MSc Group Project Presentation

Field Development Plan
Team (A) – AQUA
1IPE FDP 2014 - Team A7/11/2016

Contents:
• EXECUTIVE SUMMARY
• FIELD DESCRIPTION
• DEVELOPMENT AND MANGEMENT PLAN
• CONCLUSION
2IPE FDP 2014 - Team A7/11/2016

EXECUTIVE SUMMARY
3IPE FDP 2014 - Team A7/11/2016
STOIP: 806 MM
bbl Stock
Water
Injection
Technique
FPSO + Tie
to existing
Pipelines
10 New Production
Wells + 6 New Injection
Wells (16 Wells)
20 Slots
SubSea
Template
Oil Pipeline
Gas Pipeline
Recovery Factor
47.8 %
First Oil Q3
2017
NPV (0.10)
$2014 7,727
MM USD
HSE Standard

FIELD DESCRIPTION
Seismic Interpretation
4IPE FDP 2014 - Team A7/11/2016
Seismic plot used for basic interpretation of the reservoir, structure.
• An anticline, with possible syn-depositional faults
• Pinching out of the main sands and the Ribble sands towards NNW

FIELD DESCRIPTION
3-D Model of X-Field, with Faulting Visible in Blue
5IPE FDP 2014 - Team A7/11/2016

FIELD DESCRIPTION
Severity of the edges
6IPE FDP 2014 - Team A7/11/2016
Severity of the edges, in
the top structure of the
X-Field, which can be
used for detection of
possible faulting from
the Top Structure.

FIELD DESCRIPTION
2D Contour of X-Field
7IPE FDP 2014 - Team A7/11/2016
2-D Contour of X-Field with
Possible Faulting directions
highlighted in blue and pink,
the extent of the faulting is
approximated by the
distance to the nearest fault
from well test
interpretations, visible as
red circles.

FIELD DESCRIPTION
OWC (Oil Water Contact)
8IPE FDP 2014 - Team A7/11/2016
The wells X1, X2, X3 and X4 lie in the region with the lower
OWC at 10850 ft. TVD SS, and the Well X5 and X6 lie in the
region with the shallower OWC, at 10560 ft. TVDSS, with 2
Wells seeing opposite trends, X2 being almost all water, and
X6 being all oil.
Well-X1 Well-X2 Well-X3 Well-X4 Well-X5 Well-X6

FIELD DESCRIPTION
Conceptual Explanation for Different Oil-Water Contacts observed in the X-Field
9IPE FDP 2014 - Team A7/11/2016

FIELD DESCRIPTION
Field Stratigraphic Correlation
10IPE FDP 2014 - Team A7/11/2016
Full Field Stratigraphic Correlation for the X-Field,
with all the wells in the section, and in order
X1,X2,X3,X4,X5,X6, with no preferred direction.

FIELD DESCRIPTION
Stratigraphic Correlation Panel (1) for Wells X2, X1, X6 and X5
11IPE FDP 2014 - Team A7/11/2016
Stratigraphic Correlation for Wells X2,
X1, X6 and X5, in the direction SE-NW,
with faults shown in red.

FIELD DESCRIPTION
Conceptual Geological Model from Stratigraphic Correlation Panel (1)
12IPE FDP 2014 - Team A7/11/2016

FIELD DESCRIPTION
Stratigraphic Correlation Panel (2) for X4, X6, X1 and X3
13IPE FDP 2014 - Team A7/11/2016
Stratigraphic Correlation for Wells X4, X6,
X1 AND X3, in the direction NE-SW, with
the fault across well X-6 shown in Red.

FIELD DESCRIPTION
Conceptual Geological Model from Stratigraphic Correlation Panel (2)
14IPE FDP 2014 - Team A7/11/2016

FIELD DESCRIPTION
Core Image Analysis
15IPE FDP 2014 - Team A7/11/2016
Oil-Stained Cores
Interbedding
with Mudstones
Sand-Filled Mud
Lined Burrows

FIELD DESCRIPTION
Palaeocurrent Direction of Interpreted Sediment Supply
16IPE FDP 2014 - Team A7/11/2016

FIELD DESCRIPTION
Interpreted Geological Sequences of Evolution of the field
17IPE FDP 2014 - Team A7/11/2016

FIELD DESCRIPTION
Indicators for Shallow Marine Environment
18IPE FDP 2014 - Team A7/11/2016
 The Main Jurassic Sand Units thins out towards the east because of sedimentary input
from the SW-NE direction.
 Core image samples that shows the bioturbated mudstone lamina and trace fossils
present.
 A general coarsening up texture of rock.

FIELD DESCRIPTION
GEOLOGY AND RESERVOIR DESCRIPTION
19IPE FDP 2014 - Team A7/11/2016
The Formations in the X-Field can be classified into five diff types of sub-units.
• Ribble Sand which is highly permeable (1000mD) and porous representing very
good to excellent reservoir characteristics.
• Clyde is very low permeability (10-50 mD) with poor reservoir characteristics.
• Lydell, Mersey and Usk Sands show permeabilities that are varying from very-
high to moderate values (average 670 mD) resulting in a reservoir unit that is
good to moderate in quality.

FIELD DESCRIPTION
20IPE FDP 2014 - Team A7/11/2016
Multi-Well Histogram for Core Derived Porosities for X1, X4 and X5
Porosity X1 X4 X5
Minimum 3.6 % 10.2 % 3.7 %
Maximum 33.3 % 32.4 % 28.8 %
Std. Deviation 5.92 % 3.23 % 5.21%
Mean 22.32 % 24.65 % 20.8 %

FIELD DESCRIPTION
21IPE FDP 2014 - Team A7/11/2016
Multi-Well Histogram for Core Derived Permeability for X1, X4 and X5
K X1 X4 X5
Minimum 0.01 mD 0.05 mD 0.01 mD
Maximum 4500 mD 2900 mD 3600 mD
Std.
Deviation
801.91 mD 734 mD 789.54 mD
Mean 733.12 mD 767.2 mD 564.53 mD
Cutoff 1 mD 1 mD 1 mD

FIELD DESCRIPTION
Cross Plot Multi Wells (Core Permeability – Core Porosity) for X1, X4 and X5
22IPE FDP 2014 - Team A7/11/2016
Porosity and Permeability, plotted on a semi-log graph, showing two different trends for Well X1, and
Wells X4 and X5, thereby hinting that the main reservoir units, in Well X1 is different from Wells X4
and X5.

FIELD DESCRIPTION
The Permeability and Porosity profiles for the Well X5
23IPE FDP 2014 - Team A7/11/2016
The Permeability and
Porosity profiles for
the Well X5, hint at the
existence of possible
layering within the
reservoir section, with
layers of very high and
very low
permeabilities, which
is also being confirmed
in the Lorentz Plot (in
the next slide)

FIELD DESCRIPTION
Lorenz Plot and Semivariogram for Core of well X5
24IPE FDP 2014 - Team A7/11/2016
Well X5, was chosen for core analysis, as it has all three sets of data, with sufficient sample
sizes for each of the four distinct zones , along with core photographs, and RFT data.

FIELD DESCRIPTION
Core Derived Porosity and Permeability Cross plot for Core-Data in Well X5
25IPE FDP 2014 - Team A7/11/2016

FIELD DESCRIPTION
Cross Plot Multi-Wells (Porosity – Formation Resistivity) for X3, X4 and X5
26IPE FDP 2014 - Team A7/11/2016
For the estimation of Rw, both “Pickett Plot” and “Rwa” method have been used, and the value of
Rw, in the field was approximated at 0.03 OHMM. Values of Rm and Rmf are from the log headers.
Porosity

FIELD DESCRIPTION
Facies identification
27IPE FDP 2014 - Team A7/11/2016
• For our facies identification , we decided to go for a sand/shale system, and used the ROCK_NET flag
generated from the summaries section in Techlog.
• For estimation of Water Saturation (Sw), we used was the Indonesia Equation, as the Archies
Equation is only for clean sands.
• For Vshale, cutoffs from Histogram, and Clavier Equation.
• KMOD for Permeabilities.
Well-X1 Well-X2 Well-X3 Well-X4 Well-X5 Well-X6

FIELD DESCRIPTION
Cross Plot (Neutron-Porosity – Bulk Density) for wells X1-X6
28IPE FDP 2014 - Team A7/11/2016
Density-Neutron Cross
plots for all Wells, the
main outlying points,
belong to the bottom
most Non-Reservoir
Unit, Sand-5 (Very-
Shaly Sand), and
excluding those
outlying points, the
entire lithology falls
along similar trends,
agreeing with our
interpretation of a
sand & shale system.

FIELD DESCRIPTION
Multi-Well Gamma-Ray Histogram for Wells X1-X6
29IPE FDP 2014 - Team A7/11/2016
Higher than
normal Gamma
Ray Values for
the Reservoir
Sands especially
in Wells that lie
within the area
under the Clay
Seals (Wells- X1,
X2)

FIELD DESCRIPTION
HYDROCARBONS IN PLACE; Deterministic Reserve Estimation
30IPE FDP 2014 - Team A7/11/2016
WORST MOST PROBABLE BEST
Area (acres) 2425.5 2425.5 2825.5
Thickness (feet) 100 340 580
Porosity (%) 0.18 0.23 0.33
Water Saturation (%) 0.4 0.2 0.1
Form. Volume Factor (bbl/stb) 1.49 1.43 1.33
NTG 0.89 0.98 0.99
STOOIP (MMSTB) 121.386 806.7262111 2810.62
Deterministic Reserve Estimation, using parameters from the Petrophysical Analysis

FIELD DESCRIPTION
HYDROCARBONS IN PLACE; Probabilistic Reserve Estimation
(Latin Hypercube Method)
31IPE FDP 2014 - Team A7/11/2016
Probabilistic Reserve
Estimation, using
parameters from the
Petrophysical Analysis,
and Latin Hypercube
Sampling.
STOOIP (MMSTB)
P10 1,274.80
P50 859.69
P90 517.70

FIELD DESCRIPTION
Sensitivity Analysis for STOIP; Tornado Chart
32IPE FDP 2014 - Team A7/11/2016
472.67
0.29
0.32
2,785.50
1.46
0.98
207.33
0.21
0.15
2,465.50
1.37
0.92
0.00 500.00 1,000.00 1,500.00
Thickness (FT.)
Porosity (%)
Water Saturation (%)
Area (Acres)
Form. Volume Factor (bbl/stb)
NTG
Sensitivity Analysis for Field-X STOOIP (MMSTB)
Upside Downside
The range of values
used for the Input
Parameters are taken
from the generated
summary of the six
wells, varying from the
best to worst values,
with the median
values assumed for the
base case, for
sensitivity analysis.

FIELD DESCRIPTION
Sensitivity Analysis for STOIP; Spider Diagram
33IPE FDP 2014 - Team A7/11/2016
400.00
600.00
800.00
1,000.00
1,200.00
1,400.00
10.00%
11.61%
13.21%
14.82%
16.43%
18.03%
19.64%
21.24%
22.85%
24.46%
26.06%
27.67%
29.28%
30.88%
32.49%
34.10%
35.70%
37.31%
38.92%
40.52%
42.13%
43.73%
45.34%
46.95%
48.55%
50.16%
51.77%
53.37%
54.98%
56.59%
58.19%
59.80%
61.41%
63.01%
64.62%
66.22%
67.83%
69.44%
71.04%
72.65%
74.26%
75.86%
77.47%
79.08%
80.68%
82.29%
83.90%
85.50%
87.11%
88.71%
Sensitivity Analysis for Field-X STOOIP (MMSTB)
Thickness (FT.) Porosity (%) Water Saturation (%) Area (Acres) Form. Volume Factor (bbl/stb) NTG
The range of values used for the Input Parameters are taken from the generated summary of the six wells, varying from
the best to worst values, with the median values assumed for the base case, for sensitivity analysis.

PVT ANALYSIS
PROPERTY MEASURED
API 40
Initial Reservoir Pressure (psi) 5745
Temperature (°F) 250
Bubble Point (psi) 1785
GOR (scf/stb) 351
Density (lb/ft3) 41.51
Viscosity (cP) 0.34
Oil Compressibility , 1/psi X10^-5 1.3
Oil Formation Volume Factor 1.41
IPE FDP 2014 - Team A 06/19/14 34

CAPILLARY PRESSURE
IPE FDP 2014 - Team A 06/19/14 35
0
20
40
60
80
100
120
140
160
0102030405060708090100
Pressure(oil water) vs pore
space %
Pressure(oil
water)
Pressure,Psia
porosity % 22.9
permeability MD
49 Depth (Ft)
10330.4
100101
100
10
1
0.1
0.01
Sw %
J(sw)
S 0.336483
R-Sq 80.8%
R-Sq(adj) 80.7%
Log Fitted Leverett-J Function for Field-X Capillay Pressure Core Data
log10(J(sw)) = 2.525 - 1.723 log10(Sw %)

RELATIVE PERMEABILITY
IPE FDP 2014 - Team A 06/19/14 36
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
0 0.5 1KR1
T 0Water Saturation, Sw
Relative
Permeability
Mersey and Lydell Sands
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0 0.2 0.4 0.6 0.8 1
KRHT
KRIT
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0 0.5 1
KR1T
KRHT
ClydeSands
UskSands

RELATIVE PERMEABILITY
IPE FDP 2014 - Team A 06/19/14 37
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
0 0.2 0.4 0.6 0.8 1
KR1T
KRHT
0
0.1
0.2
0.3
0.4
0.5
0.6
0 0.2 0.4 0.6 0.8 1
KR1T
KRHT
Ribble sands Forth Sand & Ush Sand

Well-Test Analysis
Log-Log Diagnostic(X2) Results (Oil Zone)
38IPE FDP 2014 - Team A7/11/2016
Reservoir Parameter Results
Permeability (mD) 250
Skin 1.25
Wellbore Storage Coefficient
(bbl/psi)
0.0349
Well Thickness (ft) 130
Extrapolated Pressure (psia) 5680
Reservoir Interval (ft TVDSS) 10637 - 10672 & 10688 –
10700
Productivity Index(bbl/d/psi) 35
Distance from Fault (ft) NA

Well-Test Analysis
39IPE FDP 2014 - Team A7/11/2016
Skin -3.5
(bbl/psi)
0.0349
Reservoir Interval (ft TVDSS) NA
Productivity Index(bbl/d/psi) 70
Distance from fault (ft) 220

Well-Test Analysis
• Log-Log Diagnostic(X5) Results (Oil Zone)
40IPE FDP 2014 - Team A7/11/2016
Skin 22
Wellbore Storage
Coefficient (bbl/psi)
0.2
Reservoir Interval (ft TVDSS) 10264-10332
Productivity
Index(bbl/d/psi)
64.2
Distance from fault(ft) 467 and 600 ft. (Interesting
Fault) - BU

Well-Test Analysis
41IPE FDP 2014 - Team A7/11/2016
Skin 43.6
(bbl/psi)
0.241
Reservoir Interval (ft TVDSS) 10264 – 10309
Distance from fault (ft) 325 and 325 ft. (Interesting
Fault) - BU

Well-Test Analysis
Well Test Summary Table
Well Name Well X2 Well X3 Well X5 Well X6
K(mD) 249.7 - 270.30 214.7 692.80 - 820 338.8 - 500
Kh(mD Ft) 32460 - 35143 21470 204400 - 223000 158200 - 211500
P* (psia) @
10500 ft TVDSS
5680 - 5700 5246 4304 - 4350 4826 - 4837
S (Total Skin) 0.9989 - 1.5 -3.5 20.83 - 22 43.6 - 60
Fault Detection
Distances
N/A 220 ft.
467 and 600 ft.
(Interesting Fault) - BU
325 and 325 ft.
(Interesting Fault) - BU
IPE FDP 2014 - Team A 06/19/14 42
• Permeability values from all the well test shows high heterogeneity in the reservoir.
• Formation damage(Skin) in the range -3.5 – 45.

Well-Test Analysis
Well Test Interpretations
• Fault Signatures are identified in Wells X2, X5,
X6.
IPE FDP 2014 - Team A 06/19/14 43

Well-Test Interpretations
• Semi steady state regimes are not found in
any log-log plots, therefore:
– Drainage area & Shape factor were not calculated
using pan system.
– Pmbh & Pavg could not be calculated.
IPE FDP 2014 - Team A 06/19/14 44
Well-Test Analysis

Well-Test Analysis
IPE FDP 2014 - Team A 06/19/14 45
RFT Analysis
for X1, X2,
X3 and X5
Two OWC’s
identified @ 10560
and 10840 ft. TVD SS

Case
no.
Number of
wells
Plateau
Production
(years)
Recovery
Factor
(fraction)
Base
Case
4 Producers and
2 Injectors
12.6 0.26
Case 1 9 Producers and
5 Injectors
5 0.46
Case 2 10 Producers (1
Horizontal) and
5 Injectors
4.8 0.47
Case 3 14 Producers
and 8 Injectors
3 0.478
Number of wells
The selection of the number of wells
was determined on the basis of the
combination of:
(1)Economic factor
(2)Recovery Factor
(3)Plateau production period
IPE FDP 2014 - Team A 06/19/14 46
FIELD DESCRIPTION
WELL PERFORMANCE
Producer Injectors
Existing 4 2
New 10 6
Optimum Case (Case-3)

Layer
Pressure
Water Cut Oil rate OD ID
(psia) (fraction) (bopd) (in) (in)
1900 0.9 389.2 4.5 3.958
1900 0.9 403.1 5.5 4.8
Optimum tubing diameter
“4.5 in OD “
The selection criteria:
Oil rate (bopd) @
Water cut = 0.9 (fraction)
Layer Pressure = 1900 psia
IPE FDP 2014 - Team A 06/19/14 47
Worst Case Scenario
The difference between the oil rates is very low,
thus, we go for the smaller tubing size
FIELD DESCRIPTION
WELL PERFORMANCE

Plateau
Period
Recovery
Factor
Water Cut Layer
Pressure
(years) (fraction) (fraction) (psia)
Case 3 3 0.478 0.35 5720
Natural Flow of well:-
• The well flows naturally at
the Optimum Oil rate for “3
years”
• The corresponding Layer
pressure, Water cut and
Recovery Factor are shown in
the table, also their
relationship
IPE FDP 2014 - Team A 06/19/14 48
FIELD DESCRIPTION
WELL PERFORMANCE

Artificial Lift Selection is Dual “ESP”.
Gas Lift was not used because:
• The reservoir does not produce gas
• Quantity of gas available after
separation is not sufficient
• Uneconomical to import gas from the
closet facility available
IPE FDP 2014 - Team A 06/19/14 49
FIELD DESCRIPTION
WELL PERFORMANCE

Selection of the Pump
• Available options:
IPE FDP 2014 - Team A 06/19/14 50
Specifications HN 21000 (HS) – Reda KC 20000 – Centrilift
Motor 562 Series – Reda KMH-J 562 – Reda
Min Liquid rate 20416 20416
Max Liquid rate 28000 28000
Stages 14 – 88 2 – 98
(The pump selection is based on the performance at the worst case scenario
The pumps that were available for these conditions are shown in the table)
FIELD DESCRIPTION
WELL PERFORMANCE

Selection of the Pump
• Comparison of the performances of the pumps are shown in
the table
IPE FDP 2014 - Team A 06/19/14 51
Pump Name Layer Pressure Water Cut Oil Rate
(psia) (fraction) (bopd)
HN 21000 (HS) – Reda
1900 0.9 363.8
KC 20000 – Centrilift 1900 0.9 464.6
Based on the performance @ worst case scenario:
“KC 20000 – Centrelift” is selected as the ESP
FIELD DESCRIPTION
WELL PERFORMANCE

Performance of the pump
• The table shows the point, i.e. water and Layer pressure, till
where the ESP can provide the Optimum Oil Rate
IPE FDP 2014 - Team A 06/19/14 52
FIELD DESCRIPTION
WELL PERFORMANCE
From the above table we can see that the pump will be able to produce at
Optimum rate till “5000 psia and water cut ranging from 0.41 to 0.47”
Layer Pressure
(psia)
Water Cut
(fraction)
Oil Rate
(bopd)
5720 0.35 15297.9
5000 0.41 10173.6
5000 0.47 8501.9
4600 0.35 10021.2
1900 0.2 9597.3

Formation Damage
The Formation Damage caused by:
a) Drilling
b) Cementing
c) Perforation
d) Production
– Fine movement
– Scales(organic and inorganic)
– Pressure Reduction
– Stimulation
IPE FDP 2014 - Team A 06/19/14 53
FIELD DESCRIPTION
WELL PERFORMANCE

Production Zone maintenance
• Re-perforation for water Shut-offs.
• The technical well treatment solutions to remove the
Formation Damage are as follows:
– Matrix.
– Hydraulic Fracturing.
IPE FDP 2014 - Team A 06/19/14 54
FIELD DESCRIPTION
WELL PERFORMANCE

• Selection Criteria for Well Treatment method:
IPE FDP 2014 - Team A 06/19/14 55
Treatment Type Skin Permeability
Propped Hydraulic Fracture Low Low
Propped Hydraulic Fracture High Low
Frac and Pack High Medium
Matrix High Medium/High
Treatment not required Low Medium/High
FIELD DESCRIPTION
WELL PERFORMANCE

Selection of Well Treatment Method
“Matrix v/s Hydraulic Fracturing”
IPE FDP 2014 - Team A 06/19/14 56
Parameters Matrix Hydraulic Fracturing
Hydrocarbon Saturation ˃ 40% ˃ 40%
Water cut ˂ 30% ˂ 30%
Permeability ˃ 20 mD 1-50mD
Reservoir Pressure ˂ 70% depleted ˂ 70% depleted
Based on the above table, Matrix method is chosen.
FIELD DESCRIPTION
WELL PERFORMANCE

Sand Control
Typical Allowable Sand Production Levels are mentioned in the table below:
IPE FDP 2014 - Team A 06/19/14 57
Produced Fluid Production Rate Allowable Sand Level
Light Crude Oil <5000bopd 30lb/1000bbls
5000-15000 10 lb/1000bbls
>15000 5 lb/1000bbls
• Initially, the sand production is “2.79 × 10−3lb/barrel" at the production rate
of 10,000𝑏𝑝𝑑, thus we dont need to worry about Sand production
• But, in the future with the increase in the water cut, it will be expected to get an
increase in sand production.
• At that period “Internal Gravel Pack” will be used.
FIELD DESCRIPTION
WELL PERFORMANCE

FIELD DESCRIPTION
– STRUCTURAL CONFIGURATION.
– GEOLOGY AND RESERVOIR DESCRIPTION.
– PETROPHYSICS AND RESERVOIR FLUIDS.
– HYDROCARBON IN PLACE.
– WELL PERFORMANCE.
– RESERVOIR MODELLING APPROACH.
– DYNAMIC MODEL.
58IPE FDP 2014 - Team A7/11/2016

MODELLING APPROACH
Static reservoir model :
• Created from contour map provided.
• Top & bottom Surfaces created from contours.
• Well locations were defined .
• Well logs and deviation data were input.
• Corner point gridding used to define grid, allows addition of fault.
• Horizons and layers added based on well tops created in well correlation.
• For wells where porosity and permeability data was available, it was up-
scaled.
• Properties were then distributed across the cells based on stochastic
techniques.
59IPE FDP 2014 - Team A7/11/2016

MODELLING APPROACH
Permeability Distribution
IPE FDP 2014 - Team A 06/19/14 60

MODELLING APPROACH
Cross section of model with pore distribution
IPE FDP 2014 - Team A 06/19/14 61

MODELLING APPROACH
Porosity distribution
IPE FDP 2014 - Team A 06/19/14 62

FIELD DESCRIPTION
– STRUCTURAL CONFIGURATION.
– GEOLOGY AND RESERVOIR DESCRIPTION.
– PETROPHYSICS AND RESERVOIR FLUIDS.
– HYDROCARBON IN PLACE.
– WELL PERFORMANCE.
– RESERVOIR MODELLING APPROACH.
– DYNAMIC MODEL.
63IPE FDP 2014 - Team A7/11/2016

DYNAMIC MODEL
Reservoir simulation input parameters:
• A 3-D two phase Black oil model.
• Grid Cells of 73*57*50 (NX*NY*NZ) are exported from Static model.
• Only one OWC is considered at 10840 ft. TVDSS.
• OIIP calculated by Eclipse-100 is 1.078 Billon bbls.
• Initial Reservoir Pressure is 5745 psi.
• Bubble Point Pressure is 1785 psi.
64IPE FDP 2014 - Team A7/11/2016

DYNAMIC MODEL
• Fluid properties for oil and water
were entered (i.e. oil formation
volume factor, relative
permeability, water-oil capillary
pressure data and Rock
compressibility).
• Oil-water contacts were defined.
• Model was quality checked by
comparing GRV.
• Model generated with 208,050
cells.
IPE FDP 2014 - Team A 06/19/14 65
Optimum Case (Case-3)

o DEVELOPMENT PLANS, RESERVES AND PRODUCTION
PROFILES.
o DRILLING FACILITES.
o PRODUCTION AND PROCESS FACLITLES.
o RESERVOIR MANGEMENT & MONTIORING (I.e. Production
Plan).
o ENVIROMENT IMPACT AND ABATEMENT.
o ABONDAMENT.
o COST.
66IPE FDP 2014 - Team A7/11/2016
DEVELOPMENT AND
MANGEMENT PLAN

PROFILES.
Plan).
o ABONDAMENT.
o COST.
67IPE FDP 2014 - Team A7/11/2016
DEVELOPMENT AND
MANGEMENT PLAN

Reservoir development strategies:
• Several development plan cases were considered
with various sensitivities on liquid flow rates and
water injection rates.
• Four scenarios were chosen for detailed
investigation as follows:
– Base case
– Case 1: 9 producers & 5 injectors
– Case 2: 10 producers(1 horizontal) & 5 injectors
– Case 3: 14 producers & 8 injectors
68IPE FDP 2014 - Team A7/11/2016
DEVELOPMENT AND
MANGEMENT PLAN

BASE CASE
• Natural depletion case.
• 4 of appraisal wells will be producer wells,
while two of the wells will be converted to
water injection wells.
• Wells are completed in (Layers (DZ): 1-5).
• Control mode - BHP limit of 1900 Psi is set.
• Reservoir evaluation period : 30 years.
• Recovery factor – 26 %.
• Water cut – 43 %.
IPE FDP 2014 - Team A 06/19/14 69

CASE 1
IPE FDP 2014 - Team A 06/19/14 70
• 9 producers and 5 injectors.
• Injectors completed in low
permeable zones.
• Control mode – Reservoir
Oil rate of 90,000 STB/day.
• Recovery factor of 46%
is achieved.
• Reservoir is energized
with water injectors.
• Oil recovery is increased
due to high sweep efficiency.
• Sensitivities were run on the
locations of wells and timing
of water injectors.
• Water cut is around 88.9%.

CASE 2
• 10 Producers(1 horizontal) and
5 injectors.
• 1 Horizontal wells of
2000 ft. laterals are placed.
• Reservoir Oil rate of 100,000
STB/day.
• 5 injectors will be drilled and
completed in low permeable
zones.
• Various sensitivities were run
to optimize the location and
length of the horizontal wells.
• Recovery of 47.1 %.
• Water cut is 88%.
IPE FDP 2014 - Team A 06/19/14 71

CASE 3
• 14 producers and 8
injectors.
• Reservoir Oil rate of
132,000 STB/day.
• 8 Injectors will be drilled in
low permeable zones.
• Various sensitivities were
run to optimize the location
and length of the wells.
• Recovery of 47.8 %.
• Water cut is 88%.
IPE FDP 2014 - Team A 06/19/14 72
OPTIMUM
DEVELOPMENT PLAN
CASE

SIMULATION RESULTS
IPE FDP 2014 - Team A 06/19/14 73
CASES
OIL RECOVERY
EFFICIENCY (%)
TOTAL OIL
PRODUCTION (MILLION
BBLS)
MAX WATERCUT
PLATEAU
PERIOD (YRS)
BASE CASE
(4 P + 2 I)
26 280 0.43 12
CASE 1
46 499 0.89 5
(9 P + 5 I)
CASE 2
47.1 509 0.88 4.8
(10 P + 5 I)
CASE 3
47.8 510 0.88 3
(14 P + 8 I)
* P - Producer Wells;
I – Injector Wells
FOE vs TIME

SIMULATION RESULTS
FOPR (Field Oil Production Rate)
IPE FDP 2014 - Team A 06/19/14 74

SIMULATION RESULTS
• FOIP (Field Oil In Place)
IPE FDP 2014 - Team A 06/19/14 75

SIMULATION RESULTS
FWCT (Field Water Cut)
IPE FDP 2014 - Team A 06/19/14 76

UNCERTAINTIES
Uncertainties and limitation of reservoir model:
• All the faults have not been incorporated in this
model given the uncertainty of the location and
transmissibility’s.
• For simplicity, only one oil-water contact has been
considered.
• Property variation across the fault is uncertain as
the layers pinch out.
IPE FDP 2014 - Team A 06/19/14 77

PROFILES.
Plan).
o ABONDAMENT.
o COST.
78IPE FDP 2014 - Team A7/11/2016
DEVELOPMENT AND
MANGEMENT PLAN

PROFILES.
Plan).
o ABONDAMENT.
o COST.
79IPE FDP 2014 - Team A7/11/2016
DEVELOPMENT AND
MANGEMENT PLAN

INTRODUCTION
80
The drilling program is
designed to drill 16 new
development wells in “X” field
penetrating the upper Jurassic
Sandstone formation located in
offshore Northern North Sea of
water depth 150 meters.
The wells are intended to
penetrate the “X” field structure
at the designated locations from
reservoir simulation.
IPE FDP 2014 - Team A7/11/2016

Offset Well Analysis
• The offset wells
analysis have been
conducted for the
available data for
wells X2 and X3.
• The offset well
analysis is used for
casing point selection
and the mud design.
81IPE FDP 2014 - Team A7/11/2016

Well Design Summary
IPE FDP 2014 - Team A 06/19/14 82

Subsea Template Location
The program
includes the
selection of the
center of the
subsea platform to
achieve all the
proposed wells
from single subsea
template.
83IPE FDP 2014 - Team A7/11/2016

Directional Well Program for the
longest well (J-Type)
84IPE FDP 2014 - Team A7/11/2016

Geological Prognosis
85IPE FDP 2014 - Team A7/11/2016

Pore Pressure,
Fracture
Pressure and
Overburden
86
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
11000
0 2000 4000 6000 8000 10000 12000
TVDft,RKB
Pressure, psi
PORE PRESSURE
MUD ACTUAL DATA (WELL X3)
OVERBURDEN PRESSURE (1 Psi/FT)
FRACTURE PRESSURE (EATON METHOD)_Various Poisson Ratio
FRACTURE PRESSURE (EATON METHOD)_Max Poisson Ratio (0.50)
FRACTURE PRESSURE (0.85 psi/ft)
LOT / FIT is planned
for drilling wells to
update the fracture
gradient and casing
design.
IPE FDP 2014 - Team A7/11/2016

Casing Setting
Depths,
Bottom-Up
Design
87
Obtained LOT / FIT will
be used to review the
is planned for drilling
wells to update the
casing design.
To isolate the
reservoir
section
IPE FDP 2014 - Team A7/11/2016

Casing summary Table
88
Hole Size
In
Casing
OD
In
Casing Setting Depth
ft., MD
Casing Setting
Depth (*)
ft., TVD-RKB
Casing Setting Depth
ft., TVD-SS
Casing Seating Depth Criteria
36 30 693 693 615
 Set 123 ft. below the seabed (As per offset well X3).
 Seal off unconsolidated formation at shallow depths
which, with continuous mud circulation, would be
washed away.
26 20 1383 1382 1304
 Seal off any fresh water sands.
 Case and cement off unconsolidated shallow sediments.
 Provide Structural support for the subsea Wellhead and
BOPs.
17.50 13.375 8282 6549 6471
 To isolate troublesome formations between production
and surface casing (unstable shale and lost circulation (i.e.
Chalk).
 Cased off Tertiary formations and usually set in top upper
Cretaceous
12.25 9.625 14054 10112 10034
 Set above the pay zone to isolate the production interval
from other formations and/or act a conduit for the
production tubing.
 Cased off top Cretaceous chalk and Lower Cretaceous
siltstones.
8.50 7 15555 11039 10961
 Set across the reservoir to allow selective access for
production / injection/ control the flow of the fluids from
or into the reservoir.
(*) RKB-MSL = 78 ft.
IPE FDP 2014 - Team A7/11/2016

Rig Selection Criteria
89
Criteria Selected Design Criteria Source of Design Criteria
Water Depth 150 m Given for Group A
Mud Pumps
1600 HP
Three Mud Pumps (2 + 1 Back Up’s)
HP = Q x P / 1714
For 8 ½”, 1600 HP
Hoisting System
Derrick, Draw works, fast line, dead line, travelling
block, crown block, Reserve Drum, Drilling Hook and
Elevators
The total vertical load on the rig when pulling the string = 382,036 Ib
Buoyant Weight = 15,000 ft * 22.50 Ib/ft * 0.85 = 300,000 Ib
Tension in the fast line = 300,000 / 8 * 0.842 = 44,536 Ib
Tension in the dead line = 300,000 / 8 = 37,500 Ib
BOP’s 10,000 Psi
The maximum expected Burst surface pressure from gas kick off is 4700 psi
The Maximum Pressure to surface (In case of Gas Migration to Surface) is
5800 psi
The Abnormal high pressure BOP rated as 10,000 psi.
IPE FDP 2014 - Team A7/11/2016

Rig Selection
90
Rig Name Providers Water Depth Mud Pumps Hoisting System BOP’s
West Alpha Seadrill 60 – 600 m 3, 1600 HP N/A 15 K
Ocean Ambassador DIAMOND OFFSHORE 335 m
3 x National 12-P-
160, 1,600hp, 5,000
psi
1000 KIb
Cameron 18 ¾”
10,000 psi four-ram
preventer
2 x Shaffer 18 ¾”
5,000 psi annular
preventers
Ocean Yorktown DIAMOND OFFSHORE 868 m 3 x Oilwell A1700-PT,
1,000hp, 5,000 psi
1000 KIb
Cameron 18 ¾”
10,000 psi four-ram
preventer
2 x Shaffer 21 ¼”
5,000 psi annular
preventers
IPE FDP 2014 - Team A7/11/2016

BHA Design
91
Hole Size Vertical /
Deviated
Anticipated Drilling
Problems
Primary BHA Design Secondary BHA Design
36” Hole Vertical BHA Wash out, Losses 36” Pendulum BHA
Or
26” Hole Opener Rotary BHA
N/A
26” Hole Nudge
Directional BHA
Losses 26” Nudge Motor BHA N/A
17 ½” Hole Directional BHA Slow ROP 17 ½” Motor BHA (For First Well) 17 ½” RSS BHA (Rotary Steering
BHA) will be evaluated after
drilling the first well
12 ¼” Hole Directional BHA Losses in Chalk
formation and shale
instability problems
12 ¼” Motor BHA (For First Well) 12 ¼” RSS BHA will be evaluated
after drilling the first well
(In case of no losses in Chalk
formation), this BHA can be used
to drill the shale section in lower
cretaceous.
8 ½” Hole Directional BHA Kicks, stuck 8 ½” Motor BHA (For First Well) 8 ½” RSS BHA will be evaluated
after drilling the first well
Motor BHA
RSS BHA
IPE FDP 2014 - Team A7/11/2016

Drilling Parameters
92
Hole Size Vertical / Deviated WOB, Ibs Flow Rate, GPM (*) Surface rpm Drilling Problems
36” Hole Vertical BHA 35,000 – 45,000 1000 60 Wash out
26” Hole Nudge Directional BHA 35,000 – 45,000 1300 – 1820 60 Losses
17 ½” Hole Directional BHA 35,000 – 45,000 875 – 1225
(1100 – 1200) from
Offset Well X-3
60 Slow ROP
12 ¼” Hole Directional BHA 25,000 – 35,000 612 – 857
(+/- 750 GPM) from
the Offset Well X-3
60 Losses in Chalk
formation.
Shale instability
problems
8 ½” Hole Directional BHA 15,000 – 25,000 425 – 600
(Min 500 PM) for the
offset well X-3
60 Kicks, stuck
(*) The designed flow Rate is between 50 – 70 x Hole Size (Rule of Thumb)
IPE FDP 2014 - Team A7/11/2016

Bit Design
93
Hole Size Formation
Depth
In, ft.
MD
Depth
out, ft.
MD
Bit Type Bit Picture
Rationale
36” Hole Sandstone 571 693 Mill Tooth Bit
 Mill tooth can be used to drill soft formation in top hole in
Tertiary.
 Mill tooth bit cost relatively cheaper than the Insert/ PDC
bits.
26” Hole
Mud and
Siltstone
693 1383 Mill Tooth Bit
 Mill Tooth can be used to drill soft formation in top Tertiary,
Mill tooth bit cost relatively cheaper than the Insert/ PDC
bits.
17 ½” Hole
Siltstone,
Sandstone,
Anhydrite
1383 8282
Insert Bit
(In case of
presence of
Chert)
PDC Bit
(In Case of no
chert)
 Insert bit can drill all the formation include the Chert.
 The insert bit will help to kick off using motor BHA (creates
steady tool face for orienting the motor).
 The insert bit disadvantage is the limited life by bearing
wear, increase the bit trips to drill the section, and increase
the rig time and cost.
 If geologists confirm the non-presence of the chert, PDC bit
will be used (with directional drilling features).
12 ¼” Hole
Chalk and
Siltstone
8282 14054 PDC Bit
 PDC bit can drill moderately hard formations (not chert);
ROP varies depending on the formation.
 The PDC bit should provide higher ROP than the tricone bit.
8 ½” Hole Sandstone 14054 15555 PDC Bit
 PDC bit can drill moderately hard formations (not chert);
ROP varies depending on the formation.
 The PDC bit should provide higher ROP than the tricone bit.
IPE FDP 2014 - Team A7/11/2016

Casing Design Table
94
Hole Size
In
Section Depth
Ft, MD
Setting Depth
Ft, TVD-RKB
Setting Depth
Ft, TVD-SS
Casing
OD
In
Weight, Ib-ft Grade
26 1383 1382 1304 20 106 J-55 and/or K-55
17.50 8282 6549 6471 13.375
No standard (Non
API Casing)
Due to high collapse
Load in this design
(The Collapse
resistance required
is > 3044 Psi
12.25 14054 10112 10034 9.625
47 and 53.50 (Special
Drift ID for 53.5
Ib/ft)
L80 / N-80
8.50 15555 11039 10961 7 29 L-80 / N-80
IPE FDP 2014 - Team A7/11/2016

Example for Casing Design
9 5/8” Production Casing Design
95
Assumptions:
5800 psi
4750 psi
Pi @ Top of Liner= 10990 psi
0 psi
6240 psi
Depth Pi Pe Pb Pb x D.F.
Surface 0.00 4750.00 0.00 4750.00 5225.00
Top of Liner 9600.00 10990.00 6240.00 4750.00 5225.00
Pc = Pe-Pi
Assumptions:
0 psi
0 psi
0 psi
6240 psi
Depth Pi Pe Pc Pc x D.F.
Surface 0 0 0 0 0
Top of Liner 9600 0 6240 6240 6240
Pe= Normal Pore Pressure
9.625 PRODUCTION CASING DESIGN
Burst Load:-
Pb = Pi - Pe
(ii) External Loads:
Pe @ surface =
SUMMARY
Collapse Load:-
Pe @ surface =
Pe @ packer top =
SUMMARY
Pi= Gas well, well closed at surface, leak in tubing under tubing hanger at surface, annulus
above packer is full of packer fluid
Pi= Casing empty, due to gas being switched off after gas lifting, assume well in producing
well
Pe= Normal pore pressure
(i) Internal Loads:
Pi @ surface =
Pi @ packer top =
(ii) External Loads:-
Pe @Top of Liner =
(i) Internal Loads:
Pi @ perforations top =
Pi @ surface =
BURST PLOTS
COLLAPSE PLOTS
0.00
1000.00
2000.00
3000.00
4000.00
5000.00
6000.00
7000.00
8000.00
9000.00
10000.00
11000.00
12000.00
0.00 2000.00 4000.00 6000.00 8000.00 10000.00
TVDft,RKB
Pressure,psi
Pb x D.F. Pb 47, L-80/N-80 53.5,L-80/N-80
0.00
1000.00
2000.00
3000.00
4000.00
5000.00
6000.00
7000.00
8000.00
9000.00
10000.00
11000.00
12000.00
0.00 2000.00 4000.00 6000.00 8000.00 10000.00 12000.00
TVDft,RKB
Pressure,psi
Pe Pi Pb Pb x D.F.
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
11000
12000
0 1000 2000 3000 4000 5000 6000 7000
TVDft,RKB
Pressure,psi
Pe Pi Pc Pcx D.F.
0.00
1000.00
2000.00
3000.00
4000.00
5000.00
6000.00
7000.00
8000.00
9000.00
10000.00
11000.00
12000.00
0 1000 2000 3000 4000 5000 6000 7000
TVDft,RKB
Pressure,psi
53.5,L-80/N-80 Pc 47, L-80/N-80
IPE FDP 2014 - Team A7/11/2016

Cementing Program
96
Casing Design Considerations Technique TOC
30
Design for the
Hydrostatic Pressure < Fracture Pressure (During the
CMT Job)
CMT is up to Surface to support the Subsea WH and
BOP.
Inner String Cementing
(A Stinger Cement Job)
Is to cement the casing through DP
To Surface
20
Design for the
CMT Job)
CMT is up to Surface to support the Subsea WH and
BOP.
Inner String Cementing (A Stinger Cement
Job)
Is to cement the casing through DP
To Surface
13.375
Design for the
Hydrostatic Pressure < Fracture Pressure
Single Stage Cement
TOC @ 200 ft. above the previous
casing
9.625
Design for the
CMT Job)
DV tool between the chalk and Shale to reduce the
hydrostatic head in the chalk while cementation
Two Stage Cement
TOC @ 200 ft. above the previous
casing
7
Design for the
CMT Job)
Design for the reservoir pressure and Temperature
Liner Cementation
Linear will be cemented over their
entire length, all the way from the
liner shoe to the liner hanger.
20" CSG
13 3/8" CSG
9 5/8" CSG
7" LNR
IPE FDP 2014 - Team A7/11/2016

Mud Program
97
Hole Size Formation Mud Type Mud Weight (*), ppg Technical Functions of the fluids Issues (Cost, Environments)
36” Sandstone
WBM
(Sea Water)
8.94
Drill the Top hole and the return to the sea bed.
Having drilled to the required depth, the hole is displaced to
mud to prevent debris from settling onto the bottom of the
hole when running the 30” Conductor.
Environmentally friendly.
26”
Mud and
Siltstone
WBM
(Sea Water) with viscous
pills
8.94- 9.23
Drill the top hole w/ sea water.
Spot 9.23 ppg mud prior to running 20” casing
17 ½” Hole
Siltstone (Shale),
Sandstone,
Anhydrite
WBM –
SUPER SHALE TROL / KCL
Polymer
10.19 – 11.92 Help to reduce the shale swelling.
12 ¼” Hole
Chalk and
Siltstone (Shale)
WBM –
SUPER SHALE TROL / KCL
Polymer
12.31 – 12.50 Help to reduce the shale swelling.
8 ½” Hole Sandstone
Super
Shale TROL (Semi-Disperse)
12.50
Help to reduce the shale swelling.
The skin obtained from the offset well X3 is between 0.9 – 2.5.
IPE FDP 2014 - Team A7/11/2016

Sub Sea Drilling Challenges
• The rig may disconnect from the well or even
move off location due to bad weather.
• More complex equipment such as guide frame,
marine riser, telescopic joints, riser tensioners,
and flex joints.
• Well intervention is a major technical and
economical challenge in deep water, and lack of
well maintenance can easily risk flow assurance.
98IPE FDP 2014 - Team A7/11/2016

Production and Production
Facilities
Challenges in the field:
• Pipework in subsea, place-surface and down-hole
• Corrosion/Erosion
– Not an issue initially as CO2 content is initially less
– Internal external corrosion of production facility
– Coatings/materials to avoid corrosion
• Scaling
• Asphaltenes
• Production platform
• Bottom-hole completion
99IPE FDP 2014 - Team A7/11/2016

Well completion design
100IPE FDP 2014 - Team A7/11/2016
4.5in VAM Tubing
4.5in ‘X’ Nipple
Crossover 6.5in x 4.5in
4.5in Hydril EU Tubing Tailpipe
4.5in ‘X’ Nipple
4.5in ‘X’ Landing Nipple
Wire-line Entry Guide

PRODUCTION AND PROCESS
FACILITIES
Floating Production Storage and Offloading Unit (FPSO)
 Main Functional Requirements:
– Production of crude oil;
– Processing of produced crude for oil, water, gas and sand separation;
– Treatment of produced water prior to disposal or re-injection;
– Provision of utility systems for LPF topsides and subsea operations;
– Provision of space, weight and basicutilities for potential retro-fitting of
water injection facilities;
– Space and weight provision for potential future additional produced
water treatment facilities.
IPE FDP 2014 - Team A 06/19/14 101

Surface Processing
 Topsides Facilities
• Schematic facility design
102IPE FDP 2014 - Team A7/11/2016

Surface Processing
• Facilities:
 Floating Production Storage and Offloading (FPSO) will be use for
the production of crude oil and associated gas product.
 The well fluid will be process in a single three stage gas-oil
separation train.
 The gas is compressed to the export pipe line and treated to remove
water vapour and heavier hydrocarbons.
IPE FDP 2014 - Team A 06/19/14 103

Surface Processing
• Produced water disposal
104IPE FDP 2014 - Team A7/11/2016
Corrugated Plate Interceptor
Induced Gas floatation Unit

Surface Processing
• Topsides Facilities
 Main Utility Systems: The main utility systems associated with the
topsides operations consist of:
– Chemical injection
– Emergency power generation
– Electrical power generation
– Cooling and Heating medium
– Relief and Flare facilities
– Diesel and Potable water
105IPE FDP 2014 - Team A7/11/2016

IPE FDP 2014 - Team A 1067/11/2016
SUBSEA PRODUCTION AND
ASSOCIATED FACILITIE
 Well Completions
– The wellhead will be a conventional manufacturer’s standard
product rated according to Closed In Tubing Head Pressures
(CITHP).
– Allowing the use of any mobile drilling rig (MODU).
– Completions will be single string.
– Sub-assemblies and material selection specified to minimise
planned work-over operation.
– Down-hole monitoring equipment will be used for all producers
and injectors.

107IPE FDP 2014 - Team A7/11/2016
 Subsea Trees and Controls
• The wellheads will be design to resist 65 tonnes snag loads and a
safety margin will be imposed.
 Subsea Manifolds
• Provision for manifold will be provided for the future use of
water injection for the two required functions of water injection
and control.

108IPE FDP 2014 - Team A7/11/2016
 Subsea Flow-lines
• The design will allow for hydraulic and thermodynamic regimes to
be adjusted during start up and shut down.
• The flow line will be run to the FPSO via flexible risers.
• The system design will allow circulation and pigging operation.

PRODUCTION EXPORT
SYSTEM
 Oil Export
• The crude oil produced will be exported from floating production storage
and offloading unit (FPSO) via tie back to the existing pipeline facility.
• The presence and proximity of existing pipeline which is about 70km
which currently serve Clair field is our selection (Assuming the existing
pipeline are capable to handle the production from our field).
IPE FDP 2014 - Team A 06/19/14 109

PRODUCTION EXPORT
SYSTEM
 Gas Export
The gas export will be carried out via existing gas pipe-line facility.
The nominal pipe-line diameter will be 12in from the FPSO to the deep gas diverter.
The discrete segment of the gas export pipe-line comprises:
• A rigid carbon steel pipe-line to the Deep Gas Diverter;
• An expansion spool-piece and tie-in facilities at the Deep Gas Diverter;
• Flexible riser from the FPSO to a Pipe-line End Manifold (PLEM) (which will also
house a Subsea Isolation Valve (SSIV));
• An expansion spool-piece connecting the pipe-line to the PLEM/SSIV.
IPE FDP 2014 - Team A 06/19/14 110

PROFILES.
Plan).
o ABONDAMENT.
o COST.
111IPE FDP 2014 - Team A7/11/2016
DEVELOPMENT AND
MANGEMENT PLAN

RESERVOIR MANGEMENT &
MONTIORING
• Typical Well test.
• Production profile
management.
• Downhole permanent
Sensors:
– Optical Sensing System.
• Flow Meters.
• 4D seismic
• Surveillance program.
IPE FDP 2014 - Team A 06/19/14 112
Reservoir Management
Process

PROFILES.
Plan).
o ABONDAMENT.
o COST.
113IPE FDP 2014 - Team A7/11/2016
DEVELOPMENT AND
MANGEMENT PLAN

PROFILES.
Plan).
o ABONDAMENT.
o COST.
114IPE FDP 2014 - Team A7/11/2016
DEVELOPMENT AND
MANGEMENT PLAN

ABANDONMENT
• Cessation of the production of 1,027 BPD is
determined using economic screening criteria.
• All reasonable provisions will be made during the
design construction and operational phases of the
development to facilitate abandonment.
• Technique for all aspects of abandonment and
removal will be reviewed from time to time during
the project life.
115IPE FDP 2014 - Team A7/11/2016

PROFILES.
Plan).
o ABONDAMENT.
o COST.
116IPE FDP 2014 - Team A7/11/2016
DEVELOPMENT AND
MANGEMENT PLAN

ECONOMICS
Key Assumptions
• Oil price (2014): $103.25/bbl
• Gas price (2014): $10.95/bbl
• Discount Factor: 10% (Constant) (industry standards)
• Field considered as standalone, for taxation purposes
• Tax: 62% (corporate tax 30% + supplementary tax 32%)
• Opex and Capex: Simulated using IHS-Questor economics
software
(Woodmackenzie UK Country Report)
117IPE FDP 2014 - Team A7/11/2016

7/11/2016 IPE FDP 2014 - Team A 118
Uncertainties

Concept Scenarios
1. FPSO + Subsea
2. Production Platform + Subsea Tieback
3. Semi-submersible + Subsea Tieback
For 10 producer wells and 6 injector wells the three cases were
simulated.
Parameters to be satisfied for a project to be viable:
NPV[i] > =0
NPVI[i] > = 0
IRR > = i
IPE FDP 2014 - Team A 06/19/14 119

Development Options
IPE FDP 2014 - Team A 06/19/14 120
Parameters FPSO + Subsea via
existing pipeline
Platform + Subsea
Tieback via existing
pipeline
Semi-submersible
+ Subsea via
existing pipeline
MCO (MM$) -535 -522 -552
Payback (years) 3 3 3
NPV[0.10] 7727 7696 7709
NPVI[0.10] 14.42 14.74 13.97
IRR (%) 150 129 145
OPTIMUM CASE

Optimum Case
NPV vs. Discount Factor
IPE FDP 2014 - Team A 06/19/14 121
0
2000
4000
6000
8000
10000
12000
14000
16000
18000
20000
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1
NPV,MMUSD
Discount Factor
NPV Profile
NPV Profile

Optimum Case
Cumulative Discounted
Cash Flow
IPE FDP 2014 - Team A 06/19/14 122
-1000
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
0 5 10 15 20 25 30
CUMDCF
Year
Payback period = 3 Years
MCO = $535 MM
TCS = $7,727 MM
Used to determine the size and profitability of the project.

Optimum Case
Sensitivity Analysis
123IPE FDP 2014 - Team A7/11/2016
2500
3500
4500
5500
6500
7500
8500
9500
10500
11500
12500
0 0.2 0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 2
NPV
Proportional Change
Field Spider Diagram
Capex
opex
Tax
Oil Price
Spider Diagram is showing variation in capex, opex, tax and oil price.
Varying one parameter at a time.
Taxation has the
highest effect in
NPV value

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