Institute of Petroleum Engineering
Heriot-Watt University
Mungo energy
Field Development
Project
Team W – Australia – WA-418-p
Michael Mouat
Gonzalo Del Valle
Timothy Erick Riadi
Zhaslan Uzykanov
Zisis Vryzas
Ciriako Aci
6/20/2012
2
Contents
Figures …………………………………………………………………………………………………………………………………………….…5
Tables ……………………………………………………………………………………………………………………………………………….6
List of abbreviations ................................................................................................................................7
Executive Summary .................................................................................................................................8
1.
Technical Summary ...................................................................................................................10
1.1
Field Location ........................................................................................................................ 10
1.2
Geology.................................................................................................................................. 10
1.3
Petrophysical Analysis ........................................................................................................... 12
1.4
Reservoir Fluids ..................................................................................................................... 15
1.5
Hydrocarbon in Place ............................................................................................................ 15
1.5.1 Deterministic, Probabilistic and Reserves Calculations.................................................15
1.6
Well Test Analysis .................................................................................................................. 16
1.7
Reservoir Modelling .............................................................................................................. 17
1.8
Economic and Commercial Considerations ........................................................................... 19
1.9
Field Development Plan ........................................................................................................ 20
1.10 Drilling ................................................................................................................................... 23
1.11 Production and Process Facilities .......................................................................................... 24
1.12 Production Plan ..................................................................................................................... 26
1.13 Environmental Impact and Abatement ................................................................................. 27
1.14 Field Abandonment Programme ........................................................................................... 27
2.
Field Description........................................................................................................................29
2.1
Geology.................................................................................................................................. 29
2.1.1 Structural Configuration ................................................................................................29
2.1.2 Depositional Environment .............................................................................................30
2.1.3 Stratigraphic Correlation ...............................................................................................31
2.1.4 Rock Properties .............................................................................................................32
2.1.5 Geological conclusions, uncertainty and risk ................................................................33
2.1.6 Geostatistics ..................................................................................................................34
2.2
Petrophysics .......................................................................................................................... 37
2.2.1 Determination of shale volume .....................................................................................38
2.2.2 Determination of permeability......................................................................................38
2.2.3 Determination of lithology ............................................................................................39
2.2.4 Determination of porosity .............................................................................................40
2.2.5 Determination of water saturation ...............................................................................40
2.2.6 Determination of net pay ..............................................................................................40
2.2.7 Oil Water Contact ..........................................................................................................41
2.2.8 Stress Sensitivity ............................................................................................................41
2.2.9 Petrophysical Uncertainties ..........................................................................................41
2.3
Hydrocarbon in Place ............................................................................................................ 42
2.3.1 Deterministic and Probabilistic Model ..........................................................................42
2.3.2 Uncertainties Associated with HCIIP Determination.....................................................43
2.3.3 Reserves ........................................................................................................................43
2.4
Reservoir Fluids ..................................................................................................................... 44
2.4.1 PVT Data ........................................................................................................................44
2.4.2 Hydrocarbon/Chemical Composition ............................................................................44
2.4.3 Water Analysis ...............................................................................................................45
2.5
Well Performance.................................................................................................................. 46
2.5.1 Well 1.............................................................................................................................46
2.5.2 Well-3 ............................................................................................................................47
2.5.3 Well-5 ............................................................................................................................47
3
2.6
3.
3.1
3.2
3.3
3.4
3.5
2.5.4 Well-6 ............................................................................................................................48
2.5.5 Conclusions....................................................................................................................48
Reservoir Modelling Approach .............................................................................................. 49
2.6.1 Static Model ..................................................................................................................49
2.6.2 Capillary Pressure and Relative Permeability ................................................................50
2.6.3 Simulation Models.........................................................................................................52
2.6.4 Recovery Mechanisms ...................................................................................................53
2.6.5 Alternative Development Plans Considered .................................................................58
2.6.6 Conclusions and Recommendations .............................................................................60
Development and Management Plan .......................................................................................61
Economic and Commercial Consideration ............................................................................ 61
3.1.1 Adjacent Fields ..............................................................................................................61
3.1.2 Australian Market ..........................................................................................................61
3.1.3 Corporate Environment.................................................................................................62
3.1.4 Cash Flow.......................................................................................................................63
3.1.5 Project Parameters ........................................................................................................64
3.1.6 Sensitivity Analysis ........................................................................................................68
3.1.7 Conclusion .....................................................................................................................69
Drilling ................................................................................................................................... 70
3.2.1 Introduction ...................................................................................................................70
3.2.2 Objective of the Programme .........................................................................................70
3.2.3 Geological Prognosis .....................................................................................................71
3.2.4 Pressure Profile & Mud Programme .............................................................................71
3.2.5 Rig Selection ..................................................................................................................71
3.2.6 Well Control...................................................................................................................72
3.2.7 Drilling Fluid Selection ...................................................................................................73
3.2.8 Drilling Bit Selection ......................................................................................................73
3.2.9 Casing Design.................................................................................................................74
3.2.10 Cementing .....................................................................................................................75
3.2.11 Bottom Hole Assembly (BHA) ........................................................................................76
3.2.12 Directional Drilling & Surveying.....................................................................................76
3.2.13 Risk Management ..........................................................................................................77
3.2.14 Drilling Schedule ............................................................................................................77
Production and Process Facilities .......................................................................................... 78
3.3.1 Well Completions ..........................................................................................................79
3.3.2 Subsea System ...............................................................................................................80
3.3.3 Host Facility and Hydrocarbons Export .........................................................................82
3.3.4 Flow Assurance ..............................................................................................................84
3.3.5 Tubing Selection ............................................................................................................86
3.3.6 Pressure Maintenance...................................................................................................87
3.3.7 Artificial Lift ...................................................................................................................88
Reservoir Management and Monitoring ............................................................................... 89
3.4.1 Production Profile..........................................................................................................89
3.4.2 Project Schedule ............................................................................................................90
3.4.3 Well Management and Monitoring ...............................................................................90
3.4.4 Well Intervention...........................................................................................................92
Environmental Impact and Abatement ................................................................................. 92
3.5.1 Non-Technical Summary ...............................................................................................92
3.5.2 The Existing Environment ..............................................................................................93
3.5.3 Significant Risks and Mitigation Measures ....................................................................94
3.5.4 Conclusions....................................................................................................................95
4
3.5.5 Environmental Management ........................................................................................95
3.6
Field Abandonment Programme ........................................................................................... 96
3.7
Costs ...................................................................................................................................... 97
3.7.1 General ..........................................................................................................................97
3.7.2 Exploration, Appraisal and Development Costs ............................................................97
3.7.3 Operations Expenditures ...............................................................................................98
3.7.4 Abandonment Costs ......................................................................................................98
3.7.5 Pollution Liability Provision ...........................................................................................98
3.8
Field Uncertainty ................................................................................................................... 99
4.
References ...............................................................................................................................100
5
Figures
Figure 1 W-Field Location, North West Australia .................................................................................. 10
Figure 2 Geologists Depositional Interpretation ................................................................................... 12
Figure 3 Well 2 log sample from Terrastation indicating OWC and sand bodies.................................. 14
Figure 4 Top Structure Map, Indicating Development Wells ................................................................ 22
Figure 5 Well completion design ........................................................................................................... 25
Figure 6 Production Profile.................................................................................................................... 26
Figure 7: Top Structure Map ................................................................................................................. 29
Figure 8: Seismic Survey ........................................................................................................................ 30
Figure 9 Geologists Depositional Interpretation ................................................................................... 30
Figure 10 Depositional Environment ..................................................................................................... 31
Figure 11 North to South Correlation.................................................................................................... 32
Figure 12 Well 2 Lorenz Plot.................................................................................................................. 35
Figure 13 Well 2 Modified Lorenz Plot .................................................................................................. 36
Figure 14 Well 2 Semi-Variogram.......................................................................................................... 37
Figure 15 Well 2 log sample from Terrastation indicating OWC and sand bodies................................ 41
Figure 16 Reverse Cummulative Frequency STOIIP Probabilities ......................................................... 43
Figure 17 STOIIP Sensitivity Analysis ..................................................................................................... 43
Figure 18 Upscaled Geo-model Displaying Porosity ............................................................................. 50
Figure 19 Capillary pressure Vs. Water saturation................................................................................ 51
Figure 20 Relative Permeability Curves for Oil and Water .................................................................... 51
Figure 21 Average reservoir pressures and oil production profiles in Depletion Cases ....................... 53
Figure 22 Recovery factor for Depletion and Water Injection Cases with 1, 2 and 3 injection wells ... 53
Figure 23 Recovery factor of oil for various Kv/Kh ratio cases. ............................................................ 55
Figure 24 Oil saturation grid with injection wells placed in the crest and limbs of the structure ........ 57
Figure 25 Oil Recovery Factors for 3 to 5 injectors and 7 to 12 Producers ........................................... 57
Figure 26 Production Profile, Oil Recovery Factor and Residual Oil in Reservoir for Best Case ........... 59
Figure 27 Oil Saturation Grid with proposed development wells ......................................................... 60
Figure 28 Produced Oil and Gas ............................................................................................................ 65
Figure 29 Reverse Cumulative Frequency for Probabilistic NPV of the project ................................... 69
Figure 30 Well completion design ......................................................................................................... 82
Figure 31 Flow diagram for produced fluids ......................................................................................... 84
Figure 32 Scale Percipitation and different Sea Water Saturation ....................................................... 85
Figure 33 Tubing Size Sensitivity ........................................................................................................... 86
Figure 34 Gas Injection Sensitivity ........................................................................................................ 88
Figure 35 Production Profile.................................................................................................................. 89
Figure 36 Project Schedule .................................................................................................................... 90
6
Tables
Table 1 Executive Summary .................................................................................................................... 8
Table 2 Physical Core Analysis Summary .............................................................................................. 11
Table 3 Reservoir Properties from core sample and log analysis ......................................................... 13
Table 4 Range of STOIIP Parameters ..................................................................................................... 15
Table 5 Deterministic and Probabilistic Calculations ............................................................................ 16
Table 6 Production Plan ........................................................................................................................ 19
Table 7 Summary of Drilling Program ................................................................................................... 24
Table 8 Water Analysis .......................................................................................................................... 26
Table 9: Lithology evaluated from core analysis ................................................................................... 33
Table 10 Summary of Statistics for Palaeocene Reservoir .................................................................... 34
Table 11 Summary of Statistics for Triassic Reservoir ........................................................................... 34
Table 12 Log Analysis of Palaeocene Reservoir..................................................................................... 39
Table 13 Log Analysis of Triassic Reservoir ........................................................................................... 40
Table 14 Range of STOIIP Values ........................................................................................................... 42
Table 15 Deterministic and Probabilistic Calculation ............................................................................ 42
Table 16 Calculations of Reserves ......................................................................................................... 44
Table 17 Approximated PVT data for reservoir conditions ................................................................... 44
Table 18 Hydrocarbon analysis of separator products (Well 4) ............................................................ 45
Table 19 Reservoir water samples containing Cations and Anions....................................................... 45
Table 20 Sea water samples .................................................................................................................. 46
Table 21 DST Completion Intervals ....................................................................................................... 46
Table 22 DST Results ............................................................................................................................. 47
Table 23 Development Strategies ......................................................................................................... 65
Table 24 Screening of Platform Development Options......................................................................... 69
Table 25 Best Economic Case for Steel jacket Platform, Selling Gas..................................................... 70
Table 26 Summary of Lithology from Surface to Reservoir................................................................... 71
Table 27 Rig Characteristics .................................................................................................................. 72
Table 28 Mud Type and Weight ............................................................................................................ 73
Table 29 Drill Bit Specification ............................................................................................................... 74
Table 30 Casing Properties, Burst and Collapse loads........................................................................... 75
Table 31 Cementing Characteristics ...................................................................................................... 76
Table 32 Reservoir Properties for WellFlo Characteristics .................................................................... 79
Table 33 Injection Tubing size sensitivity .............................................................................................. 87
Table 34 Production Tubing water cut sensitivity ................................................................................. 89
Table 35 Ranked Uncertainties ............................................................................................................. 99
7
List of abbreviations
$
$MM
°C
b/d
bbls
BHA
bopd
Bscf
Bscf/y
BSW
BUR
bwpd
CALM Bouy
CAPEX
Dollars
Million Dollars
Degrees Celsius
barrels per day
Barrels
Bottom Hole Assembly
barrels of oil per day
Billion standard cubic feet
Billion standard cubic feet per year
Base Sediment and Water
Build Up Rate
barrels of water per day
MSTB/d
NE
NM
NPV
NPVI
Thousand Stock Tank Barrels per day
North East
Nautical Miles
Net Present Value
Net Present Value Index
NW
North West
OPEX
OWC
Operating Expenditure
Oil Water Contact
PHPA
Partially Hydrolyzed Polyacrylamide
Productivity Index
Profit Investment Ratio
Capital Expenditure
PI
PIR
PRRT
psi
RFT
CO2
Carbon Dioxide
ROP
Rate Of Penetration
CRA
deg
EOB
Corrosion Resistant Alloy
degree
End Of Built UP
RSS
RT
SCAL
Rotary Steerable System
Real Terms
Special Core Analysis
ES
Environmental Statement
SE
South East
ESP
FDP
FPSO
ft
FT
FTHP
GOR
GRV
Electric Submersible Pump
Field Development Plan
Floating, Production, Storage and Offloading
feet
SS
SSSV
STB/d
STOIIP
Subsurface
Subsurface Safety Valve
stock tank barrel per day
Stock Tank Oil Initially In Place
Federal Tax
SW
South West
Flowing Tubing Head Pressure
Gas Oil Ratio
Gross Rock Volume
TVD
TVDSS
True vertical Depth
True Vertical Depth Subsea
WOB
Weight On Bit
H2S
Hydrogen Sulphide
HSE
IRR
KCL
km
Health, Safety and Environment
Internal Rate of Return
Potassium Chloride
Kilometre
Kick Off
Point
KOP
Catenary Anchor Leg Mooring Buoy
LTBR
m
m2
Long Term Bond Rate
MCO
MMb/y
MMscf/d
Maximum Capital Outlay
million barrels per year
million standard cubic feet per day
Metre
Metre Squared
Petroleum Resource Rent Tax
pounds per square inch
Repeat Formation Tester
8
Executive Summary
Location
Timeline
North West Australia Transition Region
Exploration Block: WA-418-p
Water Depth: 80m
Reservoir Unit: Palaeocene sands
Expected Licence agreement
Anticipated Peak Oil Production
Expected Abandonment
Operator
Partners
Mungo Energy
Mungo Energy
Hydrocarbon Estimates
Composition/Content
STOIIP
Reserves
Crude (°API)
GOR (SCF/BBL)
Sulphur (%)
CO2 (%)
420MMbbls
220MMbbls
Figures
2013
2016
2036
100%
33.5
560
0%
1
Economical Analysis
NPV (US$MM 2012)
MCO (US$MM 2012)
NPVI (US$MM 2012)
IRR (%)
4061.8
904.56
4.8
45.5
Table 1 Executive Summary
The W-Field is located in block WA-418-p in the Northwest transition region 160km off of the North
West coast of Australia, 60km from the nearest platform and situated in 80m water depth.
The exploration of the W-field through six drilled wells discovered three hydrocarbon-bearing units,
two of which contain minor reserves and will be ignored for appraisal at this stage. Seismic indicated
the main reservoir is a NW to SE four-way dipping anticline structure, the main sand layers are of
Palaeocene age and were deposited by a deep marine turbidite system these layers are interbedded
with lobes of shale’s which are thought not to be laterally continuous. The OWC datum is around
8730ft TVD, but is an edge drive system. Thus far seismic surveys identified no faults, but leaky faults
have been identified to the North and East from well testing. The average porosity of the Palaeocene
sand is 24% and an average permeability of 230 mD from a range between 100 to 1500 mD.
A most likely STOIIP of 420 MMbbls was calculated from both deterministic and probabilistic
calculations with a recovery factor of between 50 to 60% expected from numerical simulation and
study of analogous fields. Therefore recoverable reserves are estimated to be around 220 MMbbls.
9
The reservoir fluid in place is a sweet, light, under-saturated oil of 33.5 °API with a GOR of 560
SCF/STB, initial reservoir pressure is 3850 psi and bubble point is 1745 psi.
The W-Field will be developed from a steel jacket platform and requires water injection as the
secondary recovery mechanism. The injectors will be drilled from a Jack-Up rig prior to the steel
jacket platform being fixed into position. Phase one expects first oil in September 2015 from the five
existing producers drilled during the appraisal stage, which will be tied back to the platform via
umbilicals. From the platform, phase two consists of drilling six new deviated wells to sustain a peak
production plateau of 80000 BOPD for approximately four years. The W-Field is anticipated to be
abandoned after twenty years production in 2035 or until the economic limit of 1400 BOPD is
reached. A potential third phase of production consists of drilling into the lower Triassic and Permian
hydrocarbon units to increase overall total production and extend field life. Produced oil will be
separated from gas and stored in a Floating Storage Unit (FSU) with the gas utilised for gas lifting,
power generation and export via pipeline to the Angel platform and sold onto market.
From Economical analysis of the proposed production plans it has been identified that the W-Field is
a profitable project, which will benefit from a well worked production plan. A steel jacket platform
was selected as the most profitable solution; taking into account the local environment we are going
to operate in and the relevant economic assumptions the project is expected to yield an NPV of
US$4062 million, from an MCO of US$905 million, with an NPVI of 4.8, IRR of 45.5% and a payback
period of 3 years.
Mungo energy will consider the local existing environment and all environmental sensitivities
surrounding the W-Field in order to minimise damage to the proposed area of development
Upon completion of the project the steel jacket platform will be totally removed to shore for
recycling, reuse or final disposal complying with current UK regulations. All subsea architecture will
be removed and isolated from the reservoir accordingly. The pipeline system put in place will be
trenched and cleaned allowing the local environment to recover to its previous state.
10
1.
Technical Summary
1.1
Field Location
The W-field is located in block WA-418-p, 160km offshore in the Northwest transition region of
Australia in 80m water depth and approximately 60km from the nearest platform, Angel, Figure 1.
The average temperature and weather conditions in North West Australia is mild with the greatest
risk to safety arising from cyclones, which can occur during Australian summer.
60 km
160 km
Figure 1 W-Field Location, North West Australia
1.2
Geology
The W-field is a four way dipping anticline structure which is elongate from northwest to southeast
the form of the structure is due to an underlying salt dome. There are three hydrocarbon bearing
11
units of interest within the W-field; the oldest is a Permian dolomite unit bearing oil, underlain by
anhydrite and the salt dome. The second is a very thin layer of Triassic sandstone bearing oil, which is
overlain by a layer of mid Jurassic coal and shale. The upper Jurassic formation consists of alternating
units of shale and limestone. This epoch is of particular interest because of the microfossil
accumulations within, which is assumed to be the source of hydrocarbons for the main Palaeocene
sand. This is overlain by Cretaceous layers of marl and shale overlain again by thick laterally
continuous layers of limestone and chalk. The third hydrocarbon accumulation lies in the Palaeocene
period this is a series of layered sandstones interbedded with shale. The deposited environment is
shown in the geologist’s interpretation of Figure 2.
The third reservoir has the most promising properties and is therefore the main area of interest and
appraisal at this time. The other two accumulations have insufficient data for appraisal at this time
but are available to be pursued at a later point in the development of the W-Field.
Core’s were recovered from well 2 during its appraisal drilling which allowed the reservoir and
surrounding rock to be analysed, the general description of lithology and rough petrophysical
interpretations are presented in the Table 2 below.
Lithofacies
Geological Description
Ranges of Petrophysical Parameters
Sandstone
Tan to light grey, medium to fine grained,
occasional coarse grains, cemented to friable,
subrounded, fair to poor sorting, feldspars,
pyrite, oil stained
Porosity range: 20 to 26%
Permeability range: 100 to 1500 mD
Unit Thicknesses: 10 – 50ft
Shale
Light to medium grey, firm, pyritic
Porosity range: 0 to 5%
Permeability range: 0 to 10mD
Unit Thicknesses: 5 – 10ft
Table 2 Physical Core Analysis Summary
From interpretation of the structure and seismic survey we can see that depositional environment
originates in the northwest and flows towards the southeast. From physical core analysis the
depositional environment is that of deep marine turbidite system. The sandstone layers are thinning
upwards and contain dish structures, which is indicative of high-energy turbidite flows most likely
12
deposited over a period of minutes. The interbedded shale’s are very fine grains which have been
deposited slowly over decades and centuries from adjacent lobes creating an overlap between shale
lobes and sandstone sheets giving a fairly uniform distribution of petrophysical properties.
Figure 2 Geologists Depositional Interpretation
This has created a reservoir with thick sandstones in the north and west which pinch out towards the
south and east, interbedded with non-laterally continuous shale’s, a North to South correlation
representing this is shown in Figure 11, a West to East correlation is shown in Appendix 1, Figure 4.
1.3
Petrophysical Analysis
Of the six appraisal wells drilled in the W-field five ran wire-line logging tools W1, W2, W3, W4 and
W6, three recovered core samples W2, W3 and W6. Petrophysical properties were determined from
logs and core samples, which proved the Palaeocene sandstone formation was worthy of continued
appraisal. From previous physical core analysis together with log analysis we can confirm the
thinning upwards trend of the sand layers indicate the W-Field is a deep marine turbidite system.
Calculations of permeability and porosity from logs also mitigated the need to further investigate the
Triassic and Permian hydrocarbon units, at this time. Values calculated from the logs were validated
with core analysis, as seen in Table 3, meaning any derived values from log data can be assumed to
be closely representative of the geology in place. All the logs were corrected for depth, borehole
13
stability and temperature then used to calculate water saturation, porosity, permeability and shale
volume for input into the static geo-model. These properties along with gross rock volume from the
geo-model were used as the basis for calculations of hydrocarbons initially in place. Gross pay
thickness ranges from 150 to 270ft thick formations, interbedded with shale.
W1
W2
W3
W4
W6
Net pay
21.57
22.56
25.19
22.42
24.68
26.42
22.46
23.51
AVG Water
saturation
Net
Gross pay
34.62
17.35
37.48
23.33
51.08
53.95
17.93
17.93
25.69
18.08
AVERAGE
22.48
33.36
WELL
Average Porosity
CORE
24.27
19.17
RR/G,
frc
NTG, frc
0.81
0.98
0.95
0.98
0.95
0.77
0.78
0.48
0.97
0.88
0.934
0.85
Average permeability
CORE
net pay
NO CORE DATA
156.19
243
206.23
137
NO CORE DATA
330.18
210
230.87
196.67
Table 3 Reservoir Properties from core sample and log analysis
Porosity values derived from the bulk density log closely match with the core data analysis. The
porosity cut-off value of 10%, which will be used in net pay calculation, is determined by using the
value equivalent to 1mD. Permeability values were derived using the linear relationship between
core porosity and core permeability together with the porosity from bulk density log. Both porosity
and permeability values are most accurate in the sand stone region due to a biasing of core samples
towards the sandstone layers. Meaning the assumptions for matrix density porosity calculations are
from a density log of 2.67 g/cc (i.e. sandstone).
14
OWC
Figure 3 Well 2 log sample from Terrastation indicating OWC and sand bodies
Figure 3 shows a log sample from Terrastation of well 2 indicating the oil water contact at
approximately 8730ft TVD indicated by the rapid spiking increase in water saturation. There are also
clearly visible clean sands, where the bulk density and neutron porosity logs cross over, indicated by
the green shaded area. The W-field possesses two or three thick sand bodies above the OWC which
are continuous across most of the field but do thin out over the crest and pinch out towards the east
and south. The variety of log samples is very useful in representing the reservoir geo-model, but
these could be improved further with physical core data from each well, further refining calculated
values of permeability and porosity used as input into the geo-model.
Statistical analysis was completed on all three sets of core samples, normal and modified Lorenz
plots were created to evaluate the degree of layering and heterogeneity. Lorenz plots and a semivariogram of well 2 data are shown in Figures 12, 13 & 14 Indicating again a layered system similar to
that identified from logs, with two easily identifiable speed zones containing the majority of the
storage capacity of the sampled region. The ordered Lorenz plot yields a Lorenz coefficient of 0.58,
which can be compared with the coefficient of variation, this value is indicative of a heterogeneous
15
system. The Semivariogram identifies the variance of adjacent samples, this yielded a layered system
with beds of approximately 40ft spacing and a long correlation length.
1.4
Reservoir Fluids
Reservoir fluid samples were recovered from various well tests these samples were sent for PVT and
compositional analysis. The results yielded a sweet crude oil of 33.5 °API with no traces of hydrogen
sulphate and very low values of carbon dioxide. The initial reservoir pressure is 3780psi and the
bubble point pressure is 1740psi this close margin along with the lack of aquifer information, from
well testing, indicates secondary recovery will be required early in field development. All the usual
parameters were also calculated, Bo, viscosity etc and utilised during production WellFlo simulations
and reservoir modelling. Formation water samples and sea water samples were also taken to analyse
the risk of scale precipitation. There is a very small risk of Celestine and Anhydrite scale creation
therefore an inhibitor will be added to the injected water once a 30% sea water breakthrough is
seen, to reduce the build up of scale.
1.5
Hydrocarbon in Place
The ranges of gross rock volume, determined from the geo-model, NTG, Porosity, oil saturation and
formation volume factor determined from petro-physical analysis are shown below, Table 4.
GRV(Bbbls)
NTG (%)
PORO (%)
So (%)
Bo (BR/STB)
3-4
77-95
22-26
76-82
1.39-1.35
Table 4 Range of STOIIP Parameters
1.5.1 Deterministic, Probabilistic and Reserves Calculations
Deterministic and probabilistic calculations were completed to improve redundancy of STOIIP
estimations; the range of STOIIP from deterministic was greater but correlates well with the more
refined value from Monte Carlo simulation using Crystal Ball. The most likely value of STOIIP is
around 420 MMbbls. Multiplying this with an average recovery factor of 0.52, which is typical of a
deep marine turbidite system and matches our simulations, to provide an initial estimate for
recoverable reserves of approximately 220 MMbbls. Shown in Table 5.
16
Minimum
Most
Likely
Maximum
281.33
422.87
614.65
Recovery
Factor
0.45
0.5
0.58
Reserves
(MMbbls)
126.60
211.43
356.50
P10
P50
P90
366
420
487
Deterministic
STOIIP
(MMbbls)
Probabilistic
STOIIP
(MMbbls)
Recovery
Factor
0.45
Reserves
(MMbbls)
164.7
0.5
210
0.58
282.5
Table 5 Deterministic and Probabilistic Calculations
1.6
Well Test Analysis
Well test data was available from four wells, W1, W3, W5 and W6 the well tests were performed in
single and multiple layers within the Palaeocene sandstone. Drawdown data was not constant and
therefore only build up data was analysed. Data was sparse and at times unreadable for W3 and W6
,but these tests gave indications of transmissibility throughout the reservoir; W3 indicated a
potential unsealing fault in the North which could impact aquifer support from this region the faults
are shown in Figure 4. Tests from W5 indicated a potential closed system and parallel faults with
decreasing width with depth but are thought to be leaky, which again could impact on aquifer
support in the East. Tests from W1 were best representative of the reservoir which indicates good
horizontal permeability and relatively good vertical permeability. This is due to the nature of the
depositional environment and the lack of continuity between shale layers. Permeability was
calculated to between 120mD and 180mD with an average productivity index 4.59bbls/day/psi which
decreases with decreasing depth which correlates well with what we calculated from well test
analysis.
17
1.7
Reservoir Modelling
The static Geological model of the W-field Palaeocene sandstone reservoir was constructed in Petrel
2011.1 software. Top surface was created based on contours. Correlated logs from exploration wells
helped to understand the degree of layering and reservoir structure which was utilised to represent
the geology. Correlation of the main reservoir sand bodies and shale layers identified the thickness of
each layer and where they pinch out. Sandstone units were divided into three layers each, to reduce
the uncertainty of vertical permeability. Horizons between sandstone and shale units were converted
to surfaces as the basis for facies. The model was created with facies allowing porosity from log data
to be distributed in the 3D model where appropriate. The Co-krigging function was used to distribute
high permeabilities with high porosities. Initially, a fine grid model was up scaled to 51 x 68 x 18 with
62,424 grid cells appropriate for simulation. A grid file with porosities and permeabilities was
exported from the geo-model and used as main input for the hydrodynamic model. Construction of
the hydrodynamic model included SCAL results, relative Permeability curves and PVT data from
reservoir fluid analysis. Samples obtained from well two provided results for Capillary Pressure
Curves and Relative Permeability curves for varying permeabilities and porosities. A representative
Capillary Pressure Curve was determined using the Leverett J-function formula and assuming a
contact angle of zero, average J-function was recalculated back to create an average Capillary
Pressure Curve. Relative Permeabilities of oil to water and oil to gas were chosen so that they would
be representative for different samples. Properties of oil and PVT data were very similar for different
samples. The PVT data, capillary pressure curves and relative permeability curves were used to
simulate the model in eclipse 100 software. In order to better understand the reservoir behaviour
varying sensitivity cases were run. Three cases were run with varying Kv/Kh ratios of 0.01, 0.1 and 1
to evaluate the uncertainty surrounding vertical permeability. Two Natural Depletion Cases were run
one below bubble point and another stopping above bubble point. These cases consisted of
production from six existing wells with initial target rate of 12000 BLPD and bottom-hole pressure of
2450 psi until reservoir pressure declined to 3000 psi with further secondary recovery utilising Gas
18
Lift. The gas Lift target rate is 12000 BLPD and bottom-hole pressure of 1900 psi. New wells in further
cases have been modelled with the same control on bottom hole pressure as gas lift is adopted when
all new producers are brought online. Reservoir pressure declined very fast reducing the production
rates. Well three was converted to an injectr to maintain reservoir pressure and increase production
rates. Results of this simulation were very good, relative to the case of natural depletion. Further
increase in the number of injection wells from one to three gave even better results in terms of Oil
Recovery Efficiency, due to an ever increasing reservoir pressure. To increase coverage of the
reservoir, new deviated wells were brought onto production. The number of producing wells was
increased until reservoir pressure started to decline. Pressure maintenance became one of two main
tools to improve production as well as the number of production wells. Increasing the number of
production and injection wells yielded very similar results for the cases with five to six injectors and
ten to thirteen production wells. As it can be seen from Figure 26 The case with eleven production
and five injection wells has an Oil Recovery Factor of 58% and cumulative production of 273 million
STB of oil, which is a know uncertainty from our modelling assumptions. Cases with greater number
of wells ended up with small differences in recovery so any further increase in the number of wells is
not efficient in terms of reservoir management. The case with eleven production and five injection
wells is recommended as the most effective reservoir development case. The details of this
production plan are described in Table 6 below. Gas injection and water injection separately into the
reservoir crest were modelled to identify any potential methods of improving recovery efficiency.
Both of these trialled cases were found not to be effective enough and water injection into the oilwater contact zone was decided upon as the main secondary recovery mechanism. Polymer flooding
was trialled and aimed to improve mobility while reducing the water cut of the produced fluid,
however the reduction in water cut caused less effective reservoir pressure support. Resulting in a
very low recovery factor along with the added cost of the polymer meaning this case is ineffective
both economically and in terms of improving production efficiency.
19
Number of wells
Plateau oil production rate
Plateau duration
Plateau liquid production rate
Plateau water production rate
PLateau gas production rate
Injection rate
Injection fluid
Field life
11 producters/5injectors
80000 b/d
4 years
100000 b/d
3500 b/d
45 MM scf/d
20000 b/d/well
Water
20 years
Table 6 Production Plan
1.8
Economic and Commercial Considerations
After evaluating Mungo energy’s current financial situation the following conclusions can be made:

80% of the NPV is concentrated in Africa

Large amount of assets in current portfolio

Debt of the company should be carefully controlled
Knowing the situation of the company and after studying the project carefully, it is thought that the
development of the project will be very important for the growth of Mungo and ensure a good
financial position after the payback period has passed. Although funding the project on our own
would be possible and could have associated positive aspects it is also very risky, a farm-in would
provide part of the CAPEX needed to develop this project and will spread some risk of investment to
other partners. The ideal company for this operation would be Shell, since it is a company that has
shared partnership successfully with Mungo in previous projects and it is a company with a large
presence in Australia, which could help in cost reductions from Shell’s previous knowledge of the
Australian Market.
The project was analysed in the existing environment and Team W can confidently prove the
profitability of the project over a production life of twenty years. Developing this asset will help to
ensure the growth of the company, since the projected production schedule predicts a peak plateau
of almost 80,000 STB/d starting in 2015 and lasting for almost four years.
20
Having an estimated recoverable reserve of 220MMbbls, production of block WA-418-P was
evaluated using different numbers of wells for production and injection, with the most efficient case
being 13 producers and six injectors. After evaluating the economic parameters for the established
scenarios, it was found that the most efficient in economic terms was not the one given by
engineering analysis it is the case where the reservoir was produced using eleven producers and five
injectors. The recovery factor of this economic optimum was smaller than the engineering optimum,
but since drilling two more wells would not make our production increase significantly, the NPVI is
greater and the MCO is smaller, having almost the same payback time four years and an IRR of
45.5%.
Given the size of block WA-418-P and its location, the use of a fixed platform is suggested. The
characteristics of the field and the development strategy was input into Que$tor, which gives results
of the Investment profile, taking into account the production profile and the specifications for
artificial lifting, number of wells, etc. This investment will imply a total CAPEX of US$1,112 million
which in the cash flow of the project will result in a MCO of US$915 million and results in a
substantial NPV of US$4.140 billion, meaning an NPVI of 4.8.
A sensibility analysis was performed on the project cash-flow, showing that the NPV has a direct
relation with production and price of the oil, while the taxation situation imposed by the government
is the most critical parameter.
1.9
Field Development Plan
The W-Field development can be divided into two and possibly a third stage, with the first utilising all
existing wells and pre-drilling injector wells. W3 will be converted to an injector and a Jack-Up rig will
pre drill another four injector wells from January 2015 to the end of April 2015 before the steel
jacket platform is moved into position during May 2015. This strategy to utilise existing wells and pre
drill injector wells will reduce CAPEX before production. Because of the high uncertainty surrounding
aquifer support water injection will commence from the start of production, all existing wells will be
21
brought onto production in September 2015 with a strict control on injection rate to reach a plateau
of 80,000 BOPD for approximately four years. Due to the high uncertainty surrounding the continuity
of shale layers, faulting, subsequent transmissivity and aquifer support this stage of production will
provide more information on reservoir characteristics and either confirm or contradict our modelling
assumptions. All new development wells are displayed with stars in Figure 4 below.
The second phase utilises information from the first phase of production and the steel jacket
platform to drill six deviated wells, starting from June 2015, from the in place platform and brought
online sequentially from September 2015 to May 2016, to sustain the plateau. The field will be
produced for approximately twenty years or until the economic limit of 1400 BOPD has been
reached.
22
Figure 4 Top Structure Map, Indicating Development Wells
There is potential for a third phase in the project, this will involve production from the Triassic and
Permian hydrocarbon accumulations. Existing wells experiencing high water cuts from the
Palaeocene sands can be worked over and drilled into the lower formations to explore their potential
further. With the low permeability and porosity measured from log data it may be feasible to
produce from these zones after fracturing and acidizing. This plan can be attempted before the
economic limit is reached or before the field is abandoned.
Each vertical well is expected to produce between 7/8 MMScf/d and deviated wells are expected to
produce approximately 5 MMScf/d. Gas will be used for power generation and primarily 4 MMScf/d
23
per well will be required for gas lifting. Therefore we have a surplus of approximately 16 BScf/y,
during the plateau period. Gas injection into the crest and into the Triassic aquifer was investigated
but didn’t improve production therefore this excess gas will be exported via pipeline to the Angel
platform and then onto market.
1.10 Drilling
The W-Field is situated in water depth of 262 ft and is a soft to medium strength, normally pressured
formation with the exception of an 800 ft thick over-pressured interval above reservoir. Typically
target depth is expected to be 8300 ft TVD. For deviated wells, a length of about 5000 ft is estimated
for typical horizontal displacement. The completion of six existing wells and drilling of four new
vertical injection wells will be drilled from a jack up rig while six new deviated producer wells will be
drilled from a rig installed on the steel jacket platform. Deviated wells will be drilled using a rotary
steering system with well equipped MWD tools; tangent angles range from 40 to 45 degrees and the
kick of point (KOP) is below 1800 ft TVD. All the wells will be completed using a Christmas tree rated
to 5000 psi. 30’’, 20’’, 13 3/8’’ and 9 5/8’’ casing configuration will be cemented in place with 7’’ wire
wrapped screens across the reservoir interval for controlling sand production.
The drilling programme, briefly summarised in Table 7, starts with drilling four vertical injector wells.
This will then be followed by drilling six more deviated producer wells. The drilling of first injector
well will start early January 2015 and each injector well is expected to take approximately a month
(28days) to drill and complete. By the end of June 2015, all the injector wells are expected to have
been drilled and completed. The drilling of first new deviated producer well will start early June 2015
and each of the deviated wells will be completed within one and half months (average of 38days).
There will be measurements while drilling to gather more information and coring to provide more
physical analysis to hopefully reduce some geological uncertainty.
Environmental considerations are based around guidelines outlined by the Department of Energy
and Climate Change (DECC). For safety reasons, while drilling, an overbalance shall be maintained at
24
all times while safety factors of 1.1 and 1.0 have also been incorporated for design of casing burst
and collapse loads respectively. Water based mud will be used. The mud will be modified using
environmentally friendly additives such as polymers when reactive formations are encountered while
drilling through the formation. The pay zone will be drilled using non damaging drilling fluid. All the
cuttings will be disposed of to the sea bed after being certified by the environmental supervisor.
Interval
depth
(feet)
262 514
514 1485
1484 4969
4969 8220
8220 8480
Hole
Size (
Inches)
26
17 1/2
12 1/4
8 1/2
Mud
weight
Type (ppg)
sea
water water
Pore
Pressure
(ppg)
30
WBW
9.0
8.5
WBM
9.5
9.4 9.8
8.95 9.8
8.5 - 9.0
WBM
WBM
Size
(ft)
8.8 - 9.5
20
13
3/8
9
5/8
Casing
Setting
depth
Grade
Cementing
weight TOC
Type (ppg)
(ft)
514
14855
J-55
4969
L-80
8220
L-80
8.5 - 9.0
class
G
class
G
class
G
BOP
rating
(psi)
Cummulative Days
vertical deviated
wells
wells
5000
4
4
10.0
262
5000
6.2
6.2
11.0
1185
5000
14.2
16
12.0
4669
10000
25.2
32
10000
28.2
38
Table 7 Summary of Drilling Program
1.11 Production and Process Facilities
The W-Field main Palaeocene reservoir consists of weak sandstone with a uniform medium to fine
grain size distribution. To mitigate against the expected sand problem, we will use a wire wrapped
screen in our completion. The final well design, to maximize the liquid recovery, is an open hole
completion with wire wrapped screen and 5.5” production tubing as seen in figure 5. The open hole
completion within the reservoir interval will provide the maximum inflow capacity without any
limited entry skin. Gas lift will be used early on in production to maximize the production rate.
Pressure maintenance through water injection will be used before production to maintain the
reservoir pressure above bubble point.
25
Figure 5 Well completion design
The W-Field will utilise a steel jacket production platform which will be capable of handling 80,000
BOPD, 92,000 BWPD, 45,000 MSCFPD and 100,000 BLPD at their respective peak production rates.
Three stages of three phase separators will be used to separate between oil, water and gas from the
subsea manifold. The oil will be stored in a floating storage unit (FSU) and then transported to the
refinery using two shuttle tankers. On the other hand, the gas will be processed and transported to
the nearby Angel platform and then sold on to market. Wellheads with pressure ratings of 5000 psi
will be used for all producer wells and a pressure rating of 10,000 psi will be used for all injector
wells. This is based on the maximum operating pressure and the maximum reservoir pressure that
will be achieved during the production and injection. Subsurface safety valves will be designed at 850
ft as a secondary safety device in case of wellhead failure. Dynamic seals will be used between
26
production tubing and packer to allow tubing movement due to temperature change in the system.
In addition, down hole measurement systems will be installed in some wells to monitor the reservoir
pressure and temperature to determine the future action for the field development.
Water analysis, as shown in Table 8, shows the possibility of scaling problem due to the presence of
calcium and strontium. Scale inhibitors will be injected to prevent the incompatibility between sea
water and formation water. There is no H2S detected in the reservoir; however a significant amount
of CO2 is detected which may cause a corrosion problem. Corrosion resistant alloy steel will be used
in the system to avoid the corrosion effect from CO2.
Cations
Sodium (Na)
Potassium (K)
Calcium (Ca)
Strontium (Sr)
Barium (Ba)
Ammonia (NH3)
Ammonium (NH4)
Magnesium (Mg)
Concentration (ppm)
21300
320
2700
373
4
3
55
204
Anions
Chloride (Cl)
Bromide (Br)
Iodide (I)
Sulphate (SO4)
Phosphate (PO4)
Bicarbonate (CHO3)
Carbonate (CO3)
Concentration (ppm)
37900
212
14
216
5
320
0
Table 8 Water Analysis
1.12 Production Plan
PRODUCTION PROFILE
BOPD
90,000
80,000
70,000
60,000
50,000
40,000
30,000
20,000
10,000
0
2015 2017 2018 2020 2022 2023 2025 2026 2028 2030 2031 2033 2035
Year
Figure 6 Production Profile
The production profile above, Figure 6, has a brief period of zero production while new development
wells are being drilled, shown in structure map Figure 4. The large increase in production occurs over
a sixty day time step, the wells brought online at this time are the five existing vertical producers,
27
from this point on towards the plateau the newly drilled deviated wells are brought online. These
wells should operate at a cumulative 80,000 STB/d to sustain the plateau for almost four years.
Production is expected to last for 20 years or until the economic limit of 1400 BOPD is reached.
Bottom hole pressure will not fall below bubble point so as to keep the field under saturated and oil
mobility as high as possible. This pressure retention will be satisfied by water injectors which should
inject below a bottom hole pressure of 5000 psi so as not to fracture the formation.
This production plan is subject to well and reservoir monitoring. If the reservoir conditions are as
predicted and no major intervention work has to be completed then production can be expected to
terminate around year 2035 or until the field becomes uneconomic.
1.13 Environmental Impact and Abatement
An environmental study has been completed to assess the impact that may arise from the proposed
operations and to identify measures, which will be put in place to minimize these effects. The local
environment has been investigated and the main threat to personnel and the project are cyclones,
which can occur during the wet season. There are many fish species, mammals and seabirds
identified in this region, these will be considered during the construction, operation and
decommissioning of the platform with the least amount of disturbance to the local environment as
possible.
Mungo Energy is committed to following the appropriate mitigation measures properly, as they are
described in the attached ES, in order to minimize the effects on the environment. Overall, it is
therefore concluded that the environmental impact during the W-Field development will not incur
any significant long lasting environmental effects.
1.14 Field Abandonment Programme
The steel jacket and topside facilities required to develop the W-Field will be removed, reused,
recycled or disposed of abiding to current UK environmental regulations. Decommissioning and
abandonment costs have been covered during economical analysis, detailed in this document.
28
WELL ABANDONMENT
At the end of project life, all the wells will be plugged in order to ensure that the reservoir unit is
isolated properly from surface. Conductors and casing facilities are recommended to be cut and
covered ten feet below the seabed.
STEEL JACKET
According to the relevant legislation, the steel jacket will be completely removed for reuse or
recycling or final disposal on land.
PIPELINES
According to the relevant legislation, Mungo Energy considers the best option for decommissioning
of pipelines to leave them in situ. Consequently, the environment can cover them from itself and
there will not be further disturbance on the seabed from their removal.
DRILL CUTTINGS
Mungo Energy proposes that in the case of the cuttings, a critical valuation should be done in
accordance with the relevant legislation, in order to identify whether removal or disposal in the field,
is the most appropriate method.
29
2.
Field Description
2.1
Geology
2.1.1 Structural Configuration
From analysing the top structure map, Figure 7, and seismic image, Figure 8, the W-field forms a
four-way dipping anticline structure elongate from northwest to southeast, the origin of deposition is
from NW to SE. The seismic image does not have any noticeable faults, while well testing indicated
parallel faults in the eastern region of the structure and an unsealing fault towards the north, which
are all believed to be leaky indicated below. The depth to top of structure is 8085 ft TVDSS, this is a
Palaeocene formation consisting of massive sandstones interbedded with shale and mudstones
sealed above by a clay formation. Below this a large chalk formation is present overlying Jurassic
limestone and shale accumulations, which are organic-rich and thought to be the source of the
hydrocarbon play. There are a further two hydrocarbon bearing bodies in deeper Triassic sandstone
and deeper Permian dolomite. Underlying this there is a salt dome, elongate from southeast to
northwest. The OWC of the Palaeocene reservoir is approximately 8730ft TVD shaded in blue below.
Figure 7: Top Structure Map
30
Palaeocene, Sandstone
Chalk
Limestone
Salt
Figure 8: Seismic Survey
Clay
Palaeocene Sandstone
Interbedded Shale
Chalk
Limestone
Coal
Triassic Sandstone
Permian Dolomite
Salt
Marl/Shale/Siltstone
Figure 9 Geologists Depositional Interpretation
2.1.2 Depositional Environment
The main reservoir sandstone units have been deposited by a deep marine high-energy turbidity
current, with multiple-source systems. This is a mud system which is rich in sand therefore the
principal architectural elements are depositional lobes shown in the, Figure 10, below. The high net
to gross above 70% and the structural form of the reservoir trap created by clay indicates a sand rich
submarine fan system. Multiple sources create overlapping lobes and sheets. This hypothesis arises
from petrophysical log, core data, research into related depositional systems and analogue fields:

Visible changes in lithology from, chalk to sandstone and shale.
31

Thinning upwards of the sandstone beds containing visible dish structures is characteristic of
rapid deposition from turbidity flows

Shale and mudstone is very fine which would indicate constant slow depositional
environment from adjacent lobes. (Appendix I, Figure 3)

Shale is not laterally continuous throughout the reservoir they more conform to plate like
structures containing areas for vertical communication, which would indicate they have been
eroded by layer upon layer of turbidite sheets.
Figure 10 Depositional Environment
2.1.3 Stratigraphic Correlation
The Palaeocene reservoir is clearly a layered system as indicated from the correlations completed in
Petrel; gamma ray was used to correlate between wells as it represents the best difference between
layers. The up scaled yellow and green blocks indicate sandstone and shale respectively, with a GR
reading of less than 28gAPI being sand. The sand is thickest in the North, W3, and thins out towards
the south, W4, which is visible in Figure 11 this is due to the northwest direction from which the
sandstone was deposited. The same is true for Appendix, Figure 4 but sand is thickest towards the
west and thins out towards the east. The sandstones are laterally continuous throughout the
32
Palaeocene zone but this is not the case for the shale layers, which pinch out and are eroded at
greater depths in the formation.
Figure 11 North to South Correlation
2.1.4 Rock Properties
The main Palaeocene reservoir consists of massive sandstones interbedded with shale and cemented
sandstones. From physical core analysis of W2, Appendix I, Figure 3, the massive sandstones are fine
to medium grained, rounded, friable to cemented just above the shale layers and moderately sorted.
The sand layers range from 10 – 50 ft thick and have no significant structures but possess vertical
streaks and dish structure, which indicate quick de-watering of the sandstone. High-energy turbidite
submarine fan lobes therefore deposited the sandstone. The stacked massive sand sequences have
no discernible features or bedding forms they consist of layers fining up overlain by coarse layers of
sand which is again indicative of high energy turbidity currents. These sandstones are laterally
continuous over each interval while pinching out towards the East and South of the formation.
33
The fine grain interbedded mudstone and shale occur in units of approximately 5 - 10ft thick. These
will have been deposited over a much longer length of time compared to the sandstone and are seen
as not being laterally continuous therefore the reservoir could posses compartmentalisation or
productive vertical flow paths.
2.1.4.1 Physical core analysis
Core samples were recovered at various depths from well 2, 3 and 6 but only selected core from the
Palaeocene region for well 2 was available for physical analysis. More samples were also taken from
the second suspected reservoir in the Triassic sandstone, but none of these are available for physical
analysis. The core samples pictured in Appendix I, Figure 3 show cemented sandstone just above the
shale layer, this is due to chemicals emitted from the shale cementing the sand in place. Above this
the core is stained with oil and friable indicating greater pore space. The core above the cemented
zone is friable meaning there will be a need to install sand control measure down hole. A physical
inspection of the cores recovered yielded the following characteristics, Table 9:
Lithofacies
Geological Description
Ranges of Petrophysical Parameters
Sandstone
Tan to light grey, medium to fine grained,
occasional coarse grains, cemented to friable,
subrounded, fair to poor sorting, feldspars,
pyrite, oil stained
Porosity range: 20 to 26%
Permeability range: 100 to 1500 mD
Unit Thicknesses: 10 – 50ft
Shale
Light to medium grey, firm, pyritic
Porosity range: 0 to 5%
Permeability range: 0 to 10mD
Unit Thicknesses: 5 – 10ft
Table 9: Lithology evaluated from core analysis
2.1.5 Geological conclusions, uncertainty and risk
From the geological investigations we can draw the following conclusions: the Palaeocene reservoir
is the main target for development. The Triassic and Permian reservoirs are potential future targets
later into the development of the field, if they are economically viable. Reservoir thickness towards
the East is fairly unknown because the W-field posses no hard or soft copy log data. Continuity of
shale bodies, these pinch out, are eroded and not laterally continuous over parts of the reservoir.
Potential sealing faults reducing flow from the northern part of the reservoir and maybe some
34
degree of compartmentalisation identified from well testing. All these uncertainties could be further
investigated with 3D seismic data and extended well tests. Aquifer support is generally unknown and
hard to determine, especially in the East side of the field and may deteriorate due to faulting
interpreted from well test and unknown geological flow paths. Core is friable and therefore sand
production is likely which reduces available choices of production facilities, subsea equipment is not
an option due to the expected high levels of sand production resulting in difficulties with clean up
and work over.
2.1.6 Geostatistics
2.1.6.1 Reservoir Description From Core Analysis
The following statistical analysis was completed to better understand the degree of heterogeneity,
permeability and porosity within the reservoir. Results are contained below for the Palaeocene,
Table 10, and for the Triassic reservoir, Table 11.
Well
Producing
Interval
Ns
Av. KAr
(mD)
Average
Porosity. Ø
Cv (Khor)
N0 (20%)
Ps(%)
2
8620 - 8880
148
322.53
22.57
0.86
74
-
3
8800 - 8980
17
206.23
18.14
0.80
65
39.01
6
8170 - 8380
101
336.47
22.70
1.30
168
25.81
Table 10 Summary of Statistics for Palaeocene Reservoir
Well
Producing
Interval
Ns
KAr (mD)
Ac. Ø
(%)
Cv (Khor)
N0 (20%)
Ps(%)
2
10472.5 -10653
148
0.42
12.14
.49
24
8.05
Table 11 Summary of Statistics for Triassic Reservoir
The arithmetic average was selected as it best represents the permeability over the layered W-field
reservoir with a resulting range of 206.23 to 336.47mD. The turbidite fan system has a coefficient of
variation (Cv) which shows high heterogeneity in wells 2 and 3 while well 6 has a Cv > 1 indicating a
very heterogeneous system. Well 2 is the best representative case because sufficient samples were
recovered for analysis with the samples recovered from wells 3 and 6 being insufficient, for accuracy
35
permeability properties were distributed in the model using derived permeability from log data. Core
porosity was averaged using arithmetic average and samples were sufficient for property modelling.
The statistics generated from the core data taken from the Triassic region of our formation indicates
low porosity of 12.14% and very low permeability of 0.42mD, all samples at this depth meet sample
sufficiency requirements. Therefore we are choosing at this time to appraise the much larger
Palaeocene sands. With the intention of further investigating both the lower reservoirs with the
intention of improving permeability by fracturing and acidising if required.
2.1.6.2 Lorenz plots
Lorenz plots utilise core porosity and permeability to represent the degree of transmissibility as a
function of storability while modified Lorenz plots can indicate the extent of layering within the
reservoir. The Lorenz plot in, Figure 12, for well 2 yielded a Lorenz coefficient of 0.58 which is
heterogeneous, which correlates with the coefficient of variation.
Cummulative K/Ktotal
Lorenz plot Palaeocene Reservoir Well 2
1
0.8
0.6
0.4
0.2
0
0
0.2
0.4
0.6
0.8
1
Cummulative Φ/Φtotal
Figure 12 Well 2 Lorenz Plot
The varying gradient of the black line on the modified Lorenz plot, Figure 13, below indicates layering
within the Palaeocene sands. The higher gradient lines are speed zones which indicate high perm
layers with the less steep lines indicating low flow layers. This layering will need to be represented in
the geological model as it will impact on recovery.
36
Cummulative K/Ktotal
Modified Lorenz plot Palaeocene
Reservoir - Well 2
1
0.8
0.6
0.4
0.2
0
0
0.2
0.4
0.6
0.8
1
Cummulative Ø/Øtotal
Figure 13 Well 2 Modified Lorenz Plot
2.1.6.3 Semi-variogram
Various semi-variograms were created to assess the variation of permeability between adjacent core
samples. The semi-variogram below, Figure 14, from well 2, is cyclical meaning it represents
repeating geological units i.e. the degree of layering over the interval 8621 to 8821 ft. The nugget is
approximately 0.59 indicating both errors and heterogeneities in the data, the error is due to sparse
data over the interval investigated. The long correlation length further indicates a layered system.
The vertical correlation length of approximately 40ft indicates the length between adjacent beds in
terms of permeability.
Information gathered from statistical analysis was used as an input for distribution of petrophysical
properties in petrel. Due to the large spacing between wells and the lack of data laterally between
wells major and minor correlation lengths were estimated using the static model. The estimations
were indicative of turbidite sheets.
37
Semivariogram Palaeocene Reservoir
8621 - 8821 ft
Normalised Gamma
2
1.5
1
0.5
0
0
10
20
30
40
50
60
70
80
Lag (ft)
Figure 14 Well 2 Semi-Variogram
2.1.6.4 Kv/Kh Ratio
Vertical permeability data is only available for well 6 limiting interpretations of the W-field Kv/Kh
ratio. The cores taken are biased towards the high perm sand zones, but they give an indication of
the degree of anisotropy within the Palaeocene sands. There is greater spatial variation in the upper
two layers that were sampled with approximately 50% of the Kv/Kh values above a ratio of 1
indicating that gravity will contribute to the flow pattern and reduce piston like displacement in
these layers. The lowest layer is isotropic with values lying around 1 or lower indicating gravity will
have a reduced effect in this layer providing greater piston like displacement. From this we can
probably expect to get earlier water breakthrough in anisotropic layers, this is difficult to model
correctly in the geomodel, but to have as accurate a model as possible recovery we can vary Kv/Kh in
the dynamic model and analyse the effect. A plot of Kv/Kh Fraction Vs Depth is shown in Appendix I,
Figure 2.
2.2
Petrophysics
Five wells were run with wireline logs, this data along with the core samples for three wells
mentioned earlier in the report were used to derive various petrophysical properties using
TerraStation software. The derived properties such as porosity and permeability were compared with
core data and well test results to confirm reliability. Three potential reservoirs were identified from
38
logs a Paleocene sandstone, Jurassic-Triassic sandstone and Permian dolomite. Our main interest in
this development project is the Paleocene sand which has the thickest layer of sand and the lowest
water saturation. Paleocene sand has an average porosity of 24% and permeability of 230 mD (based
on core data). It has several thin layer of shale which separates the sand body. The average
temperature of this reservoir is 244°F.
Before the well log data is used for analysis it was checked with hard copies for any discrepancies, it
has to be corrected by creating a constants table for each well and depth matched. Core data from
Well 2 was depth matched based on real observations in the core store visit. Wells with a very small
vertical displacement or without directional survey data will be treated as a vertical well. For analysis
purpose, the logs will be zoned by its reservoir interval. The petrophysical properties for the
Palaeocene reservoir are derived for the gross rock volume investigated and the net pay layers within
this gross volume, the results are displayed in Table 4 below. Three wells penetrated the Triassic
reservoir of which only two possessed core data, with the results displayed in Table 5. From the
results we can see the values for log porosity and permeability are again considerably lower than our
Palaeocene reservoir and therefore not worth appraising at this time, which is the same conclusion
we came to earlier when completing statistical core analysis.
2.2.1 Determination of shale volume
The shale volume was calculated by using linear model and gamma ray as an input curve. The cut off
parameter was 30 API for clean sand and 110 API for shale. The cut off value has been confirmed
with the core samples in Well 2.
2.2.2 Determination of permeability
The permeability value was calculated by crossploting the core porosity and permeability to generate
the appropriate linear relationship. The porosity (density) is then used as an input to calculate the
permeability by using the linear relationship. Because of the linear relationship, some value of the
39
permeability will not be representative for certain interval with high porosity. This derived
permeability was used for property distribution in Petrel.
2.2.3 Determination of lithology
Lithology can be determined using 2 types of crossplot: Bulk density vs. Neutron porosity and M-N
plot (Figures 1 & 2, Appendix II). The data points from logging are imported to the curve and overlaid
by standard curve and interpreted. This lithology plot was then confirmed by matching with physical
core interpretation and the interpretation of lithological logs and crossplots. Summary tables below
for the Palaeocene reservoir, Table 12, and for the Triassic reservoir, Table 13, compare results.
WELL
22.46
21.57
25.19
24.68
26.42
23.51
AVG Water
saturation
Net
Gross pay
34.62 17.35
37.48 23.33
51.08 53.95
17.93 17.93
25.69 18.08
22.48
24.27
33.36
Average Porosity
CORE
W1
W2
W3
W4
W6
AVERAGE
Net pay
22.56
22.42
19.17
RR/G,
frc
NTG, frc
0.81
0.98
0.95
0.98
0.95
0.77
0.78
0.48
0.97
0.88
0.934
0.85
Average permeability
CORE
net pay
NO CORE DATA
156.19
243
206.23
137
NO CORE DATA
330.18
210
230.87
196.67
GROSS = the reservoir sand (with oil and water)
net pay = the reservoir sand which contain only oil
Reservoir interval
W1: 8314-8464
W2: 8618-8882
W3: 8800-8980
W4: 8250-8390 TVD (10389'-10583' MD)
W6: 8180-8380
Gross thickness
150
264
180
194
200
Table 12 Log Analysis of Palaeocene Reservoir
WELL
Average Porosity
CORE
W1
W2
W3
W4
W6
AVERAGE
Net pay
AVG Water
saturation
Net
Gross pay
RR/G,
frc
NTG, frc
Average permeability
CORE
Gross
12.21
12.89
14.49
17.99
48.4
85.73
39.04
85.73
0.61
0.72
0.60
0.0023
0.41
4.07
1.57
3.3
12.55
16.24 67.065
62.39
0.665
0.30
2.24
2.435
GROSS = the reservoir sand (with oil and water)
40
net pay = the reservoir sand which contain only oil
W2: 10470'-10690'
W3: 10640'-11300'
220
660
Table 13 Log Analysis of Triassic Reservoir
2.2.4 Determination of porosity
The porosity value can be derived from several logs such as density, neutron-density and neutronsonic. The model which matches closely with the core result was the density models. The porosity
value was then derived from bulk density log and corrected by using the shale volume which had
been calculated before. The input parameters are assumed as a normal sand shale formation, fluid
density: 1 g/cc (water), matrix density: 2.67 g/cc (sand) and shale density: 2.45 g/cc.
2.2.5 Determination of water saturation
There are many models to calculate the water saturation. The famous methods are Simandoux and
Archie's equation. Simandoux model will tend to underestimate the water saturation. On the other
hand, Archie's equation will tend to overestimate the water saturation in shale zone but it will give a
reasonable match with core values at lower shale contents. Our main interest, the Paleocene sand, is
very clean with low shale contents making the Archie model the most suitable model for this
situation. Archie's model use porosity (density) and deep induction resistivity as the input curves.
The generic rock properties for sandstone were input in the Archie equation, A: 0.62, M: 2.15 and N:
2.00.
With the Archie equations as:
2.2.6 Determination of net pay
The determination of net pay thickness cut off parameters will have a great effect on the project’s
economics. The cut off parameter used is 40% for Vshale, 50% for water saturation and 10% for
porosity. This is based on the comparison between log data and core data on W2.
41
2.2.7 Oil Water Contact
The OWC contact was suspected to be around 8740 ft TVD from hardcopy logs and indicated on
Figure 15 below with a blue dashed line. This was confirmed through analysis of a combination of
resistivity and water saturation logs.
OWC
Figure 15 Well 2 log sample from Terrastation indicating OWC and sand bodies
2.2.8 Stress Sensitivity
We posses no stress sensitive core data, but we don’t notice any large variations in core and log
derived petrophysical properties. A minimal variation between data is pleasing as it indicates that our
sandstone is not susceptible to stress sensitivity and can therefore be ignored.
2.2.9 Petrophysical Uncertainties

Intuitively we would expect 100% water saturation below the oil water contact, but the
method for deriving water saturation is flawed because this is derived from the resistivity log
which will measure irreducible trapped oil as moveable oil therefore underestimating water
saturation. The water saturation curve displayed on Figure 15 shows lower than expected
water saturation below OWC because of this.
42

RFT surveys could be completed to get a better picture of fluids at specific intervals and the
pressure gradients at these points.

Derived permeability can be overestimated quite dramatically; this is because of a linear
correlation between core porosity and core permeability. The derived permeability is
therefore only accurate for porosities below 30% anything above this will yield huge
unrepresentative values of permeability; an example is shown in Appendix II, Figure 3. These
high permeabilities were filtered out before distribution in the geomodel.
2.3
Hydrocarbon in Place
A range of values shown in, Table 14, were taken from geological, petrophysical and PVT data for the
deterministic and probabilistic calculations of stock tank oil initial in place.
GRV(Bbbls)
NTG (%)
PORO (%)
So (%)
Bo (BR/STB)
3-4
77-95
22-26
76-82
1.39-1.35
Table 14 Range of STOIIP Values
2.3.1 Deterministic and Probabilistic Model
The deterministic calculation used pessimistic, most likely and optimistic values from the table above
to calculate STOIIP. For probabilistic calculations Monte Carlo Simulation was run using ranges
defined from triangular and normal distributions in Crystal Ball software which determined a
probabilistic STOIIP shown here in, Table 15, and the probability of producing 10%, 50% and 90% are
in Figure 16.
Deterministic
STOIIP
(MMbbls)
Minimum
Most Likely
Maximum
281.33
422.87
614.65
Probabilistic
STOIIP
(MMbbls)
P10
P50
P90
366
420
487
Table 15 Deterministic and Probabilistic Calculation
43
Figure 16 Reverse Cummulative Frequency STOIIP Probabilities
2.3.2 Uncertainties Associated with HCIIP Determination
Each parameter has a percentage of variation associated with the estimations of STOIIP and from
Figure 17 below, taken from crystal ball, we can identify gross rock volume as the largest uncertainty
in this calculation. The reason for this is due to the uncertainty of the OWC datum across the
reservoir. Deterministic calculations were used to calculate a wide range and probabilistic was used
to refine the values and confirm a most likely estimation of STOIIP.
Figure 17 STOIIP Sensitivity Analysis
2.3.3 Reserves
Recovery factor was chosen to range between 45 to 58% from analysis of analogous fields and
simulation results, giving reserves estimation for both deterministic and probabilistic of, Table 16:
Deterministic
STOIIP
(MMbbls)
Recovery
Factor
Minimum
Most
Likely
Maximum
281.33
422.87
614.65
0.45
0.5
0.58
44
Reserves
(MMbbls)
Probabilistic
STOIIP
(MMbbls)
126.60
211.43
356.50
P10
P50
P90
366
420
487
Recovery
Factor
0.45
Reserves
(MMbbls)
164.7
0.5
210
0.58
282.5
Table 16 Calculations of Reserves
2.4
Reservoir Fluids
Reservoir fluid samples were recovered during Drill Stem Testing with very little variation in
properties between each sample. The reservoir is under-saturated with an average reservoir
pressure is 3850 psi, bubble point is 1745 psi, reservoir temperature is approximately 248°F and the
hydrocarbon in place is sweet light crude of approximate weight of 33.5° API. PVT data was examined
from well 1 and 5 displayed in Table 17.
2.4.1 PVT Data
Property
Oil Density
Oil Type
Viscosity
Reservoir Pressure
Bubble Point
GOR
Oil Formation Volume Factor
Reservoir Temperature
Range
33.5
Black
0.705
3852
1745
580
1.4
248
Unit
°API
cP
Psi
Psi
SCF/STB
RB/STB
°F
Table 17 Approximated PVT data for reservoir conditions
2.4.2 Hydrocarbon/Chemical Composition
Hydrocarbon analysis of separator products for well 4 are shown below in Table 18. The hydrocarbon
is black oil with no hydrogen sulphate and minute amounts of carbon dioxide which is promising
when designing production systems.
Component
Hydrogen Sulphide
Carbon Dioxide
Nitrogen
Methane
Separator Liquid Mol %
Nil
0.02
0.46
5.22
Separator Gas Mol %
Nil
0.88
1.03
78.14
45
Ethane
Propane
Iso-Butane
n-Butane
Iso-Pentane
n-Pentane
Hexanes
Heptane plus
Total
3.54
7.07
1.42
5.47
2.17
2.72
6.91
65
100
10.06
6.78
0.65
1.64
0.26
0.33
0.13
0.1
100
Table 18 Hydrocarbon analysis of separator products (Well 4)
2.4.3 Water Analysis
Water samples were taken from well W2 on DST#4 and are representative of the whole reservoir,
Table 19. The method used for taking the sample was reverse circulation between 8746’-8748’. This
water contains 59,000 ppm of NaCl which has a resistivity (Rw) of 0.113 ohm meter at 77°F or 0.055
ohm meter at reservoir temperature. The water pH is 7.98 and it doesn’t contain any significant H2S.
The water sample shows that the barium content in the formation water is very small (4 ppm) which
less likely will create barite (BaSO4) scale. The problem is in the Strontium and Calcium, if those ions
meet Sulphate ions from sea water, they will precipitate and create Celestine (SrSO4) and anhydrite
(CaSO4) scale. SrSO4 will become more soluble as the temperature decreasing while on the other
hand; CaSO4 can be precipitated due to cooling. Sea water samples are shown in Table 20.
Cations
Sodium (Na)
Potassium (K)
Calcium (Ca)
Strontium (Sr)
Barium (Ba)
Ammonia (NH3)
Ammonium (NH4)
Magnesium (Mg)
Concentration (ppm)
21300
320
2700
373
4
3
55
204
Anions
Chloride (Cl)
Bromide (Br)
Iodide (I)
Sulphate (SO4)
Phosphate (PO4)
Bicarbonate (CHO3)
Carbonate (CO3)
Concentration (ppm)
37900
212
14
216
5
320
0
Table 19 Reservoir water samples containing Cations and Anions
Ion
Sodium (Na)
Potassium (K)
Calcium (Ca)
Strontium (Sr)
Barium (Ba)
Chloride (Cl)
Sulphate (SO4)
Concentration (ppm)
11000
340
403
0
0
19800
2480
46
Hydrogen Carbonate (HCO3)
204
Table 20 Sea water samples
2.5
Well Performance
Having six drilled wells in the reservoir, only four were taken into account for performing Drill Stem
Test’s (DST) in the horizons that where thought of interest. This gave a total of 8 tests where the
wells were brought onto production for enough time to assure all the flow regions were shown and
shut in for enough time to allow a proper analysis of the pressure response in the reservoir. The
Drawdown used to bring the wells into production was not constant in any of the DST, which means
that they were not favourable for analysing. Due to this only Build Up analysis could be performed.
In the geology side, the DST targeted the Palaeocene structures within the reservoir that were
thought to be economically interesting. Some of them tested only a single layer within the reservoir
and others tested all the productive horizons that were intercepted by the well shown in.
Due to different reasons, two of them have a lot of uncertainty about the data or there is no
information about where the DST was performed. Analysis of the reservoir was performed at the
following intervals in Table 21 and their associated semi-log and log-log plots for each DST are in
Appendix IV.
DST#3
8433-8463
DST#4
8310-8463
DST#5
8310-8394
DST#1
8626-8638
DST#2
8534-8576
DST#3
8500-8515
Well-6
DST#2A
9660-9710
Well-3
DST #3
?-?
Well-1
Well-5
Table 21 DST Completion Intervals
2.5.1 Well 1
Three DST’s were performed, two of them in one perforated section and one of them with multiple
perforations shown in Table 22. It is observed the all the DST’s show an infinite acting system with
47
permeability between 81md and 184md. DST#3 and DST#5 show a radius of investigation of more
than 1400ft, which means that the drawdown period is long enough to get response of all the
features found near this well. DST#4 on the other hand has a smaller radius of investigation, around
800ft, this can be due to the larger interval tested. The Skin factor in Well-1 shows that DST#3 and
DST#5 have relatively high values, which means that some of the perforations have not cleaned up
with flow. On the other hand DST#4 shows negative skin, which shows that the tendency for the
wells not to clean up is not true for all the intervals tested, it could be due some formation damage in
the drilling process. Comparing this data with core analysis from the laboratory, it is consistent and
within the values expected to obtain.
Well-1
DST#3
DST#4
DST#5
Interval Perf
8433-8463
8310-8463
8310-8394
GEO
Full Sandstone
Full Sandstone
Sandstone/Shale/Limestone
Flow type
Radial Hom ∞A
K
120
81.45
123
184
KH
3600
7330.4995
11070
11776
S
1.1
-2.6251
-2
6.05
Radius Inv
1490
122
820
1810
PI(Av.)
3.876
3.25
6.858
Table 22 DST Results
2.5.2 Well-3
The analysis of this well is affected by the high uncertainty about the data obtained, since there is no
information about what interval is tested. Average data was used as input and a permeability of
142md is observed. This data is consistent with the core data study performed previously. It is noted
that in the DST report a possible unsealing fault is observed at a distance of 200ft.
2.5.3 Well-5
In Well-5 some different features are obtained which help us to understand more the dynamic of the
reservoir. DST#3 is performed in the section closest to the top structure and shows an infinite acting
pressure profile or possible closed system behaviour due to the downward curve shown in the late
time region of the log-log plot. At a greater depth, DST#1 and DST#2 show a parallel fault structure in
48
the reservoir, with a width decreasing as the depth increases. These faults do not show a totally
sealing structure which indicates more probably leaky parallel faults. In this well there has been some
problems determining the layers thickness, due to core data not existing from this well, which would
have to be taken into account for the uncertainty analysis. Because of this, the transmissibility factor
is assumed to be more reliable than the proper permeability obtained. If the system is analysed with
a partial perforation model, the permeability obtained are close to the average permeabilities
obtained in Well-1. The radius of investigation is big enough to assure a good reading of the pressure
behaviour of the reservoir in all the DST performed. The First two DST shows that the perforations at
these intervals do not clean up with flow underbalance, which could mean further workover before
production, or formation damage during drilling.
In well-5 there was another DTS test, which data response is not given, but it is noted in the given
report that shows a permeability of 82md. This test was done with the next perforations open: 86268638 / 8534-8576 / 8500-8515. This is a sign of interference between the layers being produced at
the same time.
2.5.4 Well-6
The DST in this well shows a significant amount of disturbances in the pressure response to the
generated drawdown. Due to this, the well-6 has no information to offer to the Well Test Analysis.
2.5.5 Conclusions
In general, from the well test analysis, it can be stated that the reservoir has a good permeability and
generally a good vertical communication. The reservoir shows permeability within a range of 120md
and180md, which is consistent with the core analysis and with the geology structure present in the
reservoir, with is formed by different layered turbidite sheets with some shale deposition between
layers. Due to this structure, it has to be noted that it is possible to have a very permeable layer
interbeded with a less permeable one, reducing the effective permeability, or in some cases giving
high values for this property. The Productivity index of the wells is good, having an average of
49
4.59bbls/day/psi and showing higher values in the top layers of the reservoir and lower values with
increasing depth. This correlates well with worsening petrophysical property distribution seen in the
geological model.
2.6
Reservoir Modelling Approach
The 3D static geological model created in Petrel software and was exported for hydrodynamic
simulation using Eclipse 100 simulation software. PVT properties were imported into the model from
reservoir fluid analysis along with estimated rock compressibility, capillary pressure and relative
permeability curves. Reservoir characteristics were altered along with injection and production.
2.6.1 Static Model
A static geological model based on the W-field top structure was created for the upper Palaeocene
reservoir using Petrel 2011.1. Logs corrected in Terrastation were correlated in petrel (Figures 11 &
Appendix I, Figure 4) a fine model was created representing facies allowing porosity from log data to
be distributed in the 3D model where appropriate. Because core permeability data was insufficient a
derived permeability was distributed using the co-kriging function which distributed high
permeabilities with high porosities.
2.6.1.1 Model Architecture
The contour lines from top structure map were imported into Petrel, where a top surface was
constructed. Using wireline log data from Terrastation the main reservoir sand bodies and shale
layers were correlated. The correlations identified the thickness of each layer and where they pinch
out. From this approximately 10 horizons were created of which the sand bodies were divided into
layers of three to better simulate the effects of gravity and reduce the uncertainty around
permeability in the Z-direction. These horizons were converted to surfaces as the basis for facies in
the model and cells for up-scaling properties.
2.6.1.2 Property Modelling and Upscaling
Properties were taken from Terrastation including Vshale, porosity, permeability and water
saturation these were distributed throughout the static model as detailed above. The initial fine
50
model consisted of dimensions 203 x 270 x 20 with 1,096,200 grid cells which were then up-scaled to
51 x 68 x 20 with 69,360 grid cells; the up-scaled model is shown in Figure 18. Porosity was up-scaled
using a volume-weighted algorithm and permeability was up-scaled using zone mapping by matching
the previously correlated horizons. The up-scaled grid geometry and well connections were then
exported to eclipse for dynamic simulation.
Figure 18 Upscaled Geo-model Displaying Porosity
2.6.2 Capillary Pressure and Relative Permeability
Special Core Analysis (SCAL) was completed on 9 core plugs from well 2 this yielded capillary
pressure, oil water relative permeability and gas oil relative permeability data. Firstly capillary
pressure data was collated and extracted from hard copy core analysis and plotted against brine
water saturation. Using the formula for Leverett J-function and assuming a contact angle of zero the
J-function was calculated and plotted along with brine saturation. This allowed an average value of
capillary pressure to be back calculated from the average J value, this average was then plotted with
core capillary pressure’s, shown below in Figure 19. This average value for capillary pressure was
then utilised in the dynamic model simulations in eclipse.
51
Pc vs Sw
Pc
70
60
702
50
721-2
40
698-1
30
665-1
20
659-2
10
733-2
0
0
0.2
0.4
0.6
0.8
650-1
1
644-2
Sw
Figure 19 Capillary pressure Vs. Water saturation
Relative permeability data of oil to water and oil to gas was available from all the cores but the
majority of samples contained spurious data and were deemed not to be representative. The few
representative samples were averaged and these relative permeability curves were used to in the
dynamic model. A representative relative permeability for oil and water is shown below in Figure 20.
1
0.9
0.8
0.7
0.6
0.5
Kro
0.4
Krw
0.3
0.2
0.1
0
0
0.2
0.4
0.6
0.8
1
Figure 20 Relative Permeability Curves for Oil and Water
1.2
52
2.6.3 Simulation Models
Eclipse100 numerical simulation software was used to estimate probable recovery factors from a
variety of different development scenarios and reservoir sensitivities. A brief description of each is
detailed here.
To predict the reservoir behaviour and the potential production profiles a two phase, 3D model has
been created. Natural reservoir depletion below bubble point and above bubble point has been
compared to assess the degree of compressibility and existing pressure support. The degree of
aquifer support was assessed without any pressure support, this was found to be yield very little
support. From this various cases were created with a number of water injectors, injecting below the
OWC. The Kv/Kh ratio was varied to gain an understanding of the gravitational effects within the
reservoir and how this property affects sweep efficiency. Due to the excess gas expected from our
high GOR a case was created to inject gas into the crest of the reservoir to hopefully improve oil
recovery efficiency once more.
In order to achieve the greatest oil recovery factor well location, the number of new production and
injection wells was increased resulting in a variety of differing field recovery factors.
Additional cases covered the practice of polymer injection instead of water injection which aimed to
improve sweep efficiency and decrease water cut. Drilling of horizontal wells was not modelled due
to the fact that sand layers are relatively thin for horizontal producers, meaning carefully placed
deviated wells created a larger contact surface area, horizontal producers resulted in an earlier water
cut compared to vertical and deviated cases.. The reservoir simulation base case utilised all the
existing wells and consisted of five producers and one converted injector.
53
2.6.4 Recovery Mechanisms
2.6.4.1 Natural Depletion
Different recovery mechanisms have been evaluated to identify those which will yield the greatest
production. The base case scenario was tested under natural depletion conditions from an initial
Figure 21 Average reservoir pressures and oil production profiles in Depletion Cases
Figure 22 Recovery factor for Depletion and Water Injection Cases with 1, 2 and 3 injection wells
54
reservoir pressure of 3800 psi to assess recovery as a result of the natural expansion of oil and rock
along with the reservoirs aquifer support, depletion was assessed above and below bubble point
(1745 psi) the results from the various cases are shown above in Figure 21. In the natural depletion
case above bubble point the production was controlled by a bottom hole pressure of 1900 psi, close
to bubble point without going below 1745 psi, the closer the reservoir pressure is to bubble point the
oil has greater mobility. For the natural depletion case below bubble point, the bottom hole pressure
reached 1500 psi with an expected improved recovery efficiency, due to the longer production time
as a result of a larger pressure drop. Due to the reservoir sandstone possessing a relatively high
permeability the pressure propagation is infinitely acting for a very short period of time, indicating
the natural pressure support is poor. The weak pressure support is a result of the edge drive aquifer
situated at the limbs of the reservoir surrounded by relatively thin layers of sandstone. For depletion
above bubble point the recovery factor is 6.9% which increases to 9.4% for the cases below bubble
point shown in Figure 22.
2.6.4.2 Water Injection
From the previous results it was concluded that the reservoir will require pressure support, this was
facilitated by water injection below the oil water contact of 8730ft. Well W3 was converted to an
injection well and a further four vertical injector wells were drilled into the oil water contact. These
injectors were set at a rate of 20 MSTB/d at with a maximum injection pressure of 5000 psi, so as not
to fracture formation, this process resulted in an consistent reservoir pressure above bubble point
shown in Appendix VII, Figure1. Injection from the beginning of production resulted in higher
pressure support efficiency and higher final oil recovery efficiency. The cases for natural depletion
were compared with the cases of additional injector wells which show a large increase in oil recovery
factor displayed in Figure 22. According to these simulation results, maintenance of the reservoir
pressure by injecting water yields a greater impact on production. Injection of water below the oilwater contact improves aquifer strength and mobility, the moving oil-water contact leaves residual
oil saturation, Appendix VII, Figures 2 to 4, and increasing water cut, Appendix VII, Figure 5.
55
From these results of pressure support the W-team have concluded that the vertical injector wells
will be drilled and utilised before production starts to improve overall recovery efficiency.
2.6.4.3 Vertical Permeability Sensitivities
Vertical permeability data is available only from well six, resulting in a lack of samples for proper
analysis of Kv/Kh ratio creating further geological uncertainty. In order to investigate the impact of
this uncertainty the Kv/Kh ratio was varied for a case with three injector wells and five existing
producers show in Appendix VII, Figure 6. A strong and active aquifer will move the oil water contact
towards the crest of the structure and vertical permeability will play a big part during this process of
reservoir fluid displacement by water. Results from simulation of different Kv/Kh ratios show that the
oil the recovery factor changes slightly for different values, Figure 23. Differences between recovery
factors show that the uncertainty of vertical permeability does not have a big impact on final
recovery. We can see that recovery factors do not vary until the lowest sand layers are highly
saturated with water as a result of the oil water contact moving up from the limbs. Once this occurs
vertical flow dominates the displacement mechanism meaning gravity is no longer dominating and
capillary forces are allowing greater vertical flow.
Figure 23 Recovery factor of oil for various Kv/Kh ratio cases.
56
From this limited range in recovery we can see horizontal permeability of the Palaeocene Sandstone
is the major flow property controlling the behaviour of oil displacement. Level of uncertainty for
vertical permeability may be marked as medium with relatively low level of influence on final
recovery factor shown in section 3.8 Field Uncertainty, due to the fact that the samples we have
gives us more or less a reliable range of 0.1-1 for Kv/Kh. This range gives a very similar recovery
factor with a difference of less than 2 percent.
2.6.4.4 Water Injection Into Crest
An injector well was placed in the crest of the structure appreciate and compare the processes of
displacement of oil by water in different zones of reservoir. In this case two injector wells were
placed in the oil-water contact zone to compare against the displacement process of an injection well
placed in oil bearing rock. Injection of water into the oil-water contact resulted in gradually
decreasing oil saturation and better piston like displacement. A moving water front from the initial
water bearing rocks at limbs of the structure to the oil bearing crest of the structure can be seen in
Appendix VII, Figures 7 to 9. The injection of water into the crest of the structure leads to a steep
increase of water saturation in the oil bearing zone which results in irregular movement of water
from injection to production wells. This result leaves relatively large amounts of oil behind in a zone
which was almost 100% oil saturated as it can be seen from Appendix VII, Figure 10 to 12. In terms
of vertical displacement and from Figure 24 in terms of areal sweep efficiency. This water injection
trial evaluated the effects of injector placement in reservoir rock and based on this further drilling of
new injector wells was decided to be only in the oil-water contact zone.
2.6.4.5 Oil Recovery Optimisation
Previous comparison of different cases showed that the best recovery factor was achieved from the
case using eleven production wells and five injector wells. Further coverage of the reservoir was
achieved by drilling new production wells. Drilling new injection wells aimed to maintain the
reservoir pressure above bubble point and displace oil from the movement of the oil-water contact.
Figure 25 displays the recovery factor for a number of different combinations of production and
57
injection wells. From this figure it can be easily seen that the increase in production wells from seven
to nine based on the case with three injection wells yields a noticeable increase with each new
production well until it reaches a value of 50 percent recovery for nine production wells.
Figure 24 Oil saturation grid with injection wells placed in the crest and limbs of the structure
Figure 25 Oil Recovery Factors for 3 to 5 injectors and 7 to 12 Producers
58
Further drilling of production wells is not recommended due to decreasing reservoir pressure profile.
Drilling of additional injection wells with previously drilled nine production wells increased recovery
factor to 54%. This increase in recovery shows how important it is to maintain reservoir pressure.
Drilling another new production well, increasing the total to ten wells, increased recovery factor only
slightly. An increase in recovery factor to 57% was achieved by five water injection wells. Cases with
ten, eleven and twelve producers do not vary much and recovery factor is very similar at
approximately 58%, which can be seen from Figure 25 above. The pressure profile does not decline
in these cases and there is no need to drill new injection wells. All the new production wells were
drilled in the crest of the structure and as it can be seen from the, Appendix VII, Figure 13, drilling of
six new production wells should be enough to cover the crest of the reservoir. Production profiles for
cases with five injector wells are very similar and represented in Figure 26. Plateau production rate is
80000 STB/day and it continues at this rate for little more than 3 years, cumulative production is over
20 years and is equal to 272 MMSTB of oil, which is a known uncertainty that contradicts our
reserves estimates; hopefully the model can be refined once we gain historical production data.
Drilling of new production wells into lower thinner reservoir zone will not be economical due to small
production rates and very close oil-water contact.
2.6.5 Alternative Development Plans Considered
2.6.5.1 Polymer Flooding
Polymer injection was used as an alternative development plan aimed to improve recovered oil and
reduce water cut of produced fluid. Polymer injected with water increases viscosity of displacing fluid
which should improve the displacement process and make it more piston like. Results from the
simulation of Polymer Flooding showed a big reduction in water cut, Appendix VII, Figure14,
however oil recovery factor reduced as well Appendix VII, Figure 15. Injected high viscosity fluid does
not increase reservoir pressure as fast as water injection does due to lower mobility of polymer and
it takes more time for production wells to ‘’feel’’ pressure maintenance. A slower reservoir pressure
increase results in smaller production rates, which lead to lower oil recovery factors, Appendix VII,
59
Figure 16. Taking into account all these results polymer flooding was considered not to be suitable
for the W-Field Palaeocene Sandstone reservoir development.
2.6.5.2 Gas & Water Injection
Reinjection of some fraction of produced gas into the crest of the structure with injection of water in
oil-water contact zone keeping the reservoir pressure above bubble point was an alternative
development plan considered to improve recovery factor. Gas injection Cases with different rates
showed that at high pressures and in rocks with relatively high permeability, gas becomes very
mobile relatively to oil and takes the path of least resistance to the nearest production well leaving
huge zones of by-passed oil, Appendix VII, Figure 17. Injected gas, which reaches production wells,
increases the Gas-Oil Ratio more than twice and does not act as pressure maintenance agent
resulting in lower reservoir pressure and lower oil recovery factor as it can be seen from, Appendix
VII, Figure 18, compared to Water Injection Cases with the same number of injection wells.
Figure 26 Production Profile, Oil Recovery Factor and Residual Oil in Reservoir for Best Case
60
2.6.6 Conclusions and Recommendations
Figure 27 Oil Saturation Grid with proposed development wells
There are a variety of geological and petro physical uncertainties characterising the reservoir with
virtually no historical data to reduce our uncertainties. Drilling new wells into the crest of the
structure, Figure 27, will be the greatest source of information. This information will either confirm
our assumptions from the modelling phase or provide some information to history match the model
against. Data should constantly be utilised to update the model increases the representation of the
reservoir below. This hydrodynamic model was constructed based on the available data and different
cases were simulated to determine the best and most economically efficient reservoir development
programme. Cases and sensitivity studies were compared which lead to the identification of most
favourable case in terms of oil recovery factor which were then recommended for detailed
economical analyses, Appendix VII, Figure 19. This oil recovery optimization study concluded that
eleven production wells, five of which are existing exploration wells, will be enough to cover the crest
of reservoir structure. New production wells should be deviated to increase contact area of borehole
surface with reservoir. Well number W3 will be turned into an injector well due its placement at the
outer limits of the reservoir intersection of the oil-water contact. Drilling of four new injection wells
61
outside the perimeter of the crest in oil-water contact zone will maintain reservoir pressure support
above bubble point. All the production wells will be completed over two thirds of the reservoir
thickness due to rapid water flooding of bottom sand layers. Injector wells should be completed over
the whole thickness of the reservoir, for better displacement process. Initial production rates should
be aimed at 12000 BLPD per well until average reservoir pressure declines to 3000 psi. All production
wells should be completed with artificial lift equipment (Gas lift) and used as reservoir pressure
declines to 3000 psi with target rates of 11000 BLPD per well. Control of the rates should result in
achieving a plateau of 80000 BOPD which will be held for almost four years. Drilling of injection wells
should meet the requirement to inject 20000 BWPD per well. If the reservoir development program
meets all the designed parameters it should result in an oil recovery factor between 50-60 percent in
from 20 years production, however further research into EOR methods can result in shortening of
the time of production and increasing of recovery factor.
3.
Development and Management Plan
3.1
Economic and Commercial Consideration
3.1.1 Adjacent Fields
Adjacent to the W-Field block, WA-418-p, there are several blocks developed producing oil and gas in
the area, the closest developments are Mutineer-Exeter field, the Cossack-Wanaea-Lambert-Hermes
field and the Western Shelf Gas Project, which includes North Rankin, Goodwyn, Angel and Perseus
filed.
3.1.2 Australian Market
Australia is a country with a long history of exploiting natural resources, but has strict environment
regulations, which have to be considered carefully. The WA-418-P block lies in what is defined as
Commonwealth waters, which means that a PRRT and FT will be imposed. In the actual fiscal
imposition, the country encourages investment by the deduction of the CAPEX in the PRRT until it
has been recovered with interests. This fiscal advantage gives more safety to investments and allows
62
the company to have the initial investment returned sooner in order to be able to explore new
opportunities for the company portfolio.
At the moment, some of Mungo energy’s common partners have an important presence in the
country, which could help educate Mungo about Australian regulations and developments, also if the
CAPEX needed to carry forward this project is found to be greater than the company posses a Farmin could be offered to share the risk of the investment.
From a selling point of view, the oil market in Australia is going through some difficulties and the
production forecasts show a clear reduction from year 2010 with 200Mbbls/d of production to 2017
with a production of 50Mbbls/d (Wood Mackenzie source). In the case of the gas market, prices of
contracted supply have increased significantly from US$2/Mscf in 2002 to US$3.5/Mscf in year 2012
and with a tendency to continue rising.
3.1.3 Corporate Environment
The exploration license was awarded to Mungo in 2008 and it is the only asset that the company has
in Australia. At present, the company has 88% of its NPV placed in Africa, followed by 7% in Latin
America, 5% in Europe and a 0.1% in South Asia. Having this information, it is thought that the
development of this block would be very important in order to diversify the resources of Mungo
energy and release the pressure being supported by the company from the African investments.
The potential recoverable reserves of this project were evaluated and had been estimated to be
around 220 MMbbls, which means that Mungo energy would increase its commercial reserves by
almost 20%. This will ensure growth of the company and will release the company from part of the
excessive weight that Africa, and especially Ghana, has in the company’s NPV. Developing this project
will increase the company’s presence in a part of the world where Mungo has no presence and the
potential in the Australian markey is increasing every year, being the fifth country in terms of the
number of gas reserves, should be taken into account very carefully.
63
The economic analysis has revealed a good profitability in different development strategies, which
means that the economic surplus of this project is not a problem, but it has to be studied deeply in
order to obtain the maximum economic efficiency of the capital invested.
It is common knowledge that the company is not in the best situation in terms of debt, having to
fund US$15.5 billions, this puts Mungo energy in a difficult situation with the possible development
of this project in the short term. On the other hand, it has to be noticed that our base-case planning
was estimated assuming a US$80/bbl with a premium of 6.5% for lighter crude oil giving a price of
U$85.2/bbl yielding an NPV, 10, of over US$4 billion. This would mean that in a low case scenario,
the project itself would start to make profits in 2016, and use the future profits to develop projects
that have been delayed. It is also taken into account the possibility of Mungo selling some of existing
assets which are less profitable, in order to obtain funds for the development of this project.
Further portfolio management will be evaluated in order to priorities the projects with a high
profitability, i.e. the development of the W-Field.
3.1.4 Cash Flow
The potential project development scenarios were analysed using the following economic
parameters such as net NPV, NPVI, PIR and IRR. The Cash Flow model was executed following the
Australian regulation framework and using the following assumptions:
TAXATION: Due to the location within Australian waters the project is sensitive to two different
taxations. The first one is the PRRT, which is 40% of the profits of every year, after the development
costs have been returned with an interest linked to the Commonwealth LTBR. The second is a FT,
which is 30% of the profit after profit minus the correspondent deductions. Oil levy and excise tariffs
are not applicable in this situation.
CAPEX: An expenditure schedule is obtained by the use of QUE$TOR after defining the development
to follow and entering the characteristics of the field being analysed. Displayed in Appendix VII,
Table 4.
64
OPEX: The operation expenditure schedule is given by QUE$TOR after defining the production profile
and the operation program. This is defined in Appendix VII, Table 6.
TARIFS: It is assumed that the oil produced is sent to the Kwinana refinery, which is located 1.000NM
away from production. Transportation tariffs are calculated separately for oil and gas. It is assumed a
charter rate of 10.000$/day which means that having a distance of 1.000NM, only two shuttle
tankers will be needed to produce without interruption. Gas production is conducted to connect with
the existing North West Shelf Gas Project, where it is sold in the local market. The tariff for the usage
of this pipeline is assumed to be 0.5$/Mscf.
INFLATION: Australia is a stable country, therefore it is assumed that inflation will remain constant
for the length of the project at 3%, while the price of the oil and gas is anticipated to increase at a
constant price escalation of 1.5%
A representative input for the cash flow used to screen between different developments can be
observed in the Appendix VII, Table 6.
3.1.5 Project Parameters
3.1.5.1 Production Profile
Having estimated recoverable reserves of 220MMbbls a simulation model was created in order to
obtain the best production profiles and generate cash-flows for the screening process to obtain the
most economically efficient production profile. The model output a peak production of around
80Mbbls/day of oil and 43MMscf/day during 4 years, then a declining production having a field life of
20 years. Assuming the project development will start in year 2012, this first oil will be in 2015 and
ending production at somewhere during 2035. The production profile is shown in the Figure 28
bellow:
65
35
18
16
30
14
12
20
10
15
8
6
10
MMSCFPD
MBOPD
25
OIL PROD
GAS PROD
4
5
2
0
0
2012
2017
2022
2027
2032
YEAR
Figure 28 Produced Oil and Gas
3.1.5.2 Development Strategy
Given the characteristics of the field and location the developments analysed were reduced to three
different options. The six existing wells drilled during the exploration phase were taken into account
when creating the development strategy. The developments defined were: FPSO with subsea
completion, GBS and Steel Jacket, all with existing exploration wells and subsea completions. The
new injector wells will be drilled from a jack-up rig and producing wells will be drilled from the
platform once it is available and in place. The following table shows the possibilities that have been
taken into account:
Development
OIL Transport
GAS Transport
Number of wells
Field Property
Table 23 Development Strategies
FPSO
GBS
Fixe Platform
Tanker
Pipeline/Re-injected
Producers
Injectors
10
4
10
5
11
5
12
5
13
6
Operate
Farm-In
Sell Project
66
Wood Mackenzie consultants suggested to carry forward with an FPSO development due to possible
delays with development approval, for fixed jackets and GBS structures, from the Government. More
research into this development strategy was performed, and it was found that in the Carnarvon Basin
there have been several development approvals in the last 10 years, with the majority as FPSO’s and
Steel Jacket’s, as it can be seen in the Appendix VII, Table 1. From this research and greater profits
associated with fixed jacket platforms this was the chosen platform to develop the W-Field from.
Due to the length of the project, the lease of any production asset is rejected. The first option
studied was the FPSO platform where the wells would be connected to a subsea development with
manifolds and a tie-back system, as it can be seen in Appendix VII, Figure 10. This option was found
to have the highest IRR, although it was disregarded due to the low NPV that it provided. The
following structure studied was a GBS, which was suitable for the existing environment and for the
water depth. Previous existing wells would be completed as subsea developments, and the new wells
would be drilled from the platform once in place. The economic analysis showed that this option had
the highest MCO and lowest NPVI of the chosen. These factors are thought to be very relevant to our
company since the company is not in the most comfortable situation in terms of debt and due to the
increasing portfolio of the company, the financial strategy to follow should be to maximize the
efficiency of the money invested. A template of the development can be seen in Appendix VII, Figure
11.
The last development option studied was to consider building fixed steel jacket platform with the
existing wells completed as a subsea development and tied back to the platform, where the new
wells will be drilled from. This last option has the highest NPV over the FPSO and GBS in the different
modelled situations of the wells and production profiles, which also shows a higher profit and a
lower MCO. A template of the development can be observed in the Appendix VII, Figure 12. In the
previous cases, the FPSO and the GBS were designed with storage capacity and were offloaded by
the use of a CALM Buoy offloading system, but in with the fixed platform situation, storage cannot be
67
provided, this issue was solved through the use of an FSU, which will be offloaded periodically (8 to
10 days).
The produced crude oil will be offloaded from the FSU using two chartered tankers, which will
transport the crude to the nearest refinery, located in Kwinana, as for the gas, a pipeline will be built
to connect with the North West Shelf Gas Project, located 70km away from the field. The capacity of
the Angel-North Rankin and North Rankin-Withnell Bay were checked and are able to provide this
service, since their respective production will have peaked and dropped before 2015.
In order to obtain an optimum solution, a sensitivity analysis was performed on the number and type
of wells that could be used to produce the reservoir in the most efficient way. It was found that the
CAPEX was reduced significantly if the new wells were drilled from the platform, instead of having a
pre-drilling programme with a tie-back system to the platform. It was also found that, due to this
fact, the new wells would have to be deviated to drill into the desired target areas, which show good
petrophysical properties. As a result of this analysis it was found that the best solution from an
engineering point of view consisted of 13 producers and six injectors, but after a screening process
between the different options, it was found that the most efficient situation was to develop the
reservoir with 11 producers and five injectors to obtain a better economic efficiency.
Due to the characteristics of the reservoir, the production has to be carefully planned so as not to
allow pressure to fall below bubble point, which would yield a smaller recovery factor and reduce
sweep efficiency from water flooding. It is assumed that the aquifer may not provide sufficient
pressure support therefore water injection has been designed as a secondary recovery mechanism,
meaning the injectors are working at full operating capacity throughout the life of the project.
Sensitivity analysis was performed on the number of injectors and producers in order to shorten the
project life, the modelling simulation showed a maximum recovery factor using 13 producers and 6
injectors, but economically, the most efficient scenario determined is eleven producers and five
injectors. Appendix VII, Figure 24 shows, for interest, the NPV difference of all trialled cases.
68
Different options are analysed concerning the ownership of the field, this will depend on the
corporate strategy taken by the company. The possible options are to develop the field using its own
funds, Farm-in with familiar partners with previous experience of operating in Australia, as in the
case of Shell which is part of the Joint-Venture of the North West Shelf Project and could help to
obtain a better tariff for the transport of the gas or selling of the project to another company. After
discussing the possible options, Team W has considered to farm-in the project to share the risk with
some of its usual partners, which have previous experience in the country, and have operations in
nearby areas. It is especially recommended if possible to create a partnership with Shell, which has
equity in the North West Shelf Gas Project, a large gas-producing project. This Joint Venture would
be very prosperous for the field development and would help to carry forward the project, without
funding the projects CAPEX entirely from Mungo’s resources. Selling this project is not
recommended, since it is thought that it could be a key asset for the growth of the company. This will
also sit well in the portfolio the managing directors are trying to strengthen.
3.1.6 Sensitivity Analysis
At the beginning of the project, Team W was concerned about the volumes of produced gas from the
field, since it was not known at that point the profitability of the gas or the behaviour of the gas
market in North West Australia. Sensitivity analysis was run concerning this issue, once the
production profile was known the results showed that the construction of a pipeline to sell the gas
would make an important difference in the profitability of the project. It has to be taken into account
that the prices of gas in north west Australia is expected to rise. The difference between the gas
injection case and sale cases is shown in detail in Appendix VII, Table 2.
In order to identify which parameters of the investment have the greatest impact on profitability of
the project, a sensibility analysis was performed on the following inputs: Oil Price, Gas Price, OPEX,
CAPEX and Oil Production. Appendix VII, Figures 13 to 17 display a Spider charts with the relevant
parameters: CAPEX, OPEX, Oil and Gas production, Oil and Gas price, Taxation. It can be observed,
69
that the NPV of the project is most affected by the Oil production and price and the taxation at which
the project is exposed.
NPV(US$ MM)
FPSO
GBS
10Prod-4Inj
3,345.12
3,445.98
10Prod-5Inj
3,611.68
3,735.31
11Prod-5Inj
3,667.24
3,816.59
12Prod-5Inj
3,647.09
3,790.55
13Prod-6Inj
3,531.69
3,826.72
Fixed Platform
3,584.01
3,870.08
4,061.82
4,066.64
4,107.11
Table 24 Screening of Platform Development Options
A Monte-Carlo simulation was performed in Crystal Ball in order to obtain the probabilistic value of
P10, P50 and P90 for the NPV. The results can be observed in the following Figure 29.
Figure 29 Reverse Cumulative Frequency for Probabilistic NPV of the project
The steel jacket platform was chosen as the best case scenario after the screening process, various
combinations of producers and injectors were also appraised and detailed cumulative NCF plots for
these cases are shown in Appendix VII, Figure 9.
3.1.7 Conclusion
As it was stated before, the best project development is to drill 11 producers and 5 injectors with a
fixe platform and produce the reservoir for 20 years, with a peak production of 29 MMbbls per year
during the plataeu period of approximately four years. The best engineering strategy would be to
drill 13 producers and 6 injectors, which shows a better recovery factor than the first case, but the
increase in CAPEX, is not compensated by an increase of the NPV, making the economic efficiency of
the project to be lower tha the case of 11 producers and 5 injectors, show in Table 25.
70
13PROD-6INJ
12PROD-5INJ
11PROD-5INJ
10PROD-5INJ
10PROD-4INJ
NPV(US$
MCO
(US$
MM)
IRR
MM)
Payback NPVI
4,107.11
44.8%
930.64
3
4,066.64
45.5%
904.66
3
4,061.82
45.5%
904.56
3
3,870.08
49.3%
1022.65
3.3
3,584.01
48.5%
997.50
3.3
4.7
4.8
4.8
4.3
4.1
Table 25 Best Economic Case for Steel jacket Platform, Selling Gas
3.2
Drilling
3.2.1 Introduction
The drilling aspect of this project will be completed in two phases, the first phase consist of drilling 4
vertical wells from a Jack-Up rig and the second phase consists of drilling 5 deviated wells the steel
jacket platform. The programme objective, geological prognosis, pressure profile, rig selection, mud
selection, well control, casing selection, drill bit selection, cementing, directional drilling, bottom hole
assembly, drilling schedule and new technology are discussed in depth below.
3.2.2 Objective of the Programme
The objective of the drilling programme is to complete each well within its respective time frame
adhering to the following standards expected by Mungo energy.

Safety; safety of the people and equipment is of the highest importance. The loss of life
during drilling will not be tolerated. Prevention of this occurring will be emphasized.

Environment; in all the aspects of the drilling programme, environmental consideration have
been taken seriously. Efforts have been put in place to prevent and in other aspects limit the
effects of drilling operations on the environment as far as possible.

Cost effectiveness; this is an important aspect from business point of view. The activities
have planned with emphasis on minimising costs and time wastage.

Time; Timing of all the drilling activities plays an important role with respect to economics of
the whole project. Drilling activates adhere closely with the drilling schedule ensuring safety
standards are high and no time is wasted, loss of time during drilling will delay positive
income.
71
3.2.3 Geological Prognosis
The summary of the typical lithology for the reservoir interval and above the top structure is
summarised in the table 26 below. In general, the lithology is comprised of layers of claystone/shale,
siltstone, limestone and sandstone. The reservoir sand bodies are generally friable and shales found
to be sticky. The Palaeocene reservoir sand bodies are interbedded with thin layers of shale.
TVDSS (FT)
Description
262- 1500
Soft and loose clay
1500-3272
Soft to medium hard sticky clay and slightly calcerous
3272-4400
Soft to medium hard permeable sand Inter-bedded with siltstones
4400- 8220
Soft to hard Claystones with some thin layers of limestone and siltstone
8220- 8480
Reservoir interval having friable sand stones with thin layers of shale
8480- 9000
limestone
Table 26 Summary of Lithology from Surface to Reservoir
3.2.4 Pressure Profile & Mud Programme
The reservoir interval is found to be normally pressured according to pore pressure data having a
gradient of about 0.45psi/ft. However, there is a section of formation above the reservoir interval
from 7400ft to 8200ft which is over pressured with a pressure gradient of 0.494psi/ft. During
exploration the data registered high overbalance which led to loss of mud and as a result a new mud
programme has been designed to take accommodate this. The recommended mud densities for
further drilling operation is shown in the Appendix VI, Figure1.
3.2.5 Rig Selection
The selection was based on many factors such as water depth (80m), the ease of mobilization with
respect to time, economics (day rates, mobilisation costs) and complexity during the installation and
drilling operation. A Jack-Up rig has been adopted because it is cheap, saves time and posts no need
for installation of complex wellhead and BOP during drilling operations. The Jack-Up rig will be used
for drill all the vertical injector wells. The main steel jacket platform will be used to drill deviated
wells and will also have minimum requirements as shown in table 27.The rigs will be top drive
systems in order to harness the advantages such as reduced wastage of rig time, and the ease to
solve problems associated with pipes getting stuck.
72
Item
Water depth capability
Drilling Depth capability
Derrick capacity
Draw works
Mud Pumps
Rotary System
Circulating system
Description/ specification
400 ft
35,000ft
2,000,000 lbs
NOV 4,600 HP
3 x NOV 14-P-220, 2200 HP
Top drive NOV HPS (25000ft-lbs, 300 rpm)
Shale shaker, degasser, hydraucyclones, mud storage
Table 27 Rig Characteristics
3.2.6 Well Control
Well control is a very sensitive part of drilling operation. This is mainly due to the high risks to people
involved, equipment used and the environment. Oil and gas operations have been subjected to close
scrutiny by national and international agencies about issues related to safety of people, equipment,
environment and the economics of controlling a potential blow out. Therefore well control will use
primary and secondary controls that comply with all regulations defined by the DECC.
Primary control will ensure there is at least 200psi overbalance especially in the reservoir interval
and also an overbalance in sections of formation above the reservoir interval as shown in the
Appendix VI, Figure 1.
Secondary control comes into operation when primary control is compromised. It involves use of
BOP stack with 5000 -10,000 psi rating capable of controlling reservoir pressure of 4072psi at 8900 ft
TVD and killing well with heavier mud. The BOP will be installed on 20’’ casing. The presence of faults
and evidence of over pressures from the appraisal wells above the reservoir interval requires the
wide range BOP rating.
During drilling, there will be close monitoring procedures related to observation of both primary and
secondary signs of kicks such as flowing wells with pumps shut off, flow rate increase, improper hole
fill ups during trips, increase of mud volume in the pit, drilling break and high gas cuts. Strict
measures will be undertaken to ensure timely identification of causes and controls.
73
3.2.7 Drilling Fluid Selection
The choice of drilling fluid is mainly based on; its cost, its own characteristics, impact on the
environment or environmental regulation, impact on the pay zone and also the characteristics of the
lithology. The W-Field is situated offshore; therefore greater care is taken not to damage the
environment and secondly to select the proper fluid so as not to damage the pay zone. The drilling of
formation from seabed to a depth of 514 feet will utilise sea water, suspending additives (flosal) and
a viscosifier (attapulgite clay). The rest of formation will be drilled using water based mud (WBM)
and polymer additives (polyol, PHPA) to reduce problems associated with sticky clays, the chances of
clay swelling and pay zone damage. The choice of WBM is chosen to minimise damage to the local
environment while being cost effective.
“Field experience using polyol mud has shown improved wellbore stability and yielded cuttings that
are harder and drier than in conventional WBM. This hardness makes solids control more efficient”.
The reservoir interval will be drilled using polymer inhibited water based mud i.e. a non-damaging
drilling fluid (NDDF) in order to avoid damage to the pay zone, prevent clay swelling and utilize other
advantages such as formation stability. The mud weights have been designed to have an overbalance
ranging from 50 – 200 psi over formation interval above the reservoir interval as shown in Appendix
VI, figure 2. However, the reservoir interval will have an overbalance of about 200psi throughout the
interval. The summary of typical mud weight distribution is shown the table 28 below.
3.2.8 Drilling Bit Selection
Depth
Hole Section (inches)
Mud Type
262- 514
36
Sea water
514 – 1485
26
Polyol + PHPA +KCL(WBM) 9.0
1485 - 4969
17 ½
Polyol + PHPA +KCL(WBM) 9.5
4969 - 8220
12 ¼
Polyol + PHPA +KCL(WBM) 9.4 – 9.8
Table 28 Mud Type and Weight
Mud Weight (ppg)
74
The bits were selected to minimise tripping time, provide high rate of penetration and prevent bit
balling. As indicated in the geological prognosis, the formation to be drilled has strength ranging from
soft to medium hardness with lots of claystones/shales which pose problems related to bit balling.
The bit types are chosen according to IADC Classification Chart from Smith and Hughes. The roller
cone milled tooth bit was selected for drilling the formation from the sea bed up to reservoir interval.
This is because it can withstand formation strength ranging from soft to medium hardness. However,
the type of teeth used will vary from soft steel to medium steel. For deviated wells the hard steel
tooth roller cone bits or PDC bits will be used because of the need to minimise trips, for high ROP,
effective cleaning and the presence of some hard layers of formation. A bit summary is shown in the
table 29 below.
Hole and Bit
Diameter (inches)
Depth
interval (ft)
Formation
36
262-514
soft
26
514 - 1484
Soft
17 ½
1484 - 4964
Med-Hard
12 ¼
4964 - 8220
Med-Hard
8½
8220 - 8480
Med-Hard
Bit Type
Tooth type
Roller cone (milled
tooth bits)
Roller cone (milled
tooth bits)
Roller cone (milled
tooth bits)
Roller cone ( milled
bit)
Roller cone milled
(insert bit)
Soft steel
Soft steel
Hard steel
Hard steel
Hard steel
Table 29 Drill Bit Specification
3.2.9 Casing Design
The selection of casing size was based on information learned from previous appraisal wells, lithology
characteristics and production tubing size. The design of casing burst and collapse is based on worst
case scenarios during drilling and operation. It takes into account the worst case situations such as
complete loss of circulating mud and gas fill-up. The operational scenarios have been adopted for
production casing such as evacuation of tubing/casing annulus and leak of gas from tubing just below
the tubing hanger.
75
20’’, 13 3/8’’, 9 5/9’’ casings with grades J55, L-80 are proposed. The 30 ‘’was chosen to seal off loose
formations and low fracture zones, the conductor tube will be set at a depth of 514ft TVD which has
an interval of mostly soft formations. The 20’’ should seal off fresh water sands, surface casing will be
set at depth of 1485ft TVD, 13 3/8’’ should isolate from troubled zones and swelling clays,
intermediate casing will be set at depth of 4969ft TVD to seal off layers of clay stones, sandstones
and silty mudstones. The 9 5/8’’ will seal of the over-pressured interval above the reservoir,
production casing will be at 8220 ft TVD helping seal off lithology up to the top reservoir interval
including the slightly over pressured area just above the reservoir interval indicated in well two.
Appendix VI, figure 3 shows typical well completion.
The grades of the casing were selected depending on the economics, fluid properties and guidelines
of API casing manual. The summary of the casing selections and loading are shown in the Table 30
shown below.
Casing
setting
depth
(ft)
Design loading requirements
Burst loads
(1.1 safety Collapse
factor) (psi)
loads (psi)
Selected casing properties
Casing
size
(inch)
Pore
pressure
(ppg)
514
30
8.5 – 9.5
113
254
1485
20
5.5 – 9.5
546
734
J-55
106.5
2410
770
4969
13 3/8
8.9 – 9.9
2163
2558
L-80
47
5380
2670
8220
9 5/8
8.5 – 9.5
3518
4061
L-80
40
6870
4750
Grade
Burst
Weight loads
(lb/ft)
(psi)
Collapse
loads
(psi)
Table 30 Casing Properties, Burst and Collapse loads
3.2.10 Cementing
Class G cement has been selected because of its associated advantages, it is relatively cheap, it has
good compatibility with most additives, wide range of temperature and pressure differences. A
Range of cement densities have been proposed depending mainly on the fracture strength and these
are shown in the Table 31 below. The surface casing will be cemented up to the top. However
intermediate and production casings will have their TOC as indicated in Table 31, which is at least
300ft from the previous casing shoe.
76
A number of additives such as bentonite, hollow micro spheres, accelerators, retarders and other
relevant additives will be added to create the required cement properties. Laboratory tests will be
performed on the cement slurry and cement before it is used coupled with strict adherence to the
good cement job guidelines. These tests and cement job procedures are illustrated in the appendix
vi. The cement job will be tested and confirmed after each job using logging methods such as Cement
Bond Log (CBL) and Variable Density Log (VDL)
Hole
size
(in)
Dept
h (ft)
36"
514
26"
17
1/2"
12
1/4"
1485
Top of
cement
Cemen
t Type
Additives
Class G
Bentonite
surface
Class G
4969
1200
Class G
8480
4700
Class G
Bentonite
Hollow glass
micropheres
Bentonite
polymers
Cement
Operation
Single
Stage
Single
Stage
Single
stage
Single
Stage
Cement
Density
(ppg)
Fracture
Gradient
Mud
Density
9
10
9
11
10.5-14
9.5
13
14-15.8
10.5
Table 31 Cementing Characteristics
3.2.11 Bottom Hole Assembly (BHA)
For directional drilling a rotary steering system will be used. The BHA will therefore include a bit,
drive sub, non-rotating steerable stabiliser, alternator/pulse sub, stabilizers, reservoir navigation
sensor sub, MWD sub drill collars and heavy weight drill pipes. The choice of this BHA is based on the
fact that it reduces the frequency of tripping, the oriented mode can enable rotation of drill string
while drilling and the MWD tool has a better capability to obtain information about the formation
such as, resistivity, azimuth, and the fluid contacts, bed boundaries can be detected well ahead of
the tool and time. The conventional rotary drilling assembly will be used while drilling the new
vertical wells.
3.2.12 Directional Drilling & Surveying
As mentioned earlier for directional drilling a rotary steering system will be used. In addition to
previous stated advantages, this kind of BHA has benefits such as reduction to formation damage and
prevents avenues for drilling pipes getting stuck.
77
For any deviated wells the kick off points will be done in well consolidated depths which are found
below 1500 ft. the maximum built up rates will be 3 degrees per 100 ft in order reduce torque and
drag related problems. The inclinations will range between 40- 45 degrees to allow wire line logging.
The general profile of a typical new producer well has been designed and the key details are shown
in Appendix VI, Figure 4.
3.2.13 Risk Management
The major risks include blow out, stuck pipe, lost circulation, clay swelling and fall off of
unconsolidated formation. The mitigation measures put emphasis on prevention methods rather
than corrective methods. A number of them are highlighted below.

The most dangerous of all risks is a blowout which occurs in over pressured reservoirs.
Though the data shows the reservoir interval is normally pressured, there is an over
pressured section just above the trap. To prevent a blow out, an overbalance of about 120 –
200 psi has been proposed in these troublesome intervals as shown in appendix VI. In case of
a kick, it will be dealt with using circulation of heavier mud.

In an attempt to prevent a kick or blowout by use of overbalance, there is a risk of lost
circulation creating formation damage and economic losses. Close monitoring of mud
volumes will be required. In the case of losses, appropriate measures such as adjustment of
mud density will be enforced.

For the case of stuck pipe which may occur due to thick mud cake, settling of cuttings in
deviated wells, appropriate measures ensure proper flow of cuttings to surface and a good
mud programme will be required. Clay swelling and unconsolidated formations shall also be
dealt with using proper WOB and ROP.
3.2.14 Drilling Schedule
From the data gathered concerning the exploration and appraisal wells, an average drilling time has
been planned. Four more vertical wells will be drilled to serve as injectors using a Jack-Up rig and 5
78
deviated producer wells will be from platform. An average of 28 days and 38 days are required to
drill a vertical well and a deviated well respectively as shown in Appendix VI, Figure 5. This includes
time for rig set up, logging and release of rig. The drilling of injector wells will start on early January
2015 while deviated producers will start early June 2015.
3.2.15 New Technology
The main challenges in oil and gas industry include drilling in deep water depths, hard formations,
environmentally sensitive areas, high pressure high temperature reservoirs and extended reach
drilling, optimising rig time, and quality of logging/measurements while drilling.
The appropriate technology which can be used to our advantage are the ones in areas of
developments related to optimising rig time using technology such as casing while drilling, new bit
technology, better measurements/logging while drilling and mud formulation.
Team W are also proposing to use another technology developed by Schlumberger called PowerDrive
Archer Rotary Steerable System (RSS). This technology is very compatible with the BHA that has been
proposed earlier for directional drilling. Power drive system has advantages such as an overall
improved drilling performance with an increase in ROP by 85%, reduced cost per foot by 27% versus
conventional motor BHAs. Figure 6, Appendix VI was adopted from a Schlumberger and shows the
comparison between PowerDrive Archer RSS and conventional BHA in Eagle Ford Shale Play.
3.3
Production and Process Facilities
FPSO, Gravity based structure and steel jacket platform were considered for the field production
platform. Technical limitations such as 80 meters of water depth eliminated options such as tension
leg. Economic analysis screened all the possible options resulted in the steel jacket platform being
chosen as the drilling and production module accompanied by a floating storage unit (FSU) as the
storage facility and two shuttle tankers as the offloading facility.
The base case model parameters for the development wells was modelled by using the Drill Stem
Test (DST) from well 1 because this particular DST has less noise than the other DST. The most
79
suitable flow correlation for a flow below bubble point and high water cut is Hagedorn and Brown.
The other flow correlations such as Duns and Ros, Beggs and Brill, and Orkiszewski have some
limitations within them. The Duns and Ros correlation is not suitable for multiphase flow, the Beggs
and Brill correlation is only accurate up to 10% water cut, and the Orkizewski model is not accurate
for oil gravity above 30° API.
Fluid parameter correlations are chosen based on the fluid description of well 2. The bubble point,
gas solubility and formation volume factor correlation is Glaso. The oil viscosity correlation is Beggs
which is accurate for reservoir temperatures above 220°F. Carr method is used for the gas viscosity
correlation because it has an average of 0.38 absolute errors for gas with specific gravity between
0.55 and 1.22 and a temperature range between 100 and 300°F.
The new deviated wells will start on stream as older exploration wells start to produce, they will then
be brought online sequentially as they are drilled to maximise the plateau time. By simulating the
reservoir pressure on ECLIPSE 100, we can identify that after a few years of production the reservoir
pressure will decrease to 3050 psi. From this time we will ensure the pressure declines to a minimum
of 2400 psi to ensure we stay above bubble point but allowing the maximum mobility of black oil.
The input data for production technology software, Wellflo, are shown here in Table 32:
Reservoir properties
Pressure (psi)
Temperature (°F)
Permeability (mD)
Thickness (ft)
Wellbore radius (ft)
Value
3050
244
230
201
0.58
Reservoir properties
Gas-Oil ratio (scf/stb)
Formation volume factor (rb/stb)
Oil gravity (API)
Water salinity (ppm)
Reservoir radius (ft)
Value
561
1.402
31.65
59000
4921
Table 32 Reservoir Properties for WellFlo Characteristics
3.3.1 Well Completions
George E. King Engineering states the relationship between sonic velocity and formation strength as
follow:

Sonic velocity < 50 µs/ft is strong formation
80

Sonic velocity > 90 µs/ft is weak formation

Sonic velocity > 120 µs/ft is near unconsolidated formation
From above we can conclude that our sand which has a sonic velocity between 85-105 µs/ft is weak
formation. W field has a net pay to gross average of 0.85. It is a big block of sand with fluid contacts
at 8730’. Core observation shows that the Palaeocene sand has an almost uniform sand size
distribution and it is friable. Based on that situation the team choose to have an open hole
completions with wire wrapped screens. We will use single 5.5” production tubing with packer above
the productive intervals.
The open hole single string with wire wrapped screen provides us with the ability to control sand
production, because the W-Field is relatively far from land preventing sand production is a better
option than processing large volumes of produced sand. In addition, the chosen completion also
provides a maximum contact with the Palaeocene sand interval to eliminate limited entry skin.
Gas lift will be used from first production to maximize the recovery while also utilizing the available
gas from the reservoir.
The plan is to drill the hole, run the production logging to find the fluid contact if possible and then
plug the interval below fluid contact with cement to avoid water breakthrough.
3.3.2 Subsea System
3.3.2.1 Wellhead
The highest operating pressure in the injector wells are no more than 4000 psi while the highest
pressure due to gas lift is 2000 psi. Wellheads with pressure rating of 5000 Psi are selected for the
field development. The subsea wellhead might be controlled by ROT (remote operated tool), ROV
(remotely operated vehicle) or diver.
3.3.2.2 Choke
A choke will be use with some wells in case we need to have a backpressure to control the
production flow (bottom hole pressure) and to increase the efficiency of the gas lift. In vertical pipe
81
flow, the gas expands rapidly with decreasing hydrostatic head and the liquid moves in slugs through
the tubing. Meaning the energy from gas lift is rapidly lost and liquids fall down the tubing and begin
to accumulate over the perforations. Accumulating liquids hold a back pressure on the formation. If
enough liquids accumulate, the well may "die" and quit flowing. A choke holds back pressure by
restricting the flow opening at the well head. Back pressure restricts the uncontrolled expansion and
rise of the gas and thus helps keep the gas dispersed in the liquids on the way up the tubing.
3.3.2.3 Sub Surface Safety Valve (SSSV)
In case of wellhead and/or Xmas tree failure of the naturally flowing wells, a secondary safety device
known as a subsurface safety valve (SSSV) will stop the flow from the well. There are two kinds of
subsurface safety valves, one operated from the surface (a surface controlled subsurface safety
valve/SCSSSV) and the other which will be close automatically with a given predetermined flow
condition.
Assuming a pressure rating for the SSSV of 400 psi, a safety factor of 75 psi and maximum hydraulic
gradient of 7 PPG (0.364 psi/ft), the maximum setting depth of the SSSV is:
3.3.2.4 Side Pocket Mandrel
The side pocket mandrel contains an off-centre pocket with a hole to provide communication
between annulus and tubing.
3.3.2.5 Packer
A packer is a device with rubber elements which can expand with some mechanism and provide
sealing ability between tubing and casing annulus. It will be located as close to the top of reservoir as
possible to minimise the possibility of high pressure gas accumulation below the packer.
We will use dynamic seal assemblies between tubing and packer to accommodate the tubing
contraction and expansion movement due to temperature.
82
3.3.2.6 Wire Wrapped Screen
A wire wrapped screen will be used as a sand control method. This screen is well suited for excluding
sand of medium grain size. The maximum screen size will be determined by analysing the particle
size distribution from core analysis.
3.3.2.7 Downhole Pressure Gauge
Having an accurate measurement of pressure and temperature will facilitate accurate input for
history matching in reservoir simulation. By having such data, hopefully we will be able to select the
best development scenario to maximize the liquid recovery, typical completion design Figure 30.
Figure 30 Well completion design
3.3.3 Host Facility and Hydrocarbons Export
Horizontal separators will be utilised because they have advantages around separating large volumes
of gas from liquid. It has a larger interface area than vertical separators, giving better foam/emulsion
83
handling. Test separator will be used to measure each well production accurately to determine the
development plan for the field.
The top side facility will be capable of handling 80,000 BOPD, 92,000 BWPD, 45,000 MSC/D and
100,000 BLPD at respective peak production times. Three phase separators will be used to separate
gas and water from oil. Three stages of separators are used to minimize the power requirement,
maximize liquid recovery and also avoid a large pressure reduction in a single separator which could
cause flash vaporization leading to instabilities and safety hazard. The high pressure separator will
operate at 400 psi, medium pressure separator at 150 psi and the low pressure separator at standard
pressure and temperature.
Gas from separators will be used for generating the platform’s electricity, gas lift and for sale. Before
going to the compressors for gas lift/export, the gas has to be dehydrated first to eliminate any water
content which may create a hydrates problem. It also needs to be processed to extract the CO2 and
H2S to avoid corrosion in the pipe. Multi stages compressors will be used to minimize the compressor
power while maximizing the liquid recovery. The gas from processing facility will be connected by
pipeline to the Angel platform.
Produced water from the separator has to be treated properly before it is injected back into the
reservoir for pressure maintenance. Scale inhibitor will be used to avoid the incompatible mixture
between formation water and sea water. Hydrocyclones might be combined with de-gassers to
remove the oil content from the water. Filters will be used as a solids removal devices from water.
This separation process is shown in the flow diagram below Figure 30.
84
Figure 31 Flow diagram for produced fluids
3.3.4 Flow Assurance
3.3.4.1 Inorganic Scales
NaCl Salt scale will precipitate due to cooling of well fluids and/or evaporation of the water into the
gas phase during production of saturated brines to surface. High content of Sodium and Chlorides in
the water may create problems (NaCl scale).
Carbonate scales will form if the pressure decreases. One form of carbonate scale we can expect the
W-Field reservoir is CaCO3. A moderate amount of Calcium may create CaCO3 (calcite) scale if there
is enough hydrogen carbonate (HCO3) in the water. From water analysis, there is no carbonate ion
which means the tendency of calcium carbonate scale is very small.
Sulphate scales will form if we mix incompatible brines. The SO4 ion from seawater will react with Ba,
Sr or Ca from formation and creates sulphate scale. As we can see from water analysis Figure 32
below,
85
Figure 32 Scale Percipitation and different Sea Water Saturation
From “Sulphate scale precipitation arising from sea water injection: a prediction study” paper of
Mingdong Yuan, Adrian C. Todd and Kenneth S. Sorbie, we can conclude that the celestite (SrSO4)
and anhydrite (CaSO4) scale will not form at early injection water breakthrough like barite scale will
do. They will start to precipitate at mixing ratio between 34-92% of sea water and formation water.
In that case, we do not need scale inhibitors from the first production. Late scale inhibitor injection
might cause the scale dissolver becoming less efficient because of the small surface area effects.
To maximize the economics, scale treatment will be applied after we get an indication of sufficient
sea water breakthrough. This continuous treatment is chosen because it is the most economical
method and it does not have formation damage concerns like squeeze acidizing. If scales are
detected between bottom injection pipe and perforation interval, then squeeze acidizing may be
used to solve scaling problem.
3.3.4.2 Organic Scales
A relatively small value of Vanadium (10 ppm) and Nickel (4.5 ppm) indicates that there will be a
small possibility of Asphaltenes precipitation from the Palaeocene crude oil if we operate below the
bubble point. Asphaltenes are stable above bubble points and at low pressures.
Wax is unlikely to form because Australia subsea temperature is warm enough (68°F) for wax
precipitation.
86
3.3.4.3 Corrosion
CO2 and H2S are the gases which contribute to the corrosion of the pipe work. From our reservoir
sample analysis, we do not have any H2S presence in our system but we have CO2 content between
0.88 – 1.2 mole percent is to equal to 22 – 29 psi partial pressure. CO2 is corrosive when in contact
with liquid water at 30 psi or more partial pressure. To mitigate corrosion during the field production
especially with the possibility of increased CO2 with changes in partial pressure, we will use Corrosion
Resistant Alloys or steel grades alloyed with high contents of Chromium, Molybdenum and Nickel.
3.3.4.4 Erosion
Assuming the sand control from the wire wrapped screen is effective, there will be no erosion caused
by sand. Tubing erosion might occur if the wire wrapped screen is eroded and fails due to the high
flow rates and high temperature of reservoir fluids.
3.3.5 Tubing Selection
3.3.5.1 Production Tubing
Based on the sensitivity run on production technology software, WellFlo, the relationship between
inside diameter of tubing and production rate is as shown in Figure 33.
Figure 33 Tubing Size Sensitivity
87
The optimum inside diameter of tubing from the sensitivity analysis is 5 inch which leads us to the
5.5 inch (OD) tubing size. To use the tubing in the field operation, we have to check its burst and
collapse rating against the operating conditions. The burst and collapse calculations are shown in
Appendix V, Figure 3 shows us the maximum operation pressure of 3210 psi for burst and 2919 psi
for collapse. The pipe burst and collapse pressure for 5.5” (5.012” ID, 14 lbs/ft) is 4270 psi and 3120
psi which is still above the operating pressure.
3.3.5.2 Injector Tubing
The maximum injection rate per well is 20,000 BWPD as shown in Table 33 below. Using WellFlo for
tubing size sensitivity analysis resulting on 6” tubing with 5.352 ID and 20 lbs/ft of weight. The
internal minimum yield and collapse pressure of this casing is 7560 psi and 5690 psi which is still
above the maximum operating pressure of 4000 psi.
The sea water for water injector will be filtered before being injected to the formation to separate
solids larger than 2 µm from the water.
OD
ID
(inch) (inch)
3.5
5
4
4.408
5.132
6
5.352
5.62
6
7
6.336
6.52
Operating
pressure
(psi)
3897.23
3913.87
3928.39
3954.43
3962.02
3970.87
3982.49
3991.72
3996.32
Liquid
Rate
(stb/d)
8567.18
11579.08
14207.72
18920.8
20295.04
21898.02
24002.08
25671.91
26505.62
Table 33 Injection Tubing size sensitivity
3.3.6 Pressure Maintenance
Water will be injected as early as possible to maintain the reservoir pressure above bubble point and
to maximize the liquid recovery. The water injection facility will be injecting a maximum of 100,000
BWPD. We will use sea water earlier during production when we still have very low water cut from
88
our produced fluid. When the water cut increases, we will reuse formation water and reduce the
volumes of sea water injection.
3.3.7 Artificial Lift
3.3.7.1 Gas Lift
Some of the produced gas will be injected back to the well as gas lift. The gas lift will increase the
production close to the rate at initial peak production i.e. 12,000 BOPD. The amount of gas required
for gas lift will be 4 MMSCF/d. A further increase in gas injection will increase the flow rate, but the
cost to provide this gas injection is more than the additional barrels of oil making gas injection above
4 MMSCF/d uneconomic which can be seen in Figure 34.
We will use three valves located at 4248’, 7262’, and 8035’ TVD. The maximum casing head pressure
will be at 2000 psi to enable the placement of gas lift operating valve as deep as possible to maximise
liquid production.
Figure 34 Gas Injection Sensitivity
3.3.7.2 ESP
ESPs are known for their ability to produce high water cut liquid in very high rate wells. Since there is
a possibility of sand control failure, gas lift is unaffected by produced solids therefore the better
choice of artificial lift. In addition, the maintenance cost of ESP might be higher than gas lift because
ESP has a lot of moving parts which are subject to failure.
89
For our peak target rate i.e. 12,000 STB/d (14,617 RB/d) the most suitable pump available is 53812500 with 50 stages - 92 hp motor from Weatherford which has a operating flow rate between 8000
– 16000 RB/d. Detailed here in Table 34.
Oil Production (BOPD) at water cut (%)
Recovery
method
Natural
depletion
ESP
Gas lift
0
10
20
30
40
8098
5397
3464
2068
665
10496
8261
6223
4441
11223
8812
6936
5435
50
60
70
80
90
1203
653
No operating point
Below pump minimum
4211
3213
2358
1668
Table 34 Production Tubing water cut sensitivity
3.4
Reservoir Management and Monitoring
3.4.1 Production Profile
PRODUCTION PROFILE
90,000
80,000
70,000
BOPD
60,000
50,000
40,000
30,000
20,000
10,000
0
2015
2017
2018
2020
2022
2023
2025
2026
2028
2030
2031
2033
2035
Year
Figure 35 Production Profile
After trialling 18 cases in eclipse simulation software, the best case of depletion from the Palaeocene
reservoir consisted of eleven producers and five water injectors. As you can see from Figure 35
above, production will take approximately one year to build up to the plateau which is expected to
be held for four years followed by a declining phase and field abandonment after year 2035. The
maximum field production rate at plateau will be 80,000 BOPD. With a field average OPEX/year of
US$100,000,000 assuming oil price of US$85.2/bbls the economic rate of the field is 1400 BOPD.
90
3.4.2 Project Schedule
The drilling sequence for the field development is to drill and complete all the injector wells during
the first half of year 2015 and then drill six new producer wells between June 2015 and June 2016.
The injectors are drilled before the producer to give a better support to the reservoir pressure and
keep it above bubble point. The plan for production wells is to drill and complete them as fast as
possible to bring the production forward to get the maximum economic impact. A floating storage
unit (FSU) will be taken as an asset and two tankers will be leased for a greater NPV. A high level
project schedule is shown below, Figure 36, with a more detailed summary shown in Appendix V,
Figure 2.
Figure 36 Project Schedule
3.4.3 Well Management and Monitoring
3.4.3.1 Production Well Management
The production wells will be choked at early production and will be opened gradually with the
decrease ng of reservoir pressure to maintain the plateau phase. The change in the reservoir
pressure will be monitored by installing downhole pressure gauges in the production wells. The liquid
velocity will be limited to prevent excessive erosion of the wire wrapped screen. In addition best
practices to prevent sand production will also be considered:

Increase the production rate slowly

Producing below “maximum sand-free rate”
91
The key point in the lifetime of the production wells is to sustain the plateau as long as possible while
monitoring the wellbore condition.
3.4.3.2 Injector Well Management
Scale inhibitors will be injected along with the sea water to avoid the scale precipitation in the
borehole because of the incompatibility between sea water and formation water. The injection rate
and pressure will be kept below the fracture pressure to ensure the pressure support and water
displacement works efficiently.
3.4.3.3 Wells Monitoring
To maximize the wells utilization, monitoring systems will be used to increase understanding of the
reservoir. With monitoring systems we will be able to schedule workover activity or do corrections
before a problem becomes extensive and potentially creating large losses in production. The
monitoring systems are:

Water sampling: an increase in any ion for example barium, calcium or strontium and/or an
increase in sea water breakthrough would indicate the high possibility of scale precipitation
which can be prevented by injecting inhibitors.

Oil sampling: The oil properties might change during the production, oil sample are
measured for their vanadium and nickel content to get an idea of asphaltenes precipitation.
In addition, oil properties (viscosity) are also required to determine how effective water
flooding is performing. Oil composition might be analysed to determine its pour point which
may be useful to improve the surface facilities.

Downhole pressure and temperature: A lot of information can be derived from these types
of measurements. For example, we will be able to measure changes in productivity index,
allowing accurate simulation of reservoir performance. We will also be able to measure the
tendency of asphaltenes and wax precipitation due to pressure and temperature.
92

Flow meter: We will use flow meters to be able to produce in the “sand-free rate” and also to
maximize the drawdown pressure.
3.4.4 Well Intervention
In order to maintian optimum production throughout the life of the field, the wells will require some
maintenance. There are two types of well intervention: major well intervention and minor well
intervention.
3.4.4.1 Major Well Intervention
This type of well intervention requires a drilling/workover rig due to the damage which occurs in the
system. Major well interventions have a bigger impact on project economics than minor well
interventions, since the well has to be taken off production to allow access to the tubing. The
problems which may create major well intervention are:

Completion (e.g. wire wrapped screen, production tubing) failure and replacement

Wellhead failure and replacement

Plugging a watered interval
3.4.4.2 Minor Well Intervention
This type of well intervention does not require a drilling/workover rig and may be done by using a
wire line or coiled tubing unit. Some examples of activities in minor well intervention are:

Well stimulation e.g. acidizing

Change of a gas lift valve

Changing of a subsurface safety valve
3.5
Environmental Impact and Abatement
3.5.1 Non-Technical Summary
The environmental statement (ES) presents the findings of the environmental impact assessment
(EIA) conducted by Mungo Energy for the development of field W, in the North-West Region of
Australia, in block WA-418-P. Field W is located in the North-West Province 160 km from the nearest
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coastline in a water depth of 80m. The purpose of the ES is to provide an assessment of the potential
environmental effects that may arise from the proposed operations and to identify measures, which
will be put in place to minimize these effects. The objective of the EIA process is to incorporate
environmental considerations into the project planning, to ensure that the best practice is followed
and, ultimately, to achieve a high standard of environmental performance.
3.5.2 The Existing Environment
The key sensitivities of the area can be summarized as follows:
Climate characteristics: The temperature in the NW region has a wide range of fluctuations from 0°C
in the winter to 40°C in the summer. The main characteristic of the area is the presence of cyclones
during the wet season. A tropical monsoon climate with two distinct seasons occurs across the
region.
Benthos: It can be divided into two main categories-infauna and epifauna-. Infauna is consisted of
organisms such as polychaete worms along with gorgonians, bryozoans and sponges. Epifauna
species, which are identified in the development area, consists of hermit craba, tubeworms and
anemones.
Fish Species and marine mammals: There are over 600 fish species in the region, with the main
being sharks, sea turtles and whales.
Seabirds: Field W has a wide range of seabirds, such as noddies, petrels, shearwaters, tropicbirds,
frigatebirds and boobies.
Other users of the sea: The local economy is supported mainly from the commercial fisheries. In the
area operating 14 fisheries, with main fish targets including prawns, scalefish, scampi, shark and
crabs. Furthermore, in the region there are the ports of Dampier and Port Hedland, which also play
an important role in the development of the area. They handle large tonnages of iron ore and
petroleum exports.
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3.5.3 Significant Risks and Mitigation Measures
A risk assessment has been undertaken by Mungo Energy, in order to identify those potential
impacts that might cause significant effects, so that they can be more fully assessed and mitigated as
necessary. Extended details of these environmental effects with their associated mitigation measures
are in Appendix VIII. The results of this assessment along with their mitigation measures can be
outlines as follows:

The physical presence of the drilling and support vessels
Mitigation measures: A 500m-safety zone around the rig would prohibit fishing and other vessel
activity. In addition, consultation would be carried out with other users of the sea, and notification
given to mariners of the rig movement and drilling location.

The discharge of water-based mud and cuttings from the development well
Mitigation measures: All drilling chemicals or products would be subject to a chemical risk
assessment prior to drilling, as required by the Offshore Chemical Regulations 2002. The generated
WBM will be treated and disposed to the location. OBM and associated cuttings will be treated also
and will be shipped back to shore for further treatment or disposal.

The atmospheric emissions that would arise from the installation of the development
infrastructure
Mitigation measures: All engines, generators and other combustion plant would be well maintained
and correctly operated, to ensure that they were working as efficiently as possible to minimize
emissions. Some, atmospheric emissions considered being of low importance.

The noise generated from the installation of the piles of steel jacket platform
Mitigation measures: Application of the best available technique and efficient-accurate planning of
work program to minimize the potential environmental effects. Furthermore, by installing piles during
summer, they are protected and will not be affected in their breeding.
95
The local disturbance to the seabed caused by pipeline trenching and backfilling
Mitigation measures: Before the installation of pipes, surveys on seabed will be carried out to
ensure that the pipes are placed on the right location. Use of previous 3D seafloor mapping for
accurate pipeline positioning can be very useful in this stage.

The installation and physical presence of the subsea structures
Mitigation measures: The subsea structures can cause the reduction of the fishing activity in the
area. So, they will be enclosed within protective tubular steel frames, which are designed to have a
fishing-friendly profile. Furthermore, other users of the sea, including commercial fishermen, would
be consulted about the proposed pipeline route during the detailed planning stage, in order to avoid
their activities in this area.

Any accidental hydrocarbon spillage or release
Mitigation measures: The contingency plans in place would consider all foreseeable spill risks and
would ensure that the spill risk is reduced to as low as reasonably practicable. In addition, specialized
personnel with the appropriate knowledge will help in any possible oil spillage situation.
3.5.4 Conclusions
From the assessment of potential impacts, there will be some environmental impact in the proposed
area. However, Mungo Energy is committed to following the appropriate mitigation measures
properly, as they are described in the ES, in order to minimize the effects on the environment.
Overall, it is therefore concluded that the environmental impact during the W-FIeld development will
not incur any significant long lasting environmental effects.
3.5.5 Environmental Management
Mungo Energy is committed to ensure that the whole environmental program will be followed
strictly through the life of the project, in order to maintain the environment in the appropriate levels.
In addition, the company has created a Health, Safety and Environmental Management System (HSE)
96
that ensure all activities are managed in a safe, responsible and efficient manner. The management
system will be subject to internal reviews and audits. Audits will be planned and progress will be
reported monthly to the senior management.
Finally, the Environmental Management System can be outlined in the following headings:

Policy

Organization

Planning and Implementation

Performance Management

Audit and Management Review.
3.6
Field Abandonment Programme
The decommissioning plan which is proposed by Mungo Energy is in line with DECC guidance and also
complies with the regulations in place at that time. The main legislative framework for the
decommissioning stage, consists of the Convention on the Protection of the Marine Environment of
the North Sea Atlantic 1992 (OSPAR Convention) and especially from OSPAR Decision 98/3, in which
the whole removal of the installation is demanded by each operator.
The following procedures will take place for each part of the development:
WELL ABANDONMENT
At the end of project life, all the wells will be plugged in order to ensure that the reservoir unit is
isolated properly from surface. Conductors and casing facilities are recommended to cut and covered
ten feet below the seabed.
STEEL JACKET
According to the relevant legislation, the steel jacket will be completely removed for reuse or
recycling or final disposal on land.
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PIPELINES
According to the relevant legislation, Mungo Energy considers the best option for decommissioning
of pipelines to leave them in situ. Consequently, the environment can cover them from itself and
there will not be further disturbance on the seabed from their removal.
DRILL CUTTINGS
Mungo Energy proposes that in the case of the cuttings, a critical valuation should be done in
accordance with the relevant legislation, in order to identify whether removal or disposal in the field,
is the most appropriate method.
Furthermore, the casing strings cut at least 10 ft below the seabed. The Xmas tree can be recycled
onshore or refurbished and sell it for reuse.
According to the financial analysis, the total cost of the decommissioning plan has been estimated to
be 260 million dollars.
For more detailed description of the Decommissioning Plan, the Environmental Statement of Mungo
Energy is provided.
3.7
Costs
3.7.1 General
Costs associated with the development of the W-Field have been estimated in Questor in money of
the day $2011 and then economically appraised with respect to the local economic environment in
Australia. All values are in US dollars and in money of the day 2012 terms. A detailed cash flow is
shown with Appendix VII, Table 8 and applicable fiscal imposition is shown in Appendix VII, Table 9.
3.7.2 Exploration, Appraisal and Development Costs
The costs surrounding exploration and appraisal activates has not been included in our field
development appraisal these have been considered as sunk costs incurred before the project was
considered as a worthwhile investment. A development costing (CAPEX) summary is included in
Appendix VII, Table 5. Which includes equipment, materials, fabrication, installation, design,
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management and contingency costs for topsides, steel jacket, pipelines, subsea equipment and
offshore loading activates. This came to a total of $1,121,793,000.
3.7.3 Operations Expenditures
Estimates of operating costs (OPEX) over the full 20 year life of the project have been estimated
yearly to include direct costs: operating personnel, inspection and maintenance, logistics and
consumables, wells and insurance. Operation expenditures also include Field/Project costs and tariff
costs. The final OPEX total is US$2275 Million. A detailed summary per year is included within
Appendix VII, Table 6.
3.7.4 Abandonment Costs
Mungo energy and the W-Field project will be abiding to UK decommissioning regulations which
state all platforms and facilities must be removed for reuse, recycling or scrap. More detail on this is
contained in the Environmental Statement. The decommissioning concerns materials, fabrication,
decommissioning/removal, Design, Contingency and scrap for the topsides, steel jacket, pipeline,
subsea equipment and offshore loading. The total cost of this came to $268845000. A detailed
summary is included in Appendix VII, Table 7.
3.7.5 Pollution Liability Provision
Mungo energy abides by all UK environmental regulations and we feel the voluntary oil pollution
compensation scheme, OPOL – The Offshore Pollution Liability association, is a worthwhile
investment for the future of our operating and exploration activates. This will also strengthen
pollution liability provisions currently in place in Australia by adding another contributory source of
aid that may be needed by other companies operating in the area in future years. In terms of costing
the annual sum paid to OPOL is not know, but this figure will be modelled into the cash flow under
Field/Project Costs as an OPEX cost.
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3.8
Field Uncertainty
There is still doubt around many uncertainties within this FDP and to create better awareness of
them the following table has been created, Table 35. To better manage the project the following
mitigation measures have been suggested. With increasing information about the field from drilling,
3D seismic and other investigative activates the uncertainty around these issues should be reduced
and better understood.
Discipline
Geology
Petrophysics
Drilling
Production
Reservoir
Modelling
Commerical
Analysis
Description
OWC
GRV
Core Samples
Faults
Seismic
Depositional Environment
Wash out
Water saturation
Core depth
Permeability value
STOOIP
Constants
Insufficient Mud Log Data
Overpressured Interval
Borehole Collapse
Mitigation Measures
RFT Survey
3D Seismic
More samples in palaeocurrent
3D Seismic
3D Seismic
Investigation into similar fields
correct the reading from borehole effect
RFT Survey
Depth shifting
Well test to have greater radius of investigation
Drill more well to gather more reservoir data
Detailed reservoir properties
Sufficient Overbalance
Sufficient Overbalance
Observe Cuttings
add scale inhibitor
produced fluid sampling
BHP observation
Uncertainty Impact
L
H
M
H
M
L
H
M
H
M
L
M
M
L
L
L
M
L
H
L
M
H
L
M
M
H
L
M
L
H
Scale Percipitation
Sand production
Aquifer support
Downhole equipment
integrity
Geomodel
Upscaling of Geomodel
Aquifer support
Vertical Permbeaility
Petrophysical model
Too high reserves estimate
Oil Price
Production Rate
Taxation Imposition
Pollution Liability Provision
Noise
Environmental Health and Safety
Oil spills
L
H
M
H
H
M
M
H
M
M
M
L
M
M
M
L
M
M
M
H
H
M
L
M
L
H
H
H
H
M
H
L
H
H
BHP observation
Improve geological knowledge (New wells/3D Seismic )
Accurate and meanigfull upscaling
RFT/Well Test data around OWC datum
More samples SCAL and Relative Permeability Curves
More samples SCAL and Relative Permeability Curves
3D Seismic Data/Improve Geomodel/Hystory Match
Careful Monitoring of Market Conditions
Consistent Well Rates
Ensure good communication with government
Liase with OPOL, determine cost to Project
Adopt best available techniques
All employees follow best practices set by Mungo Energy
Emergency plans indlucing trained specialed personnel
Table 35 Ranked Uncertainties
Legend: H = High, M = Medium, L = Low
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4.
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