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Skua Field Development Plan Team 2. Justin Dukas Project manager and Economics Agi Burra Geology Nurul Azami Petrophysics Justin Herriman Reserves Lim Ching Wan Reservoir Xiochan Shen Reservoir Wan Zuraidah Ahmad Production

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skua field development plan team 2

Skua Field Development PlanTeam 2.

Justin Dukas Project manager and Economics

AgiBurra Geology

NurulAzamiPetrophysics

Justin Herriman Reserves

Lim Ching Wan Reservoir

XiochanShen Reservoir

Wan Zuraidah Ahmad Production

IngveHebnes Drilling and Completions

Dylan Stringer Facilities

executive summary
Executive Summary
  • Develop southern oil field
  • Drill 2 new wells, recomplete Skua 3 and 4
  • Gas cap blow-down, confirm production rates with simulation
  • NPV10 =460 Million AUD, NPV/I=1.6
  • Payback time 21.5 months
  • Max Exposure $413 Million
mission statement
Mission Statement

To produce the best field development plan for the Skua field, maximizing the asset value to the company while minimizing the downside risks

field layout
Field Layout

Smallersection B

1 MMSTB

Largersection A

42 MMSTB

regional geology
Regional Geology
  • Offshore target located approx 700 kms west of Darwin
  • Extensional environment in NW-SE direction resulting in NE-SW normal faulting
    • horst / graben features encouraging localised deposition at elevated rates
  • Numerous faulting events in area with probable moderately recent re-activation of pre-existing structures
  • Such environments frequently encourage migration of fluids along lineaments

Section 1

(Osborne, 1990)

skua field geology8
Skua Field Geology
  • Reservoir limited by major NE trending normal faults in the east, west and north
  • Additional smaller scale faulting is known – particularly in the lower horizons
  • Target reservoir dipping toward the SE at 18.5° with an unconformable cap at ~2,300m depth
  • Full reservoir sequence was intercepted in Skua 6

Section 1

  • Main NE fault appears to be sealing – pressure data
  • Cretaceous tilting of sediments

(Osborne, 1990)

stratigraphy

(Emery et al, 1996)

Stratigraphy
  • Depositional environment
    • Fluvial to coastal environments evident from stratigraphical profiles
  • Reservoir characteristics:
    • Target reservoir is made up of 6 horizons, 5 of which are HC hosts at different sites
      • Basal layers massive sandstone with minimal flow barrier units
      • Younger reservoir rocks are made up of interbedded horizons such as sandstone / shale / siltstone / mudstones

(Osborne, 1990)

reservoir characteristics
Depositional history:

Fluvial to Coastal sediment deposition

Widespread faulting, tilting of sediments and erosion (unconformity)

Hydrocarbon emplacement

Recent re-activation of major faults

GRV = 123MM m3 or 774MM res bbl

Good porosity

Around 21%

Aquifer

Strong edge water drive

Water influx along impermeable shale unit bedding planes

Fluid contacts

OWC and GOC intercepted in a number of locations

Gas cap identified – 28m height

Oil column – 46m height

Reservoir Characteristics

(Osborne, 1990)

recommendations
Recommendations:
  • Acquire 3d seismic for increased resolution to refine location and extent of:
    • Faults → well location and reserves
    • Main sealing units→ reservoir dynamics and reserves
    • Reservoir units → NG ratio and reserves
  • Drill well in area where full reservoir sequence can be intercepted
    • Obtain core data to further assess rock and HC properties → refine assumptions into modelling
  • Generate 3D geological model to assist with understanding reservoir dynamics
petrophysics
PETROPHYSICS

NurulAzami

reservoir properties
Reservoir properties

GOC: 2286.5 m ss

OWC: 2333 m ss

h: 46.5 m

Rock properties

Φ: 21%

k: 360 – 1700 mD

Ave. N/G: 50%

HC saturation: 0.82

Residual So: 0.20

Residual Sg: 0.15

slide14

Fluid properties

  • Oil specific gravity: 0.815
  • 42º API
  • Bo: 1.48
  • Oil viscosity: 0.30 cP
  • Oil compressibility: 19.8 microsips
  • GOR: 900 scf/stb
  • Gas expansion factor: 200 scf/rcf
  • Gas viscosity: 0.021 cP
  • Water viscosity: 0.35 cP

* Properties are measured at initial reservoir P and T.

skua 3 cross section

Skua-3

GOC 2286.5

OWC 2333

1

2

3

4

5

6

7

Skua-3 cross section
skua 4 cross section
Skua-4 cross section

Skua-4

GOC 2286.5

OWC 2333

1

2

3

4

5

6

7

skua field facies

Skua-3

Skua-4

Skua-6

Bayfill

Mouthbar estuary

Channel

Mouthbar

Delta front (lagoon)

Skua field facies
skua field insitu k crossplot
Skua Field Insitu k-Φ crossplot

104

103

102

101

100

Deltaic environment – high energy

Skua-3

Skua-4

Overburden core perm

0 15.00 30.00

Overburden core porosity

slide22

Skua-3

#1

Estuarine / marine

#2

Lagoonal interdistrib. bay

#3

Fluvial - Estuarine

#4

skua 423
Skua-4

Lacustrine/ alluvial

#1

Coastal plain/ alluvial lagoonal

Lacustrine alluvial

#2

Bay margin delta plain

#3

Marginal marine lagoonal

#4

relative permeability
Relative Permeability
  • From SCAL of Skua 3 core
reserves estimation
Reserves Estimation

Justin Herriman

significance of estimation
Significance of Estimation

Ultimate goal to define return on investment

Uncertainty exists and must be managed

Required component of reservoir modelling and economics

inputs and assumptions
Inputs and Assumptions

GRV from Area vs. Depth plot

N:G, porosity, Sw estimated from logs, core, analysis

Bo, Bg from PVT

Minima and Maxima as recommended, triangular distributions

Each layer treated separately

ooip influence
OOIP Influence

Sand unit 1 N:G and GRV most influence

correlation between parameters
Correlation between Parameters

Sw and porosity correlated by -0.7

Reduction in Std. Dev.

recovery factor
Recovery Factor

Analogue fields 55-65% (Wallace & Balnaves, 1988; Edwards & Behrenbruch, 1998)

MBAL Model predicted 63%

Assumption: “no doubts are held for full and strong aquifer” (Skua Aquifer Report)

Chosen Distribution: Uniform 35-65%

Accounts for aquifer/connectivity uncertainties suggested by geologist

reservoir production engineering
RESERVOIR & PRODUCTION ENGINEERING

Chan

Wan Zuraidah

Ching Lim

main focus
MAIN FOCUS

Compare development alternatives

- Theoretical (data given)

- Preliminary simulations

Choose development alternatives

Decide on number of wells

Decide on well locations/likely perforation depths

Run sensitivities

development alternatives
DEVELOPMENT ALTERNATIVES

Gas Cap Blowdown Dev.

Well

Gas Cap

Initial Oil Column

Conventional Oil Rim Dev.

Aquifer

Well

Well

Gas Cap

Remaining Gas Cap

Gas Flooded Zone

Oil Resaturated Zone

Final Oil Rim

Remaining Oil Rim

Water Flooded Zone

Final Oil Rim

Water Flooded Zone

conventional development
CONVENTIONAL DEVELOPMENT

The effective oil thickness is located between a gas cap and a water zone

For conventional development, both gas and water coning will pose a problem

The critical oil rate Qoc for combined gas and water coning can be calculated with the Meyer-Garder Correlation

gcb development
GCB DEVELOPMENT
  • Assume gas cap has been produced
  • The critical oil rate can be estimated by applying the equation for water-coning system.

Gas cap produced

q oc results
Qoc RESULTS
  • Coning problem will occur when wells are produced above Qoc
  • If critical rate is lower, coning will be more severe
  • Wells have higher Qoc in GCB than conventional
pitfall of conventional development
PITFALL OF CONVENTIONAL DEVELOPMENT

Expected high water cut compared to GCB

May need re-perforation in later life of reservoir

Increased cost

important factors for gcb
IMPORTANT FACTORS FOR ‘GCB’

Reservoir Energy

Production Policy – Flaring

Perforation Depths

Most suitable for reservoirs with:

- strong aquifer

- small gas cap

drive mechanism
DRIVE MECHANISM

Plover Formation Aquifer Support Information Provided:

Plover formation section average thickness of 800 m

Conservative estimation – semi-circular with radius of 30 km

Volume of Connected Aquifer to Reservoir 5.2 million to 1

Aquifer support in Skua Field is very strong

Justification?

Based on Gross Rock Volume in Skua Field 142 x 106 m3

To guarantee adequate support: Aquifer : Reservoir → 1000 : 1

Required aquifer radius → 10.6 km

Additional Information:

Analogue → Jabiru field has strong aquifer support (SPE 17602)

gas cap size
GAS CAP SIZE

For all low, base and high case reserves, the relative gas cap size is calculated to be approximately 0.09

Relatively small gas cap size (m < 0.1)

GCB theoretically suitable for Skua

so conventional or gcb
SO, CONVENTIONAL OR GCB??

EXTRA BENEFITS

Maximize oil production rate and recovery, as shown by simulation

Minimize reservoir management and operating cost

GAS CAP BLOWDOWN

development strategy
DEVELOPMENT STRATEGY

Focus on SW block

Re-complete two existing wells

- Skua 3 (SK-3)

- Skua 4 (SK-4)

Drill two new vertical wells

- Skua 7: between SK-3 and SK-4

- Skua 8: SW of SK-3

development strategy57
DEVELOPMENT STRATEGY

Considerations while choosing locations:

Keeping in mind drainage radius assume equal distances between wells

Option for in-fill drilling in the future

Intersect gas cap (GCB)

present well locations

PRESENT WELL LOCATIONS

Exisiting Well Skua 4

Exisiting Well Skua 3

skua 3 cross sectional area
SKUA 3 CROSS SECTIONAL AREA

Intersects at GOC

Perforate in oil zone

Most likely to water out first

skua 4 cross sectional area
SKUA 4 CROSS SECTIONAL AREA

Intersects crest of gas cap at 2281 mTVDSS

Gas cap thickness ~ 5 m

Perforate near crest

Produce gas cap

Might produce oil upfront

proposed well locations
PROPOSED WELL LOCATIONS

Exisiting Well Skua 4

New Well Skua 7

Exisiting Well Skua 3

New Well Skua 8

skua 7 cross sectional area
SKUA 7 CROSS SECTIONAL AREA

Between Skua-3 and Skua-4

Intersect gas cap

Proposed TVD 2360 mss

Perforate near the crest

Produce gas cap upfront (blowdown)

Proposed SKUA-7

skua 8 cross sectional area
SKUA 8 CROSS SECTIONAL AREA

No 2-D seismic cross section available for proposed location

Use cross section for nearby Skua-2 as a reference

Intersect gas cap – as close to the crest as possible

Proposed TVD 2360 mss

Perforate above GOC

Proposed SKUA-8

prosper
PROSPER

Tubing size selection

prosper66
PROSPER
  • Single tubing – 4.5”
  • Tapered tubing – 5.5” top; 4.5” bottom
  • Single tubing more feasible
prosper67
PROSPER

Analyse system for various PI

(5 to 25)

case comparison
CASE COMPARISON

RF = 65%

RF = 62%

RF = 60%

production profile
PRODUCTION PROFILE

Peak production

contingency
CONTINGENCY

Not enough pressure maintenance

Gas production will increase with time

BUT, wells have already been drilled and perforated

CONTINGENCY:

Squeeze-cement perforation in gas zone

Re-perforate in oil zone

WHAT IF AQUIFER IS WEAK?

GAS

OIL

summary
SUMMARY

Aquifer support - major drive mechanism - strong water drive

Gas cap size is small – m ~ 0.09

Development option chosen - GCB

Optimum completion - single tubing 4.5”

2 new wells required

Perforate near crest

Expected recovery factor 60 – 65%

well planes
Well planes
  • Re-enter and complete skua 3 and 4.
  • Drill and complete two new vertical wells.
  • Perforate wells as high up as possible, to avoided water coning for as long as possible.
  • Perforate intervals:
    • Skua-4: 2283m - 2288m
    • Skua-3: 2290m - 2295m
    • Skua-7: 2282m - 2285m
    • Skua-8: 2272m - 2280m
completion
Completion

Wire line re-entry guide: Allows easy re-entry into tubing of wire line tools.

Landing nipple: Has a shoulder with small I.D, preventing passage of larger wire line tools.

Perforated flow tube: Allows fluid to enter the production tubing.

Permanent packer: Isolate production zones. Prevent fluids entering the annulus.

Sliding sleeve door: Gives controlled communication between tubing and annulus.

completion82
Completion

Side pocket mandrels: Used to inject gas and chemicals into well. Also used for emergency kill device.

Sub surface safety valve: Device used to shut off production in case of an emergency. Controlled from surface through hydraulic line.

Tubing hanger: Used to suspend the tubing in the well and to isolate tubing to annulus.

drilling and completions economics
Drilling and Completions Economics

Rig rent 750 000USD/day excluding casing, tubing and completion equipment.

Casing and tubing cost:

drilling and completions economics84
Drilling and Completions Economics

Total costs for re-entry and complete skua-3 and -4 and drill and complete skua-7 and -8 is 95.37 million USD.

facilities
Facilities

Dylan Stringer

potential facilities options
Potential Facilities Options
  • Subsea development with pipeline to shore/other field facilities
  • Offshore facilities with pipeline to shore/other field facilities
  • Floating Production/Storage/Offloading Facility with Subsea Facilities
facilities decision tree
Facilities Decision Tree

Jabiru FPSO from Oracle Risk Management (2008)

facilities considerations
Facilities Considerations
  • Water depth ≈ 83m
  • Typically Mild Weather Conditions
    • Wave Height 9.6m, Wave Period 12.4s
    • Wind: 10 min. avg. 41.4m/s, 1 min. avg. 46.9m/s
    • Surface Current 2.19m/s
    • Severe cyclones (wind speed of 100km/h+) approximately every 2.6 years
  • No existing nearby facilities or pipelines
  • Fluids production rate of 50,000 bbl per day.
fpso design discussion
FPSO Design Discussion
  • Tanker Conversion FPSO
  • Single Point Mooring System Situated North East of the field
  • Externally mounted disconnectable SPM
fpso design discussion contd
FPSO Design Discussion Contd.
  • Flare must be designed to Australian safety standards.
  • Production facilities for stabilising oil: Max Fluids Rate – 50,000 bbl Turn Down Ratio ≈ 80%
  • Storage capacity 300k bbl – 1,000k bbl
  • CAPEX for FPSO includes crew quarters, communications, etc.
fpso cost breakdown
FPSO Cost Breakdown

On advice it has been assumed that abandonment costs are approximately equal to salvage costs.

assumptions
Assumptions
  • Oil price $US60/bbl
    • Inflated at 5% pa
  • OPEX of $US 60 million/year
    • Inflated at 5% pa
    • No OPEX for WC and production rate
  • Conversion of 0.7 USD/AUD
  • Discount rate of 10% pa
  • Calculated Monthly, @ mid-month
  • PRRT 40% Tax 30%
  • Depletion Depreciation
  • No PRRT reduction due to exploration, appraisal costs
base case
Base Case
  • Total Project life = 6 years 8 months
  • Total Oil Production Life = 5 years 4 months
low and high reserves cases
Low and High Reserves Cases

High Reserves 29.9MMBBLLow Reserves 25.4 MMBBL

economic findings
Economic Findings
  • Project is viable
  • Most sensitive to production profile
  • Sensitive to oil price, reserves
  • Really dependent on production profile
  • Further investigation into RF, production profile
project schedule
Project Schedule

Facilities

Longest item FPSO at 14 months

Ensuring Wells are drilled before SS installation

Flexibility in drilling time

Ensuring all equipment is available before start-up

16 Months to first oil

recommendations103
Recommendations
  • Implement project, based on current data
  • Reservoir Simulation to confirm production profiles and recovery factors
    • Compare to other fields
  • 4 wells significantly better than 3 wells
    • Quicker payback
  • Possible northern block option
references
References
  • Pinceratto, E. and Casey, J. “Environmental Risk Assessment – Case Study of an Offshore Petroleum Development” SPE Paper 46842
  • Oracle Risk Management (2008), www.oracle-services.com
  • Ronalds, B.F. and Lim, E.F.H., “FPSO Trends” SPE Paper 56708
  • Osborne M (1990). The Exploration and Appraisal History of the Skua Field, AC/P2 – Timor Sea. APEA Journal, Vol 30, pp 197 – 211.
  • Emery D, Myers KJ and Bertram GT (1996). Sequence Stratigraphy. Blackwell Science, Oxford, UK.
  • Wallace TD and Balnaves C (1988). Jabiru Field Simulation: A Case History. SPE paper 17602.
  • Edwards KA and Behrenbruch P (1998). Use of Well Test Results in Oilfield Development Planning in the Timor Sea. SPE paper 16985.
  • Geological Rationale for Aquifer Support for the Skua Field, Appendix 1, Skua FDP
references continued
References Continued
  • BHP Petroleum Pty Ltd Skua Development Plan, December 1991.
  • BHP Petroleum Pty Ltd Skua-4 Production Test #1, 14-17 August, 1998.
  • BHP Petroleum Pty Ltd Well Completion Programme Skua-4, July 1991.
  • Meyer, H & Garder, A 1954, “Mechanics of Two Immiscible Fluid in Porous Media”, J Applied Physics, No.11, p. 125.
  • Behrenbruch, P & Mason, LT 1993, “Optimal Oilfield Development of Fields With a Small Gas Cap and Strong Aquifer”, SPE 25353, presented at the SPE Asia Pacific Oil & Gas Conference & Exhibition, Singapore, 8-10 February 1993.