Assignment 2010 Rev A
Transcript of Assignment 2010 Rev A
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8/9/2019 Assignment 2010 Rev A
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SETONIX OIL COMPANY BASIS OF DESIGN
PERTH CANYON DEVELOPMENT Doc No. 0902-84 Rev A
MASTER OF OIL AND GAS ENGINEERING SUBSEA TECHNOLOGY MODULE OENA 8554Assignment 2010 rev A.doc 28 July 2010 page 1 of 13
Setonix
BASIS OF DESIGN
PERTH CANYON DEVELOPMENT
Rev Description By Check PE PM Date
A Issued for Engineering Check K Mullen 28 July 2010
1 Revised as Noted K Mullen
Revised and Updated
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SETONIX OIL COMPANY BASIS OF DESIGN
PERTH CANYON DEVELOPMENT Doc No. 0902-84 Rev A
MASTER OF OIL AND GAS ENGINEERING SUBSEA TECHNOLOGY MODULE OENA 8554Assignment 2010 rev A.doc 28 July 2010 page 2 of 13
CONTENTS
1. INTRODUCTION...................................................................................................3 1.1 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...............................................................105.1 Water Depth......................................................................................................105.2 Metocean Conditions ........................................................................................105.3 Variation of Water Temperature with Depth......................................................105.4 Soil Conditions..................................................................................................105.5 Environmental ...................................................................................................10
6. COSTING AND SCHEDULE ..............................................................................106.1 Costing..............................................................................................................10 6.2 Schedule...........................................................................................................10
7. APPENDIX - CONVERSION FACTORS ............................................................11
8. APPENDIX - COST DATABASE / RELIABILITY DATA....................................13
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SETONIX OIL COMPANY BASIS OF DESIGN
PERTH CANYON DEVELOPMENT Doc No. 0902-84 Rev A
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1. INTRODUCTION
1.1 General
Setonix Oil Company (SOC) wishes to invite bidders to submit a tender forthe 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 and contains a small amount ofassociated gas, primarily methane. It is planned to develop the fieldthrough subsea wells. Tenderers are to recommend development andexport options for the field architecture.
The Perth Canyon oil field comprises a single reservoir with recoverable
reserves 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: ~12 km x 3 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 was
acquired 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 andfluvial 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 permitproduction 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
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 hydrate
blockage 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 Disposal
Gas disposal methods should be reviewed and considered 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) 80FWHP -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 3 km x 12 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 welldeclines 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 maximumdeviation 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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PERTH CANYON DEVELOPMENT Doc No. 0902-84 Rev A
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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. Thishas 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
No produced water should appear during field life. The only water presentin the system should be water of condensation.
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(C)
Viscosity(cP)
40C (104F) 2.46
50C (122F) 1.80
4 Viscosity is based on Beggs and Robinson equation.
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PERTH CANYON DEVELOPMENT Doc No. 0902-84 Rev A
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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 ppm
oil 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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PERTH CANYON DEVELOPMENT Doc No. 0902-84 Rev A
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7. APPENDIX - CONVERSION FACTORS
Mass 1 tonne 0.9842 UK ton
Mass 1 kg 2.2046 lbForce 1 N 0.10197 kgf 0.22481 lbf
Force 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 psiPressure 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 gas1 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 gas
1 terajoule per day 26,300 cubic metres of
natural gas per day
0.929 million cubic feet of
natural 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
equivalent1 million tonnes of LNG per
year (1 mtpa)
1.333 billion cubic metres
per year
3.65 million cubic metres of
natural gas per day
1 barrel of oil 0.158987 kilolitres of oil
1 kilolitre of oil 6.29 barrels of oil
1 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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PERTH CANYON DEVELOPMENT Doc No. 0902-84 Rev A
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Approximate Conversion Factors from BP website
Crude oil*
To
Tonnes (metric) kilolitres barrels US gallons tonnes/year
From Multiply byTonnes (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 1.240Gas 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
thermal
units
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 oil
equivalent
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 thermal
units
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 Btu
1 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 BtuCalorific equivalents
One tonne of oil equivalent equals approximately:
Heat units 10 million kilocalories
42 gigajoules
40 million Btu
Solid 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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PERTH CANYON DEVELOPMENT Doc No. 0902-84 Rev A
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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 acomprehensive 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.
EquipmentEquipmentEquipmentEquipment Cost (A$)Cost (A$)Cost (A$)Cost (A$) Mean Time to Failure MTTF (yrs)Mean Time to Failure MTTF (yrs)Mean Time to Failure MTTF (yrs)Mean Time to Failure MTTF (yrs)Subsea Wellhead 300,000 200 Xmas Tree - Diver Installed 2,000,000 50 Xmas Tree - Diverless 3,000,000 504 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 yearsHigh 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 yearsElectrohydraulic 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 aboveCost to S-lay Carbon Steel line 150,000 / kmCost to J-lay Carbon Steel line 270,000 / kmFlexible flowlines - 6 X 50m 4,000 / metre As aboveFlexible 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 aboveFlowline Bundle Cost +10% Assume cost of individual components of bundle plus 10%.
Assumes availability of fabrication/launch site.
Vessels/BuoysVessels/BuoysVessels/BuoysVessels/Buoys CostCostCostCost NotesNotesNotesNotes3rd 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 and
Offtake Vessel)
700,000,000 Rental: 70,000,000 p.a.
East Spar - type buoy 30,000,000