7 exploration well has been produced. This

has included preliminary characterisation of the wellstream composition.Key results are presented in Table 4.1.

Table 4.1

Well Test Data

PC-7 exploration well

Date 9 Feb 09

Oil Gravity 47.2 API

Solution GOR 65 scf/bbl

Pour Point 1.6C (35F)

4.2 Produced Oil Properties

The Perth Canyon crude oil is medium-light with an approximate gravity of47.2API and a low gas oil ratio GOR.

4.3 Produced Water

Initial water cut (percentage of water in the oil) will be zero, with water cutincreasing through field life, to 100% when all reserves have beenextracted: i.e.

Zero water cut at start of field life. 25% water cut when 60 million barrels of oil remain in the reservoir.

50% water cut when 40 million barrels of oil remain in the reservoiretc.

Note that the increasing water cut will also have an effect on the viscosityof the well fluids.

4.4 Crude Viscosities

PC-7 viscosity data4 is only available for the dead crude. The results aresummarised in Table 4.2 below.

Table 4.2

PC-7 Dead Crude Viscosities

Temperature Viscosity(cP)

40C (104F) 2.46

50C (122F) 1.80

4Viscosity is based on Beggs and Robinson equation.


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4.5 Hydrate Properties

The hydrate curve for the Perth Canyon crude with various inhibitors isshown in Figure 5.

Figure 5 Hydrate Curves for Perth Canyon Crude5

5 Ref. OTC 11963 The Physical Chemistry of Wax, Hydrates, and Asphaltene

http://www.stonefieldsheep.com/images/OTC%2011963.pdf

StableHydrate

Region HydrateFree

Region


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5. METOCEAN AND ENVIRONMENTAL

5.1 Water Depth

The Perth Canyon field is located in a water depth of 1600 m.

5.2 Metocean Conditions

Tenderer is to determine metocean conditions.

5.3 Variation of Water Temperature with Depth

Tenderer is to determine variation of water temperature with depth.

5.4 Soil Conditions

Tenderer is to determine soil conditions.

5.5 Environmental

Terms of the operating license are expected to be extremely strict:

Flaring not permitted except under emergency conditions.

Loss of hydrocarbons to the environment not permitted (severepenalties will be imposed)

Disposal of waste materials to the environment not permitted

Produced water disposed of overboard to contain less than 25 ppmoil

Interference with marine life is not permitted

6. COSTING AND SCHEDULE

6.1 Costing

A one page costing for equipment and vessels is to be prepared.

6.2 Schedule

Tenderer is to provide a one page schedule for the project.


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7. APPENDIX - CONVERSION FACTORS

Mass 1 tonne 0.9842 UK ton

Mass 1 kg 2.2046 lb

Force 1 N 0.10197 kgf 0.22481 lbfForce 1 kgf 9.80665 N

Force 1 lbf 4.448222 N

Impact Energy 1 ft-lb 1.355818 J

Torque 1 ft-lb 1.355818 Nm

Volume 1 bbl 0.1589873 m3 158.9873 litre

Volume 1 US gallon 3.785412 m3

Speed 1 knot 0.5144444 m/s

Power 1 hp 0.746043 kW

Length 1 mile 1.609344 km

Length 1 ft 0.3048 m

Pressure 1 bar 100 kPa 0.100 MPa 14.504 psi

Pressure 207 bar 20700 kPa 20.7 MPa 3000 psi

Pressure 1psi 6.894757 kPa 0.006894757 MPa

Pressure 1MPa 1N/mm2

US Customary Units Metric

1 trillion (T) 10^12 1 Terajoule (TJ) 10^12

1 billion (B) 10^9 1 Gigajoule (GJ) 10^9

1 million (MM) 10^6 1 Megajoule (MJ) 10^6

Heating value

1 cubic metre of natural gas

(North West Shelf)

between 37.3 to 41

Megajoules

1 British Thermal Unit BTU 1055 joules

Volume

1 standard cubic metre of

natural gas

35.3147 cubic feet of

natural gas

1 billion cubic metres of

natural gas

750,000 tonnes of LNG

1 trillion cubic feet of natural

gas

28.3168 billion cubic

metres of natural gas1 terajoule per day 26,300 cubic metres of

natural gas per day0.929 million cubic feet ofnatural gas per day

1 barrel of oil 158.987 litres of oil

1 barrel of oil equivalent 0.1024 tonnes of LNG

1 tonne of crude oil 7.8616 barrels of oil

Mass

1 metric tonne 0.984207 long tons 1000 kilogram

LNG

1 metric tonne of LNG 52.9 million British

Thermal units

1333 cubic metres of natural

gas at 0C

1.242 tonnes of oil

equivalent

1 million tonnes of LNG peryear (1 mtpa)

1.333 billion cubic metresper year

3.65 million cubic metres ofnatural gas per day

1 barrel of oil 0.158987 kilolitres of oil

1 kilolitre of oil 6.29 barrels of oil1 standard cubic metre of natural gas 35.3147 cubic feet of natural gas

1 billion cubic metres of natural gas 730,000 tonnes of LNG

1 terajoule 26,300 cubic metres of natural gas 0.929 million cubic feet of natural gas

Pressure bara Temp C

Metric standard conditions 1.01325 15

Normal conditions 1.01325 0

Metric standard conditions should normally be used.


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Approximate Conversion Factors from BP website

Crude oil*

To

Tonnes (metric) kilolitres barrels US gallons tonnes/year

From Multiply by

Tonnes (metric) 1 1.165 7.33 308 Kilolitres 0.858 1 6.2898 264

Barrels 0.136 0.159 1 42

US gallons 0.00325 0.0038 0.0238 1

Barrels/day 49.8

*Based on worldwide average gravity.

Products

To convert

Barrels to tonnes tonnes to barrels kilolitres to tonnes tonnes to kilolitres

Multiply by

LPG 0.086 11.6 0.542 1.844

Gasoline 0.118 8.5 0.740 1.351

Kerosine 0.128 7.8 0.806 1.240

Gas oil/diesel 0.133 7.5 0.839 1.192

Fuel oil 0.149 6.7 0.939 1.065

Natural gas and LNG

To

billion cubic

metres NG

billion

cubic feet

NG

million

tonnes oil

equivalent

million

tonnes

LNG

trillion

British

thermalunits

million

barrels oil

equivalent

From Multiply by

1 billion cubic metres NG 1 35.3 0.90 0.73 36 6.29

1 billion cubic feet NG 0.028 1 0.026 0.021 1.03 0.18

1 million tonnes oilequivalent

1.111 39.2 1 0.805 40.4 7.33

1 million tonnes LNG 1.38 48.7 1.23 1 52.0 8.68

1 trillion British thermalunits

0.028 0.98 0.025 0.02 1 0.17

1 million barrels oil

equivalent

0.16 5.61 0.14 0.12 5.8 1

Units and conversion factors from BP website

1 metric tonne = 2204.62 lb.

1 kilolitre = 6.2898 barrels

1 kilocalorie (kcal) = 4.187 kJ = 3.968 Btu1 kilojoule (kJ) = 0.239 kcal = 0.948 Btu

1 British thermal unit (Btu) = 0.252 kcal = 1.055 kJ

1 kilowatt-hour (kWh) = 860 kcal = 3600 kJ = 3412 Btu

Calorific equivalents

One tonne of oil equivalent equals approximately:

Heat units 10 million kilocalories

42 gigajoules

40 million BtuSolid fuels 1.5 tonnes of hard coal

3 tonnes of lignite

Gaseous fuels See Natural gas and LNG table

Electricity 12 megawatt-hours

One million tonnes of oil produces about 4000 gigawatt-hours of electricity in a modern power station.

Convert.exe http://joshmadison.com/article/convert-for-windows


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8. APPENDIX - COST DATABASE / RELIABILITY DATA

The following budgetary cost database is provided for high level costing of options to aid in theselection process for this assignment and to calculate budgetary field development CAPEX and OPEX.More detailed cost information may be provided by some lecturers. Note that this is not a

comprehensive component list and students should not feel obliged to use only those componentslisted below. Cost and failure for other equipment may be derived from the data below.

Equipment Cost (A$) Mean Time to Failure MTTF (yrs)Subsea Wellhead 300,000 200

Xmas Tree - Diver Installed 2,000,000 50

Xmas Tree - Diverless 3,000,000 50

4 Slot Manifold, mudmat foundation, clusterarrangement, no pigging loop, diver installed.Not including choke, control pod orflowmeter

4,000,000 Assume only critical failures are leakage from valves inproduction flowpath - 1200 yrs each, and diver made-upflanged connections - 1000 yrs each.

6 Slot Manifold, mudmat foundation, clusterarrangement, no pigging loop, diver installed.Not including choke, control pod orflowmeter.

5,500,000 Assume only critical failures are leakage from valves inproduction flowpath - 1200 yrs each, and diver made-upflanged connections - 1000 yrs each.

Subsea Heat Exchanger - for 1 well 600,000 Critical failures is limited to leakage from isolation valves in theproduction flowpath and end connections as per manifolds

Incremental cost for diverless installation ofmanifold / heat exchanger etc. - remoteconnections and isolation valves required

1,000,000 Note that diverless connections have a MTTF of 250 years

Choke Valve - Diver Retrievable 200,000 Assume 25% of chokes are repaired during field life.

Control Pod - Diver Retrievable 600,000 15 yearsIncremental cost for ROT for choke andcontrol pod

250,000 N/A

Multiphase Flowmeter - Diver Retrievable 250,000 10 yearsMultiphase Flowmeter - ROT Retrievable 550,000 10 years

High Integrity Pipeline Protection System(HIPPS) for 6 wells (downstream of manifold) -ROT retrievable

5 - 7,000,000 -limited data

3 years. Failure results in loss of production. Repair by retrievalof HIPPS module using vessel with >30 tonnes cranage

Subsea Separation System for 1 well - diverlessinstalled

3,000,000 3 - 6 years. (Little data available)

Subsea Separation System for 6 wells 10,000,000 3 - 6 years. (Little data available)Direct Hydraulic Control Umbilical - 6 wells 2,000 / metre 15 years

Electrohydraulic Control Umbilical - 6 wells 500 / metre 15 yearsIncremental cost increase for chemicalinjection line in umbilical

100 / metre N/A

Cost for CRA flowlines(Corrosion Resistant Alloy)

6,210 / tonne Flowlines are unlikely to fail (MTTF >> 1000 years). Connectionsfailure MTTFs as per manifold data above.

Cost to lay CRA line 280,000 / kmCost for Carbon Steel flowlines 883 / tonne As above

Cost to S-lay Carbon Steel line 150,000 / kmCost to J-lay Carbon Steel line 270,000 / km

Flexible flowlines - 6 X 50m 4,000 / metre As above

Flexible flowlines - 6 X >1 km 1,700 / metre As aboveFlexible flowlines - 12 X 50m 5,500 / metre As aboveFlexible flowlines - 12 X >1km 3,500 / metre As above

Flowline Bundle Cost +10% Assume cost of individual components of bundle plus 10%.Assumes availability of fabrication/launch site.

Vessels/Buoys Cost Notes3

rd

Semi submersible drilling rig spread rateDP deepwater drillship spread rate[Spread rate is about double the day rate]

350,000 / day400,000 / day Mobilisation cost is $25,000,000. Wait time of up to 6 months.Vertical wells take 30 days to drill.Offset/horizontal wells take 45 days to drill

Diving Support Vessel (includes sat divingspread and 50 tonne cranage)

138,000 / day Mobilisation cost is $ 2,250,000. Wait time up to 3 months.

Diving Support Vessel ( includes 300 tonnecranage but no sat diving spread)

320,000 / day Mobilisation cost is $ 2,250,000. Extra for sat diving spread is$25,000 / day. Wait time up to 6 months

ROV Support Vessel (includes 15 tonnecranage)

35,000 / day Mobilisation is $1,500,000. Wait time up to 2 weeks

FPSO (Floating Production, Storage andOfftake Vessel)

700,000,000 Rental: 70,000,000 p.a.

East Spar - type buoy 30,000,000

Assignment 2010 Rev B

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