msc group project presentation
TRANSCRIPT
05/02/2023 IPE FDP 2014 - Team A 1
Field Development Plan Team (A) – AQUA
Contents:
• EXECUTIVE SUMMARY • FIELD DESCRIPTION• DEVELOPMENT AND MANGEMENT PLAN• CONCLUSION
2IPE FDP 2014 - Team A05/02/2023
EXECUTIVE SUMMARY
3IPE FDP 2014 - Team A05/02/2023
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 A05/02/2023
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 A05/02/2023
FIELD DESCRIPTION
Severity of the edges
6IPE FDP 2014 - Team A05/02/2023
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 A05/02/2023
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 A05/02/2023
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 A05/02/2023
FIELD DESCRIPTION
Field Stratigraphic Correlation
10IPE FDP 2014 - Team A05/02/2023
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 A05/02/2023
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 A05/02/2023
FIELD DESCRIPTION
Stratigraphic Correlation Panel (2) for X4, X6, X1 and X3
13IPE FDP 2014 - Team A05/02/2023
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 A05/02/2023
FIELD DESCRIPTION
Core Image Analysis
15IPE FDP 2014 - Team A05/02/2023
Oil-Stained Cores
Interbedding
with
Mudstones
Sand-Filled Mud
Lined Burrows
FIELD DESCRIPTION
Palaeocurrent Direction of Interpreted Sediment Supply
16IPE FDP 2014 - Team A05/02/2023
FIELD DESCRIPTION
Interpreted Geological Sequences of Evolution of the field
17IPE FDP 2014 - Team A05/02/2023
FIELD DESCRIPTION
Indicators for Shallow Marine Environment
18IPE FDP 2014 - Team A05/02/2023
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 A05/02/2023
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 A05/02/2023
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 A05/02/2023
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 A05/02/2023
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 A05/02/2023
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 A05/02/2023
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 A05/02/2023
FIELD DESCRIPTION
Cross Plot Multi-Wells (Porosity – Formation Resistivity) for X3, X4 and X5
26IPE FDP 2014 - Team A05/02/2023
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 A05/02/2023
• 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 A05/02/2023
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 A05/02/2023
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 A05/02/2023
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 A05/02/2023
Probabilistic Reserve Estimation, using parameters from the Petrophysical Analysis, and Latin Hypercube Sampling.
STOOIP (MMSTB)P10 1,274.80P50 859.69
P90 517.70
FIELD DESCRIPTION
Sensitivity Analysis for STOIP; Tornado Chart
32IPE FDP 2014 - Team A05/02/2023
Thickness (FT.)
Porosity (%)
Water Saturation (%)
Area (Acres)
Form. Volume Factor (bbl/stb)
NTG
0.00 500.00 1,000.00 1,500.00
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
Sensitivity Analysis for Field-X STOOIP (MMSTB)
Downside Upside
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 A05/02/2023
10.00% 13.86% 17.71% 21.57% 25.42% 29.28% 33.13% 36.99% 40.84% 44.70% 48.55% 52.41% 56.27% 60.12% 63.98% 67.83% 71.69% 75.54% 79.40% 83.25% 87.11%400.00
600.00
800.00
1,000.00
1,200.00
1,400.00
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.
06/19/14 34
PVT ANALYSISPROPERTY 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 35
CAPILLARY PRESSURE
IPE FDP 2014 - Team A
01020304050607080901000
20
40
60
80
100
120
140
160
Pressure(oil water) vs pore space %
Pressure(oil water)
Pressure, Psia
porosity % 22.9 permeabil-ity MD 49 Depth (Ft) 10330.4 100101
100
10
1
0.1
0.01
Sw %
J(sw
)
S 0.336483R-Sq 80.8%R-Sq(adj) 80.7%
Log Fitted Leverett-J Function for Field-X Capillay Pressure Core Datalog10(J(sw)) = 2.525 - 1.723 log10(Sw %)
06/19/14 36
RELATIVE PERMEABILITY
IPE FDP 2014 - Team A
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 10
0.10.20.30.40.50.60.70.80.9
KR1T 0Water Saturation, Sw
Rel
ativ
e Pe
rmea
bil-
ity
Mersey and Lydell Sands
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 10
0.1
0.2
0.3
0.4
0.5
0.6
0.7
KRHTKRIT
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 10
0.10.20.30.40.50.60.70.8
KR1TKRHT
Clyde Sands
Usk Sands
06/19/14 37
RELATIVE PERMEABILITY
IPE FDP 2014 - Team A
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 10
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
KR1T
KRHT
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 10
0.1
0.2
0.3
0.4
0.5
0.6
KR1T
KRHT
Ribble sands Forth Sand & Ush Sand
Well-Test Analysis
Log-Log Diagnostic(X2) Results (Oil Zone)
38IPE FDP 2014 - Team A05/02/2023
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
Log-Log Diagnostic(X3) Results (Oil Zone)
39IPE FDP 2014 - Team A05/02/2023
Reservoir Parameter Results
Permeability (mD) 215
Skin -3.5
Wellbore Storage Coefficient
(bbl/psi)
0.0349
Well Thickness (ft) 100
Extrapolated Pressure (psia) 5246
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 A05/02/2023
Reservoir Parameter Results
Permeability (mD) 820
Skin 22
Wellbore Storage
Coefficient (bbl/psi)
0.2
Well Thickness (ft) 273
Extrapolated Pressure (psia) 4350
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
Log-Log Diagnostic(X6) Results (Oil Zone)
41IPE FDP 2014 - Team A05/02/2023
Reservoir Parameter Results
Permeability (mD) 500
Skin 43.6
Wellbore Storage Coefficient
(bbl/psi)
0.241
Well Thickness (ft) 467
Extrapolated Pressure (psia) 4837
Reservoir Interval (ft TVDSS) 10264 – 10309
Distance from fault (ft) 325 and 325 ft. (Interesting
Fault) - BU
06/19/14 42
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) - BU325 and 325 ft.
(Interesting Fault) - BU
IPE FDP 2014 - Team A
• Permeability values from all the well test shows high heterogeneity in the reservoir.• Formation damage(Skin) in the range -3.5 – 45.
06/19/14 43
Well-Test Analysis
Well Test Interpretations• Fault Signatures are identified in Wells X2, X5,
X6.
IPE FDP 2014 - Team A
06/19/14 44
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
Well-Test Analysis
06/19/14 45
Well-Test Analysis
IPE FDP 2014 - Team A
RFT Analysis for X1, X2, X3 and X5
Two OWC’s identified @ 10560 and 10840 ft. TVD SS
06/19/14 46
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 wellsThe 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
FIELD DESCRIPTIONWELL PERFORMANCE
Producer Injectors
Existing 4 2
New 10 6
Optimum Case (Case-3)
06/19/14 47
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
Worst Case Scenario
The difference between the oil rates is very low, thus, we go for the smaller tubing size
FIELD DESCRIPTIONWELL PERFORMANCE
06/19/14 48
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
FIELD DESCRIPTIONWELL PERFORMANCE
06/19/14 49
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
FIELD DESCRIPTIONWELL PERFORMANCE
06/19/14 50
Selection of the Pump• Available options:
IPE FDP 2014 - Team A
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 scenarioThe pumps that were available for these conditions are shown in the table)
FIELD DESCRIPTIONWELL PERFORMANCE
06/19/14 51
Selection of the Pump• Comparison of the performances of the pumps are shown in
the table
IPE FDP 2014 - Team A
Pump Name Layer Pressure Water Cut Oil Rate
(psia) (fraction) (bopd)
HN 21000 (HS) – Reda1900 0.9 363.8
KC 20000 – Centrilift1900 0.9 464.6
Based on the performance @ worst case scenario:“KC 20000 – Centrelift” is selected as the ESP
FIELD DESCRIPTIONWELL PERFORMANCE
06/19/14 52
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
FIELD DESCRIPTIONWELL 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
06/19/14 53
Formation DamageThe Formation Damage caused by:a) Drillingb) Cementingc) Perforationd) Production– Fine movement– Scales(organic and inorganic)– Pressure Reduction– Stimulation
IPE FDP 2014 - Team A
FIELD DESCRIPTIONWELL PERFORMANCE
06/19/14 54
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
FIELD DESCRIPTIONWELL PERFORMANCE
06/19/14 55
• Selection Criteria for Well Treatment method:
IPE FDP 2014 - Team A
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 DESCRIPTIONWELL PERFORMANCE
06/19/14 56
Selection of Well Treatment Method“Matrix v/s Hydraulic Fracturing”
IPE FDP 2014 - Team A
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 DESCRIPTIONWELL PERFORMANCE
06/19/14 57
Sand ControlTypical Allowable Sand Production Levels are mentioned in the table below:
IPE FDP 2014 - Team A
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 “ at the production rate of• 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 DESCRIPTIONWELL 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 A05/02/2023
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 A05/02/2023
06/19/14 60
MODELLING APPROACHPermeability Distribution
IPE FDP 2014 - Team A
06/19/14 61
MODELLING APPROACH
Cross section of model with pore distribution
IPE FDP 2014 - Team A
06/19/14 62
MODELLING APPROACHPorosity distribution
IPE FDP 2014 - Team A
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 A05/02/2023
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 A05/02/2023
06/19/14 65
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
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 A05/02/2023
DEVELOPMENT AND MANGEMENT PLAN
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.
67IPE FDP 2014 - Team A05/02/2023
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 A05/02/2023
DEVELOPMENT AND MANGEMENT PLAN
06/19/14 69
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 70
CASE 1
IPE FDP 2014 - Team A
• 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%.
06/19/14 71
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 72
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
OPTIMUM DEVELOPMENT PLAN CASE
06/19/14 73
SIMULATION RESULTS
IPE FDP 2014 - Team A
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 146 499 0.89 5
(9 P + 5 I)CASE 2
47.1 509 0.88 4.8(10 P + 5 I)
CASE 347.8 510 0.88 3
(14 P + 8 I)
* P - Producer Wells; I – Injector Wells
FOE vs TIME
06/19/14 74
SIMULATION RESULTSFOPR (Field Oil Production Rate)
IPE FDP 2014 - Team A
06/19/14 75
SIMULATION RESULTS• FOIP (Field Oil In Place)
IPE FDP 2014 - Team A
06/19/14 76
SIMULATION RESULTSFWCT (Field Water Cut)
IPE FDP 2014 - Team A
06/19/14 77
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
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.
78IPE FDP 2014 - Team A05/02/2023
DEVELOPMENT AND MANGEMENT PLAN
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.
79IPE FDP 2014 - Team A05/02/2023
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 A05/02/2023
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.
81
Main Offset Well X-3
IPE FDP 2014 - Team A05/02/2023
06/19/14 82
Well Design Summary
IPE FDP 2014 - Team A
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.
83
Subsea Template
IPE FDP 2014 - Team A05/02/2023
Directional Well Program for the longest well (J-Type)
84
• Nudge Plan @ 26” Hole.• KOP @ 1482 ft.• BUR = 1.5 deg / 30 ft.• J-Well Profile .• Max Inclination= 51.88.• Well TD @ 15556 ft MD/
11039 ft TVD.
Nudge plans will be provided once the subsea template final coordinates and orientation will be given.
DLS is low as possible as the KOP @ 17 ½” Hole Size (large Hole Size) to reduce T&D along the well.
IPE FDP 2014 - Team A05/02/2023
Geological Prognosis
85
The geological prognosis used is a typical North Sea geology up to the depth of the top of the reservoir.
The used pore pressure is the normal pore pressure up to the top of the reservoir.
The used reservoir pressure from the RFT data.
IPE FDP 2014 - Team A05/02/2023
Pore Pressure, Fracture
Pressure and Overburden
86
0 2000 4000 6000 8000 10000 120000
1000
2000
3000
4000
5000
6000
7000
8000
9000
10000
11000
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)
Pressure, psi
TVD
ft, R
KB
Fracture Pressures estimated from EATON method with Different Poisson Ratio and as constant as 0.85 psi/ft.
LOT / FIT is planned for drilling wells to update the fracture gradient and casing design.
IPE FDP 2014 - Team A05/02/2023
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 A05/02/2023
Casing summary Table
88
Hole Size
In
CasingODIn
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 A05/02/2023
Rig Selection Criteria
89
Criteria Selected Design Criteria Source of Design Criteria
Water Depth 150 m Given for Group A
Mud Pumps 1600 HPThree Mud Pumps (2 + 1 Back Up’s)
HP = Q x P / 1714
For 8 ½”, 1600 HP
Hoisting SystemDerrick, 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 A05/02/2023
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 A05/02/2023
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 A05/02/2023
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 A05/02/2023
Bit Design
93
Hole Size FormationDepth In, ft. MD
Depth out, ft.
MDBit 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” HoleSiltstone,
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 A05/02/2023
Casing Design Table
94
Hole Size
In
Section Depth
Ft, MD
Setting Depth
Ft, TVD-RKB
Setting Depth
Ft, TVD-SS
CasingODIn
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 9.62547 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 A05/02/2023
Example for Casing Design9 5/8” Production Casing Design
95
Assumptions:
5800 psi4750 psi
Pi @ Top of Liner= 10990 psi
0 psi6240 psi
Depth Pi Pe Pb Pb x D.F.Surface 0.00 4750.00 0.00 4750.00 5225.00Top of Liner 9600.00 10990.00 6240.00 4750.00 5225.00
Pc = Pe-PiAssumptions:
0 psi0 psi
0 psi6240 psi
Depth Pi Pe Pc Pc x D.F.Surface 0 0 0 0 0Top 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
TVD
ft,
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
TVD
ft,
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
TVD
ft,
RKB
Pressure, psi
Pe Pi Pc Pc x 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
TVD
ft, R
KB
Pressure, psi
53.5, L-80/N-80 Pc 47, L-80/N-80
IPE FDP 2014 - Team A05/02/2023
Cementing Program
96
Casing Design Considerations Technique TOC
30
Design for theHydrostatic 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 theHydrostatic 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
13.375
Design for theHydrostatic Pressure < Fracture Pressure
Single Stage Cement
TOC @ 200 ft. above the previous casing
9.625
Design for theHydrostatic Pressure < Fracture Pressure (During 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 theHydrostatic Pressure < Fracture Pressure (During the
CMT Job)
Design for the reservoir pressure and Temperature
Liner CementationLinear 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 A05/02/2023
Mud Program
97
Hole Size Formation Mud Type Mud Weight (*), ppg Technical Functions of the fluids Issues (Cost, Environments)
36” SandstoneWBM
(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
Environmentally friendly.
17 ½” HoleSiltstone (Shale),
Sandstone, Anhydrite
WBM – SUPER SHALE TROL / KCL
Polymer10.19 – 11.92 Help to reduce the shale swelling. Environmentally friendly.
12 ¼” Hole Chalk and Siltstone (Shale)
WBM –SUPER SHALE TROL / KCL
Polymer12.31 – 12.50 Help to reduce the shale swelling. Environmentally friendly.
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.
Environmentally friendly.
IPE FDP 2014 - Team A05/02/2023
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 A05/02/2023
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 A05/02/2023
Well completion design
100IPE FDP 2014 - Team A05/02/2023
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 A05/02/2023
Surface Processing Topsides Facilities• 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 Topsides Facilities• Produced water disposal
104IPE FDP 2014 - Team A05/02/2023
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 A05/02/2023
IPE FDP 2014 - Team A 10605/02/2023
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 A05/02/2023
SUBSEA PRODUCTION AND ASSOCIATED FACILITIE
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 A05/02/2023
SUBSEA PRODUCTION AND ASSOCIATED FACILITIE
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
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.
111IPE FDP 2014 - Team A05/02/2023
DEVELOPMENT AND MANGEMENT PLAN
06/19/14 112
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
Reservoir Management Process
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.
113IPE FDP 2014 - Team A05/02/2023
DEVELOPMENT AND MANGEMENT PLAN
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.
114IPE FDP 2014 - Team A05/02/2023
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 A05/02/2023
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.
116IPE FDP 2014 - Team A05/02/2023
DEVELOPMENT AND MANGEMENT PLAN
ECONOMICS
Key Assumptions
• Oil price (2014): $103.25/bbl• Gas price (2014): $10.95/bbl• Discount Factor: 10% (Constant) (industry standards)• Field considered as standalone, for taxation purposes• Tax: 62% (corporate tax 30% + supplementary tax 32%)• Opex and Capex: Simulated using IHS-Questor economics
software
(Woodmackenzie UK Country Report)
117IPE FDP 2014 - Team A05/02/2023
05/02/2023 IPE FDP 2014 - Team A 118
Uncertainties
06/19/14 119
Concept Scenarios1. FPSO + Subsea2. Production Platform + Subsea Tieback3. Semi-submersible + Subsea Tieback
For 10 producer wells and 6 injector wells the three cases were simulated.Parameters to be satisfied for a project to be viable:
NPV[i] > =0 NPVI[i] > = 0
IRR > = i
IPE FDP 2014 - Team A
06/19/14 120
Development Options
IPE FDP 2014 - Team A
Parameters FPSO + Subsea via existing pipeline
Platform + Subsea Tieback via existing
pipeline
Semi-submersible + Subsea via
existing pipelineMCO (MM$) -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
06/19/14 121
Optimum Case NPV vs. Discount Factor
IPE FDP 2014 - Team A
0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 10
2000
4000
6000
8000
10000
12000
14000
16000
18000
20000
NPV Profile
NPV Profile
Discount Factor
NPV
, MM
USD
06/19/14 122
Optimum Case Cumulative Discounted
Cash Flow
IPE FDP 2014 - Team A
0 5 10 15 20 25 30-1000
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
Year
CUM
DCF
Payback period = 3 Years MCO = $535 MMTCS = $7,727 MM
Used to determine the size and profitability of the project.
Optimum Case Sensitivity Analysis
123IPE FDP 2014 - Team A05/02/2023
0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 22500
3500
4500
5500
6500
7500
8500
9500
10500
11500
12500Field Spider Diagram
CapexopexTaxOil Price
Proportional Change
NPV
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