TeamD_final_report

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Contents
List of Abbreviations............................................................................................................................... 4
Table of Figures....................................................................................................................................... 5
Executive Summary ................................................................................................................................ 1
1 Technical Summary......................................................................................................................... 3
1.1 Geology ................................................................................................................................... 3
1.2 Formation Evaluation ............................................................................................................. 4
1.3 Reservoir Engineering and Simulation................................................................................... 5
1.4 Drilling..................................................................................................................................... 6
1.5 Production Technology........................................................................................................... 7
1.6 Economics ............................................................................................................................... 8
1.7 Decommissioning.................................................................................................................... 8
1.8 Health and Safety, Sustainability and Corporate Social Responsibility.............................. 10
2 Field Description .................................................................................................................................. 1
2.1 Structural Configuration............................................................................................................... 1
2.2 Geology and Reservoir Description.............................................................................................. 5
2.2.1 Core Analysis.......................................................................................................................... 5
2.2.2 Depositional Environment..................................................................................................... 6
2.2.3 Lithology and Lithostratigraphy............................................................................................ 6
2.2.4 Structural History Model....................................................................................................... 8
2.2.5 Geological Statistics.............................................................................................................. 9
2.2.6 Uncertainties.......................................................................................................................... 9
2.3 STOIIP Estimation ....................................................................................................................... 10
2.3.1 Deterministic........................................................................................................................ 10
2.3.2 Probabilistic ......................................................................................................................... 11
2.3.3 Stochastic............................................................................................................................. 11
2.3.4 Uncertainties........................................................................................................................ 11
3 Petrophysics....................................................................................................................................... 12
3.1 Introduction ................................................................................................................................ 12
3.2 Lithology Determination ............................................................................................................ 13
3.3 Permeability Determination....................................................................................................... 14
3.4 Core Data Analysis...................................................................................................................... 15
3.5 Porosity Determination.............................................................................................................. 16
3.6 Volume of Shale Determination................................................................................................. 17
3.7 Saturation of water Determination ........................................................................................... 17
3.8 OWC Determination ................................................................................................................... 17
3.9 Subsidence .................................................................................................................................. 19
3.10 Uncertainties............................................................................................................................. 20

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4 Reservoir Engineering........................................................................................................................ 21
4.1 PVT Analysis................................................................................................................................ 21
4.2 SCAL............................................................................................................................................. 22
4.3 Well Test ..................................................................................................................................... 24
4.4 Reservoir Simulation .................................................................................................................. 34
4.4.1 OWC Determination ............................................................................................................ 34
4.4.2 Relative Permeability and Capillary Pressure..................................................................... 34
4.4.3 Input data............................................................................................................................. 36
4.4.4 Grid Analysis and Model Design ......................................................................................... 36
4.4.5 Facies.................................................................................................................................... 37
4.4.6 Petrophysical Properties ..................................................................................................... 38
4.4.7 Reservoir Simulation Results............................................................................................... 40
5 Drilling Facilities................................................................................................................................. 44
5.1 Geology and Pressure prognosis................................................................................................ 44
5.2 Drilling Fluid selection ................................................................................................................ 46
5.3 Directional plan........................................................................................................................... 46
5.4 Drilling Schedule......................................................................................................................... 47
5.5 Casing and Cementing program ................................................................................................. 47
5.6 Bits and BHA ............................................................................................................................... 48
5.7 Cementing Procedure................................................................................................................. 48
5.8 Risk Assessment.......................................................................................................................... 50
5.9 New technology (Geo-steering) ................................................................................................. 52
6 Production Technology...................................................................................................................... 53
6.1 Well Production/Injection Constraints ...................................................................................... 53
6.2 Surface Facilities ......................................................................................................................... 54
6.3 Principal Well Design (inflow level) ........................................................................................... 57
6.4 Principal Well Design (outflow level)......................................................................................... 58
6.4 Detailed Well Design .................................................................................................................. 62
6.6 Reservoir Management & Monitoring....................................................................................... 63
7 Economics and Commercial Consideration....................................................................................... 65
7.1 Summary (Case A)................................................................................................................... 65
7.2 Target Market ............................................................................................................................. 66
7.3 Cash flow model (Case A)........................................................................................................... 66
7.4 Sinking Fund................................................................................................................................ 67
8.5 Screening Criteria with Sensitivities........................................................................................... 67
7.6 Taxation PRT abolishment.......................................................................................................... 68
7.7 Sensitivities................................................................................................................................. 69
8.8 Risk reduction ............................................................................................................................. 70
9 Bibliography:...................................................................................................................................... 71

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List of Abbreviations
Barrel BBL
Bore-Hole Assembly BHA
Blowout Preventer BOP
Capital Expenditure CAPEX
Drill Collar DC
Derivative Plateau DP
Drill Stem Test DST
Electrical Submersible Pump ESP
Early Time Region ETR
Feet ft
Field Oil Efficiency FOE
Field Oil in Place FOIP
First Known Oil FKO
Floating Production Storage and Offloading FPSO
Field Watercut FWCT
Gas Oil Ratio GOR
Gamma Ray GR
Gross Rock Volume GRV
Internal Rate of Return IRR
Initial Pressure Pi
Lost Circulation Mud LCM
Last Known Oil LKO
Late Time Region LTR
Logging While Drilling LWD
Measured Depth MD
Middle Time Region MTR
Net Present Value NPV
Operating Expenditure OPEX
Oil Water Contact OWC
Polycrystalline Diamond Compact PDC
Positive Displacement Motor PDM
Petroleum Revenue Tax PRT
Pressure Volume Temperature PVT
Productivity Index PI
Repeat Formation Tester RFT
Special Core Analysis SCAL
Stock Tank Oil in Place STOIIP
True Vertical Depth Subsea TVD SS
Water Alternating Gas WAG

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Water-Based Mud WBM
Symbols:
Carbon Dioxide CO2
Intersection Time tx
Effective Permeability k
Net to Gross 𝑁
𝐺⁄
Oil Saturation 𝑆 𝑜
Permeability x height kh
Porosity Ø
Skin S
Hydrogen Sulphide H2S
Total Compressibility ct
Time elapsed t
Viscosity µ
Water Saturation 𝑆 𝑤
Table of Figures
Number Name Main Body Page Number
1 Top Structure with Faults 2
2 North-South Cross-Section with Well Placement 2
3 Isochore 4
4 Cross section (A’-A) 4
5 Cross section (B-B’) 4
6 X5 Core Analysis 5
7 Possible Caprocks 6
8 Correlation Panel for Wells X4, X6, X2, X1 7
9 Structural History 8
10 Regions of uncertainty (grey area) 9
11 Model STOIIP histogram 11
12 Tornado Plot 12
13 Gamma Ray Logs for X1 and X2 13
14 M-N Plot for Wells X3 and X4 14
15 Semivariograms for well X1, X4 and X5 16
16 Possible Dynamic Aquifer 18
17 Possible Compartmentalisation 19
18 Possible Completely Sealed Compartment 19
19 Reservoir Fluid Composition 21

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20 Comparison of Oil formation volume factor and
Solution gas oil ratio against pressure 22
21 Oil Viscosity vs Pressure 22
22 X5 Porosity vs Permeability 23
23 X1 Porosity vs Density 23
24 Permeability Estimation 24
25 X2 Buildup Log-Log Plot 26
31 OWC Generated from Logs in Petrel 34
32 Sand 1 kr vs Sw 35
36 Existing Exploration Wells 37
37 Flow units assigned from Logs 37
38 Permeability (Sequential Gaussian Distribution) 39
39 Porosity (Sequential Gaussian Distribution) 39
40 Water Saturation (Sequential Gaussian
Distribution) 40
41 Base Case Water Cut profile 41
42 Base Case Oil Production Rate 42
43 Model 4 Oil Production Rate 42
44 Model 4 Field Oil Depletion 43
45 Model 4 Water Cut Profile 43
46 Stratigraphic Column for Brent vs. Seismic Pore
Pressure Prediction 45
47 Horizontal Well Profile 46
48 Casing Setting Depth with respect to Pressure 50
49 Sand Production Triangle 52
50 Production Network Schematic 55
51 Vertical well profile 61
52 Horizontal Well Profile 61
53 Horizontal Well Trajectory 62
54 Production Profile (Case A) 67
55 NPV as Screening Criteria 68
56 Spider Diagram 69

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Executive Summary
This Field Development Program describes the development program for the oil extraction
from X-Field located in the Southern North Sea at geographical coordinates (54’53” 300N;
2’06” 560E), 220km offshore at a water depth of 98.4ft (30m).The license for the above
process was bought by the Dathomir Company.
Administratively, Field X is located in the UK North Sea, Quadrant 44/1, a previously
unlicensed area, 360km SE of Aberdeen, 220km E of the Teesside Terminals, with no nearby
pipeline infrastructure for the transport of oil. In tectonic terms, it is located in the southern
North Sea basin.
Six Exploration Wells were drilled, all discovering high quality 40° API oil from the PVT
Analysis. Estimated Reserves are ranging from around 800 MMSTB to 1100 MMSTB. The
reservoir is believed to be homogeneous, with layer cake architecture judging from the SCAL
data. There is an average reservoir pressure of 5700psi and a bubble point pressure of 1800psi.
A possible shale body, underlying the sandbody could be acting as the source rock, with shale
and calcite acting as possible cap rocks. The oil bearing sands are believed to be from the
Jurassic Period. The depositional environment seems to be shallow marine.
The OWC’s were found to be at 10830 an d10560 in different sectors of the reservoir creating
an uncertainty about the continuity and homogeneity of the sand body. According to
evaluation of the log data, well X4 encountered the highest reservoir thickness and well X6
encountered the lowest reservoir thickness.
The project is expected to be started from the beginning of January 2017. The simulation
model was based upon the integration of various sources of data gathered from the exploration
wells. Expected flow units, such as permeability and porosity were gathered from well testing
analysis, core data, SCAL and log data.

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A system was devised to realistically represent the distribution of properties throughout the
reservoir, by using a typical distribution method that occurs in similar depositional
environments. This was required due to the limited range of data that was provided in
geographical and analytical terms.
The optimum development strategy contains the placement of 11 producers, 8 water injectors
and 1 gas injector, providing a recovery factor 61.3% over a period of 20 years of production,
once the main facilities are set up. Artificial lift methods were analyzed due to the expected
reduction in reservoir pressure and increased water cut over the years, due to production.
Considering the location of the reservoir and the associated power requirements, installation
of ESP’s is the recommended method for artificial lift as compared to Gas Lift. The optimum
method of transportation of the reservoir fluid was found to be by pipeline, considering the
quantity of the produced fluid and distance from the shore.
Considering the economic situation of the oil and gas industry a moderate price of 50$/bbl
was chosen for the produced oil. Still, the project turned out to be a highly profitable one, with
the best case yielding an undiscounted NPV of $7.727bn, IRR 47% and PIR 7.5. The best case
involved implementation of the optimum development strategy acquired from reservoir
simulation and also the application of most effective components for production of the
reservoir fluid.
Finally, the Environmental Impact Assessment accounted for the factors that will potentially
contribute to the carbon footprint in the wake of the operation and consequent abandonment
of the project. Most importantly, the mitigation measures to be put in place are also discussed

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1 Technical Summary
1.1 Geology
 Field X is an approximately 18 km2
oil field located in the UK sector of the North Sea.
 It is a triangular, partly eroded dome shaped anticline with steeply dipping flanks,
located at a depth of 9900 – 11500 ft.
 Six Exploration Wells have been drilled, all encountering oil.
 The main oil bearing sands were identified as Jurassic. Statistical analysis of available
parameters and SCAL suggested a homogenous reservoir with layer cake architecture.
 Well testing shows no evidence of completely sealing faults; they are assumed to have
no effect on transmissibility. The northern sector of the reservoir is believed to be
strongly faulted.
 The main sand is subdivided into 5 subunits, based on available data and SCAL.
 At least two different types of cap rock lithology have been identified: calcite and
shale
 The extent and thickness of the main sands is not fully understood due to limited
seismic data and a limited number of exploration wells, further drilling will delineate
reservoir parameters such as area, presence of faults, sand connectivity and thicknesses

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1.2 Formation Evaluation
Data acquired from logging, well testing, PVT and core analysis was evaluated. The main
objective of core and logging data analysis was to determine different petro physical properties
of the reservoir; namely porosity, permeability, oil and water saturation, rock type and others.
The list of available logs used to carry out the analysis is shown in the table below.
X1 X2 X3 X4 X5 X6
Gamma Ray • • • • • •
Acoustic Log • • • • • •
Formation
resistivity Log • • • • • •
Neutron Log • • • • • •
Density Log • • • • • •
Air Permeability • - - • • -
Lateral Log • • • • • •
Referred Log Data
The gamma ray logs for well X1 and X2 were inconclusive, since the drilling report gives
evidence of heavy radioactive barite containing mud being used, with density ranging from
0.62-0.65psi/ft. This complicated the differentiation between impermeable shale and permeable
sand strata. Analysis of gamma ray and resistivity logs for wells X3, X4, X5 and X6 show
convincing evidence of chalk being the main cap rock, whereas X2 and X1 show shale as the
cap rock. Neutron and density cross plots were used to determine the different lithologies
present. The reservoir consists of chalk (forming the cap), sandstone (main HC body) and inter-
bedded shale and evidence of anhydrite. Statistical analysis (Semi-variogram and Lorenz plot)
on core permeability and porosities showed evidence of repetitive geological elements,
suggesting presence of bedding structures. The grain density (2.66g/cc) obtained from core
samples correlated with log analysis, confirming the presence of sandstone being the main HC
carrying lithology.

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OWC were found to be at 10830 ft for wells in the southwestern sector, and 10560 ft for wells
X5 and X6 in the northeaster sector of the reservoir.
1.3 Reservoir Engineering and Simulation
PVT Analysis:
PVT analysis was carried out in order to improve understanding of the reservoir fluid. During
the DST fluid samples were recovered and analysed. There was little variation between
observed properties of the fluids obtained from the availiable wells. Bubble point pressure
was estimated to be around 1800 psia and the reservoir pressure was 5700 psia, suggesting an
undersaturated reservoir fluid. Oil gravity was found to be 40.9 API° - very light. Other
calculated properties included Bo, chemical composition, density, viscosity, GOR, rock and
fluid compressibilies and formation fluid analysis. Relative permeability curves, capillary
pressure curves for different reservoir units were constructed using provided data.
SCAL:
A significant correlation between porosity and permeability was found from SCAL. The best
log to estimate porosity, and consequently permeability was found to be the density log.
A Permeability vs Porosity crossplot for X2 was provided, but core data was missing.
Therefore, no correlation between dens and porosity, and consequently permeability could be
established. Sample size for X4 was found to be insufficient; this was mathematically proven
for an 80% confidence interval.
Well Testing:
Well Test analysis was carried out using Pansystem to identify reservoir parameters and
features such as as faults. Well test data for X2, X3, X5 and X6 was availiable. From
Cartesian Plots, the final buildup stage was considered for the majority of wells, due to
unstable and highly uncertain preceding drawdown and buildup stages. Reservoir parameters
were acquired from the Semilog/Horner plot. The log-log plot was used to examine any

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presence of wellbore storage in the ETR, and the presence of boundaries from the LTR.
Possible boundary models were matched to the data on the log-log plot, which led to multiple
interpretations being discussed.
Reservoir Simulation
Honoring the available geological data and conclusions from various analysis such as well
testing and formation evaluation, a reservoir model was constructed using PETREL. This
allowed further STOIIP estimation with sand body thicknesses and permeability inconsistencies
taken into account, and optimal depletion strategies were evaluated.
Facies logs were constructed based on the estimated porosity and permeability. Sequential
Indicator Simulation was chose to model facies distribution, as deterministic methods such as
moving average and closest used unrealistic assumptions. Sequential Gaussian was used for
flow units, namely, permeability and porosity. The calculated STOOIP from the model was
854Mbbls with a recovery factor of 61% using 11 producers, 8 water injectors and 1 gas
injector, re-injecting all produced gas.
1.4 Drilling
The current optimal depletion plan obtained from reservoir simulation requires a total of 20
wells of S type configurations. Wells will be positioned in clusters. The majority producers will
be drilled in the first year and will commence depletion without initial pressure maintenance,
until injectors have been drilled. To assure maximum recovery, simulation requires water
injectors to be completed vertically into the water leg, and producers to be completed both
horizontally and deviated in crest region of the reservoir.
Casing depths and sizes were chosen according to the expected pore pressures. Burst and
collapse loads were calculated with safety factors of 1.1 and 1.0 respectively. The formation
above the pay zone is assumed to consist mainly of sandstone, shale and shaley limestone with
chalk or shale forming the cap rock. Setting production casing will require a 2-Stage cementing

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program. A cement density of 16.4 lbs/gal is recommended. Drilling bits and BHA were
selected based on the trajectory of the wells, as well as type and hardness of formations
encountered. The PDC bit in combination with the PDM and On-gauge Torque Reduction
reamer are used in the bottom hole to reduce drill time and maintain bore hole integrity.
Lithology distribution and pore pressure behavior were assumed to be similar to that of the
Brent field, which is believed to be near the actual location of field X. Sandstone formations
are assumed to be normally pressured, while shaley regions are assumed to be highly over-
pressured. Overbalanced drilling technique should be used to ensure safety when encountering
unexpected overpressured formations. Pressure overbalance should be kept constant at 250 psi,
not exceeding fracture pressure gradients and avoiding loss of circulation. To maintain well
control at all times, BOPs must always be in place. To minimise environmental impacts WBM
is used.
1.5 Production Technology
Production aspects of the well were analysed, including the completion type, inflow and
outflow components, as well as possible constraints on production and injection wells;
minimum producer bhp and maximum injector pressure are based on assumed fracture
pressures, sand production was estimated using a sand production triangle for a similar
formation. An initial reservoir model containing 20 producers and 19 water injectors, was
reduced to 11 producers, 8 water injectors and 1 gas producer. This results in the same FOE
over 20 years, and a steadier decline in fluid production rates.
The optimal artificial lift method was found to be an ESP, rather than Gas Lift. Perforation
characteristics were analysed for optimum performance. Aspects hindering flow of reservoir
fluids were discussed, such as forming of scales and plugging of formation due to a drilling
procedure or perforating operation.

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Facilities platform, pipeline, separators, risers, compressors, multiphase flow meters and
production network were also discussed.
1.6 Economics
A comprehensive economic analysis based on available information suggests project to be
profitable. The payback period is expected to be 5 years. Producing life is assumed to last 20
years. An undiscounted IRR of 47% was estimated. Revenue is estimated on an assumed
average oil price of 50$/bbl, fluctuations were accounted by applying appropriate discount
factors.
Different production scenarios were screened and ranked, including various methods of oil
export to shore. The main sensitivities affecting project finances were identified to be the oil
price, inflation and taxation. The fields proximity to potential markets is assessed.
Geopolitical factors were investigated and found not to influence project parameters
significantly.
1.7 Decommissioning
At the end of field X’s productive life, the structural facilities will be decommissioned and
abandoned. This will help return the location to a secure position with minimal environmental
impact, while allowing fishing and shipping activities to continue. The decommissioning of the
project will be carried out in three phases, making sure all environmental regulations relating
to each phase are followed. A summary of the three phases is given below:-
1. Steel jacket /platform
Partial removal and reefing jacket in place will be the adopted strategy. It is not only
economically cheaper, since less movement and involvement of Heavy Lift Vessel
(HLV) is involved compared to complete removal and remote reefing, which are more

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costly. Explosives are not used in the cutting process, reducing marine disturbance.
Absence of Heavy Lift Vessels reduces pollution significantly.
2. Pipeline Decommissioning
Small diameter pipelines, which can be easily removed without significantly
disturbing the seabed are recovered. Since the pipeline used for oil transport exceeds a
20 inches diameter, the decommissioning method used is leave in- situ intervention i.e.
trenching and burying of pipeline.
OSPAR have not made any recommendation for pipelines, and therefore there is no
obligation to remove them. The main considerations are pipeline cleanliness, stability,
extent of burial and impact on other users of the sea.
3. Well Decommissioning
Plugging is the current method of abandoning wells permanently. This will be done in
accordance to regulations.
North Sea decommissioning involves plugging off wells with cement and is strictly
regulated. Operators are responsible for any failure in well integrity, during and after
abandonment.
Depending on the age and availability of production and maintenance records, an
accurate determination of well conditions can be difficult. This creates risk in selecting
the appropriate abandonment procedure.

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1.8 Health and Safety, Sustainability and Corporate Social
Responsibility
Dathomir has a committed department that establishes high standards in terms of health, safety
and environment. This department ensures that offshore activities are done with least impact on
the environment and the concerned governments‘ rules and regulations are followe. The HS&E
department monitors the training of all operators and personnel, furthermore, compliance by
all personnel is essential; to work within their designated areas and with utmost safety. Some
of the key features of the HS&E department are as follows:
 Zero rate of fatality.
 Compliance of legislature for all operations.
 Low impact on the environmental.
 Ensure quality is not compromised.

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2 Field Description
Field X is an approximately 18 km2
oil field located in the UK sector of the North Sea. It is a
triangular shaped, partly eroded and thoroughly faulted dome shaped anticline with steeply
dipping flanks, located at a depth of 9900 – 11500 ft. Evidence from core samples indicate a
shallow marine depositional environment. The reservoir is mainly composed of sandstones
with some clay strata protruding at irregular patterns. Sediments appear to be bioturbated and
show remains of animal burrows. The reservoir is a Jurassic sand body, overlain by at least
two different sealing deposits. The presence of two or more sealing mechanisms, indicated by
an unconformity, suggests a history of erosion. The existence of multiple faults, of which
some might act as flow barriers, could cause sections of the reservoir to act as separate unit,
further investigation is necessary to solidify this claim.
2.1 Structural Configuration
The available top structure map indicates a triangular dome configuration with three steeply
dipping flanks. It shows an isosceles triangular shape with legs and base approximately 4.5km
and 3.8km long, and vertex angle around 60°. The axis of symmetry is aligned in NNW-SSE,
with the apex facing SSE. The Western flank dips steeper than the Northern and Eastern
flanks. Separate peaks indicate the presence of secondary anticlines.

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Figure 1 Top Structure with Faults
Figure 2 North-South Cross-Section with projected well trajectories
Well test data, although not conclusive, suggested the presence of several faults and possible
fractures throughout the structure. Large, continuous faults, are assumed along the western
and northern flanks. Several smaller faults and fault blocks are believed to exist in the

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northern part of the reservoir, possibly isolating sections of the structure by preventing
pressure communication between flow units. The shape of the structure map indicates regions
of stress arising from faulting and uplift, and assists in identifying fracture zones, i.e.
Northern segment of structure.
Table 1 Reservoir Sand Thickness
Reservoir sand true vertical thickness for all six exploration wells was obtained from logs. A
thickness map was drawn, taking into consideration the identified depositional environment,
(see Section 2.2.2), the assumed structural history model and honoring the well data. Logging
data for well X3 ends before the bottom of the reservoir sand is reached, true thickness is
assumed to be between 700 and 900 feet.
Only wells X1 and X2 are vertical, all others are deviated. As a result, no accurate TVT
reading could be obtained from wells X3, X4, X5 and X6. Distance drilled in TVD will
always be greater than TVT if the well is deviated. Therefore, all those thicknesses are
overestimated.
The number of reservoir subunits were
given in available production and
reservoir engineering data, see Section
2.6. Sandbody thicknesses seen in the
figures below are obtained from
stochastic permeability estimates,
X1 X2 X3 X4 X5 X6
Top of Reservoir Sand 10280 10650 10265 10250 10050 10105
Bottom of Reservoir Sand 11090 11550 10950++ 11350 10700 10540
Thickness 810 900 685 1100 650 435
Reservoir Thickness
Associated Uncertainties arising
with estimating sandbody thickness

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derived from grain density measurements. Missing sections of sand units are elaborated in
2.2.3 & 2.2.4.
Figure 3 Isochore
Figure 4 Cross section (A’-A) Figure 5 Cross section (B-B’)
ft
km
km
km

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2.2 Geology and Reservoir Description
2.2.1 Core Analysis
Figure 6 X5 Core Analysis

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2.2.2 Depositional Environment
Study of core photographs indicates a low energy shallow marine depositional environment.
Shallow angles of stratification suggest a shore face or shelf setting. Signs of bioturbation and
animal burrows further support that assumption. The lack of biostratigraphic data presents an
uncertainty in accurately determining whether it is a shore face or shelf setting.
2.2.3 Lithology and Lithostratigraphy
Logging data was used to identify reservoir lithology and stratigraphic transition. M-N plots
were constructed to identify difficult lithology. Given data identifies the main sand body as
Jurassic, logging data indicates a clean sandstone with variations in salt and sulfur content.
The reservoir was found to be covered by two different sealing deposits; calcite and shale.
SCAL which is discussed in section 4.2, identifies sand units based on permeability
distributions and other given data. In the diagram below, it can be seen that the Northeastern
sector of the reservoir appears is overlain by a cretaceous chalk deposit, whereas the
Southwestern sector is covered by a shale formation, possibly containing some dolomite.
Figure 7 Possible Caprocks

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Figure 8 Correlation Panel for Wells X4, X6, X2,
X1
The correlation panel shows the different sealing mechanisms overlying the sand body. An Anhydrite layer, between 100 - 200 feet in thickness, protrudes the
reservoir sand in X1 and X2. It pinches out between X1 and X6, creating an unconformity. Both X4 and X6 are overlain by a calcite, X1 and X2 by shale. The
unconformity in X4 and X6 resulting in the missing anhydrite stratum with the following sand-shale sequence, combined with the reduced sand body thickness in
X6, suggests that an erosive event has taken place before the calcite was deposited. It is therefore assumed that the anhydrite-sand-shale sequence was eroded off
the entire northeastern sector of the reservoir, leaving only the southwest covered by shale. Consequently, the top sand layers depicted above have also been eroded
partially, and are therefore not continuously present throughout the reservoir, such as Sand 1. The underlying shale layer could be the main source rock.

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2.2.4 Structural History Model
A. Uplift, possibly driven by
halokinesis [1]
,
alternatively metamorphic
rocks rising and warping
pre-jurassic
B. Early Jurassic sediment
forming later reservoir
deposited ontop of shale
acting as possible source
rock
C. Continuous uplift,
resulting in dome shaped
Jurassic sandbody
D. Late Jurassic shale
deposited on top of early
Jurassic sand
E. Erosive event, creating
unconformity with Jurassic
shale missing completely
in certain parts
F. Cretaceous calcite
deposited
G. Post cretaceous sediment
deposited, close to
present day configuration
Figure 9 Structural History
Model

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2.2.5 Geological Statistics
Lorenz coefficients and variograms show a relatively homogenous reservoir structure. From
variogram analysis, a layercake architecture can be deducted. This assumption is supported
by SCAL findings, see Section 4.2.
2.2.6 Uncertainties
Figure 10 Regions of uncertainty (grey area)
The uncertainties associated with the reservoir during exploration and appraisal are
significant. Every additional well drilled aids in delineating reservoir characteristics and
features. Some of key the uncertainties are:
 Reservoir area
 Reservoir structure
 Sand connectivities
 Faults
The largest uncertainty at this stage is the thickness of the reservoir’s flow units. Neither
stratigraphic, nor true vertical thickness data for any of the strata is available. Estimating

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TVT or stratigraphic thickness requires an estimate on the angle of the strata itself, which
further increases uncertainty.
A full seismic investigation of the field is recommended. This creates the basis for future 4D
seismic analysis, advanced reservoir modelling and sophisticated history matching, resulting
in optimized oil recovery and efficient field management.
2.3 STOIIP Estimation
In order to reduce any uncertainty due to the available data, three different techniques were
used to carry out STOIIP calculation:
2.3.1 Deterministic
The first STOIIP calculation was done using the available top structure map and a single
OWC of 10900. The actual OWC varied from 105650 to 10860 ft TVDSS in observation
wells. Therefore, map-based calculation resulted in an overestimation of STOIIP. Simplified
material balance was used for STOIIP estimation, assuming no water influx. Production
intervals are too short, the data is considered unsuitable for STOIIP estimation.
An average OWC at 10830ft TVDSS was considered and a GRV from the top structure map is
estimated at 3.015x1010
ft3
. Most likely estimates of values for the above parameters were taken
from the available geological, petrophysical and PVT data as shown in the table below:
MIN Most Likely MAX
N/G 0.65 0.7 0.75
𝜙 0.2 0.22 0.24
𝑆 𝑤 0.65 0.7 0.72
𝐵𝑜 1.39 1.4 1.42
Table 2 NTG, Porosity, Water Saturation and Oil Formation Volume Factor values
𝑆𝑇𝑂𝑂𝐼𝑃 =
(3.016𝑥1010
) 𝑥 0.7 𝑥 0.22 (1 − 0.7)
1.4
= 995.28𝑥106
𝑠𝑡𝑏

11
2.3.2 Probabilistic
Probabilistic estimation was done using the Monte Carlo method in Crystal Ball software.
Triangular distribution was considered appropriate. The most likely values for probabilistic
calculation were taken from Table 1. 10,000 trials per simulation were carried and results
obtained are shown in Table 3:
P10 P50 P90
STOIIP 924.972 MMstb 1081.36 MMstb 1240.22 MMstb
Table 3 STOOIP (Probabilistic)
Figure 11 Model STOIIP histogram
2.3.3 Stochastic
Stochastic calculations were based on the simulation model built. It has taken into
consideration the varying oil water contacts and the presence of any pressure support through
an aquifer. STOIIP calculated from the model was estimated to be around 854 MMbbls, with
a maximum recovery factor of around 61%, which makes the estimate for the recoverable
reserves equal to 530MMbbls.
2.3.4 Uncertainties
Uncertainties surrounding the main input parameters used for the above calculations are:
924.972
1081.36
1240.22
0
200
400
600
800
1000
1200
1400
Minimum
Likely
Maximum

12
1. Petro-physical properties: Lack of core and log data from wells X2, X3 and X6 led to
calculation of the most likely permeability and porosity distribution using data from
other wells.
2. Presence faults and flow barriers
3. Variations in OWC
To study the influence of petro-physical properties on STOOIP estimates, a tornado chart
based on probabilistic calculations has been plotted. Change in porosity has the greatest
influence on STOIIP, while GRV has the least influence.
Figure 12 Tornado Plot
3 Petrophysics
3.1 Introduction
Well data from six exploration wells were provided in order to carry out the final petro-physical
analysis on the field, a list of which is provided in the table below.
X1 X2 X3 X4 X5 X6
Core Samples • - - • - -
Well Test Report - • • - • •
Gamma Ray • • • • • •
Caliper • • • • • •
Acoustic Log • • • • • •
Micro-resistivity Log • • • • • •
Neutron Log • • • • • •
Density Log • • • • • •
0.698
0.563
0.377
-0.106
-0.019
-0.2 0 0.2 0.4 0.6 0.8
1
PORO N/G So Bo GRV

13
Air Permeability • - - • • -
Lateral Log • • • • • •
Porosity • - - • • -
Spontaneous Potential
Log • • • • • •
Litho-Density Log - - - - - -
Table 4 Available Petro-physical Data (• Available, - NA)
Since no Litho-density log data was provided a correlation between core data (permeability,
porosity and density) and log were carried out in order to identify the different lithology present
in the reservoir formation (Facies distribution).
3.2 Lithology Determination
As mentioned above, all log analysis were carried out on techlog, at first GR log was used to
distinguish between the impermeable shale layers and the permeable layers, in certain cases
GR log was not completely reliable eg. well X1 and X2. Since they were the first set of
exploration wells drilled, they are assumed to have been drilled with heavy mud possibly
affecting GR readings, not making it possible to differentiate accurately between shale and
sand strata, in turn effecting Volume of shale calculations. Variations in GR log quality are
shown in the figure below.
Figure 13 Gamma Ray Logs for X1 and X2

14
Furthermore, Sonic, Neutron and Density logs were also used in the identification of the
lithology and water saturation in the reservoir. The main reservoir formation consists of:
 Main sandstone flowunit
 Chalk was encountered as the main cap rock in wells X 3, X4, X5 and X6 whereas
X2 and X1 showed signs of shale being the cap rock.
 Inter-bedded shale but in some cases they mainly formed the base of the reservoir,
there was also possible presence of anhydrite, salt and dolomite within the reservoir
Further analysis using M-N, MID plots and core sample data were used to confirm the
lithology interpretations at the same depths as the logs, the results from these plots also
correlated with the above results as shown in the following figures.
Figure 14 M-N Plot for Wells X3 and X4
3.3 Permeability Determination
The permeability determination of the reservoir was largely depended on core data and
well test analysis as there was no log data available that determines permeability
directly. One major factor highlighted here is that core analysis provided air
permeability values on which corrections for the Klinkenberg effect is assumed to have
been carried out.

15
Cross plots of depth vs. permeability, depth vs. porosity and also cross plots of
permeability with porosity were made which showed high permeability correlated
significantly with porosity.
3.4 Core Data Analysis
The provided core sample data from well X1, 4 and 5 were analysed and geostatistical
calculations were carried out. From analysis of data, coefficients of variation for
permeability were found to be greater than 1, and for porosity less than 1 indicating that
the formation is heterogeneous in terms of permeability and highly homogenous in
terms of porosity.
Well Parameter
Arithmetic
Mean
Median Mode
Standard
Deviation
Geometric
Average
Harmonic
Average
Coefficient
of
variance
X1
Permeability 774.67 530 1300 817.16 231.954 0.69 1.055
Porosity 12.79 11.8 10.5 3.89 0.304
X4
Permeability 772.74 580 1100 751.117 314.09 4.845 0.972
Porosity 24.76 25.1 24.9 3.26 0.131
X5
Permeability 611.53 115 1500 804015 50.17 4.85 1.315
Porosity 14.02 14.95 15.20 2.84 0.202
Table 5 Permeability and Porosity Averages
To further delineate the nature of this trend, the Lorenz plot and semi-variogram for the
permeability data were plotted. It can be seen from the figures below, the presence of nugget
(separation of variogram from origin) suggest presence of small scale heterogeneity and also
long correlation lengths in the horizontal direction in the formation. As we move forward the
trend of the variograms for well X1 and X4 clearly shows the different permeability zones have
repetitive geological elements, suggesting presence of bedding structures, possibly
channelizing fluid flow.

16
Figure 15 Semivariograms for well X1, X4 and X5
Source X1 X2 X3 X4 X5 X6
Core 774mD - - 772.4mD 611.5mD -
Well Test - 317mD 411mD - - 300mD
Table 6 Available Core and Well Test Data
3.5 Porosity Determination
 Porosity was obtained from log analysis and core data; from the core data inter-
connected porosity values were obtained. Porosity calculated from the density and
acoustic log showed different results, indicating possible presence of fractures and
secondary porosity
 Formula for the density porosity and acoustic porosity:
Ø =
ρma−ρb
ρma−ρf
(density porosity), Ø =
tlog−tma
tf−tma
(acoustic porosity),
Semivariogram X1 Semivariogram X4
Semivariogram X5

17
 From the log data we obtained the porosity by cross plotting the neutron and density
porosity values
 Values from the density porosity matched with the core porosity values
 Porosity was averaged using the arithmetic mean as it is not an anisotropic property
3.6 Volume of Shale Determination
Vsh from neurton-density was used as Vsh from GR was not giving reliable readings. It may
have been affected by the presence of high density mud containingg barrite.
3.7 Saturation of water Determination
 Archie equation was used for the calculation of the water saturation; it is normally
applied to the clean (non-shaley) formation
 Sw
n
=
a.Rt
Øm.Rw
, F =
a
Øm ,
 Rw ≈ 0.03 Ω-m which was obtained from Pickett plot,
 m ≈ 2.15, n ≈ 1.98
 n can also be obtained from Resistivity index vs. water saturation ( I = Sw
−n
) , whereas
the exponents m and a can also be obtained from formation factor vs. porosity plots
 F was calculated using the humble formula F =
0.62
Ø2.15
3.8 OWC Determination
The table below shows a comparison between the available log and RFT data highlighting the
first known oil, last known oil and OWC values obtained from the. It can be seen that the logs
for X2 do not give any clear values for the OWC; this was due to the fact that the poor quality
of resistivity log for well X2 made it difficult to interpret a OWC value. A similar trend was
from the resistivity logs for well X5 which ends half way in the pay zone giving no indication
of any OWC.

18
LOG
FKO
X1 X2 X3 X4 X5 X6
10260 10627 10300 10330 10270 10100
LKO
X1 X2 X3 X4 X5 X6
10830 10767 10830 10830 10484 10560
OWC
X1 X2 X3 X4 X5 X6
10830 10830 10830 10560
RFT
OWC
X1 X2 X3 X4 X5 X6
10825 10825 10828 10565
Table 7 OWC (RFT and LOG Data)
The RFT data available for wells X1 and X3 (Appendix) conform to logs giving similar
OWC and also give values for wells X2 and X5.
Possible Conditions for the different OWC:
Probability of a dynamic Aquifer: 20%
Figure 16 Possible Dynamic Aquifer

19
Probability of Compartmentalisation: 5%
Figure 17 Possible Compartmentalisation
Probability for a Sealed Water Compartment: 75%
Figure 18 Possible Completely Sealed Compartment
3.9 Subsidence
Data on fractional change in pore volume for different grain pressures was used to estimate
subsidence. As the reservoir is depleted, the pressure reduces; causing the effective stress on
the rock matrix to increase, thus increasing grain pressure and resulting in overall compaction
of reservoir formation.

20
Lab conditions under which the fractional volume change was obtained, most likely did not
account for pore spaces being saturated with either water or oil. Rock will be less
compressible when its pore volume is saturated with water or oil, rather than with air. To
increase the accuracy of the estimate, the water saturation needs to be accounted for.
Simulation data on the field’s average water saturation over time is not available. Therefore, a
correction factor of 0,5 is believed to be appropriate to account for low compressibility fluid
saturation.
The resulting estimate is not believed to be accurate, but in light of the Ekofisk platforms
subsiding almost 20 feet, rendering them unsafe for operation, this aspect will require further
investigation.
3.10 Uncertainties
 None of the parameters were measured directly, each are dependent on the accuracy
of the logging device. Uncertainties in measurement may include: heterogeneity
effects, effects of thin bed, mud invasion, calibration etc
 Depth matching is not always done correctly
 Uncertainties in interpretation may be due to inter-bedded shales, the parameters used
to calculate the porosity and Sw, homogeneous lithology assumptions and
uncertainties in cut off
 Model based uncertainties and
 Fault positions

21
4 Reservoir Engineering
4.1 PVT Analysis
In order to further understand the available reservoir fluid the available PVT data was studied.
The table below summarizes an average of the data obtained from the three phase stage
separator tests carried out on the fluids obtained from wells X2, X3, X5 and X6. There was no
data available for wells X1 and X4, it was still concluded that oil with similar properties is
present in the whole reservoir.
Reservoir Fluid Properties
Oil Gravity 40.9 API
Reservoir Pressure 5683.55 psia
Reservoir temperature 263⁰F
Bubble Point Pressure, 𝑃𝑏 1800 psia
Oil Density at Standard Conditions 41.5 lb/ft3
Gas/Oil Ratio [Solution] 389.5 SCF/STB
Oil Formation Volume Factor, 𝐵𝑜 1.41 RB/STB
Oil Viscosity 0.46 cp
Table 8 Reservoir Fluid Properties
Since the reservoir pressure is at 5700 psia the oil is under-saturated with an oil gravity of
40.9API suggesting presence of light oil. The figure below summarizes the reservoir fluid
composition, it can be seen that the PVT data does not show any presence of H2S. However,
the production test carried out on well X2 shows a very minor concentration of around 2-5 ppm
present. Tubing and well head materials have been chosen based on these values.
Figure 29 Reservoir Fluid Composition

22
Figure 30 Comparison of Oil formation volume factor and Solution gas oil ratio against
pressure
Figure 21 Oil Viscosity vs Pressure
4.2 SCAL
Porosity – permeability correlations for wells X1, X2, X4 and X5 were investigated.
Table 9 Poro Perm R2 value and Sample Size
Wells X1 X2 X4 X5
R^2 83% 76% 22% 80%
n 545 268 128 405

23
Correlation was found to be very strong, except for well X4; it was treated as an outlier and
considered not representative. One possible reason might be a low sample size. Using 𝑛 ≥
(
𝑧∗𝜎
𝑀𝑂𝐸
)
2
where the z-value for an 80% confidence interval was chosen, standard deviation of
750 mD and a margin of error of 50 mD, required a minimum sample size of n = 370. The
actual sample size was only 30% of that minimum.
Figure 22 X5 Porosity vs Permeability
Having found a strong correlation between porosity and permeability, the aim was to identify
a variable from logging data that could be used to accurately predict porosity values. This
variable was found to be grain density from the density logging tool, showing an R2
of 81%.
Correlation tables are found in the appendix.
Figure 23 X1 Porosity vs Density

24
Predicting permeability from density logs proved to be consistent with observed values.
Figure 24 Permeability Estimation
Using regression functions, permeability logs were constructed, please refer to appendix.
The correlation function for X1 is believed to be representative of the southern reservoir
sector. Likewise the derived function for X5 is applied for the northern sector.
Permeability for X1 from density log: 𝑃𝐸𝑅𝑀 = exp (
2.4535−𝐷𝐸𝑁𝑆
0.038
)
Permeability for X5 from density log: 𝑃𝐸𝑅𝑀 = exp (
2.3727−𝐷𝐸𝑁𝑆
0.023
)
4.3 Well Test
For Well Test, the reservoir model, a radial homogeneous model was selected as it was a
good starting point to keep the model simple. From the data it could be seen that constant rate
drawdown tests were conducted, the fluid was single phase and constant, small
compressibility. Formation thickness (h) in well test, corresponded to the height of the pay
zone, as validated from the Log analysis, for wells X2 and X6. But for wells X3 and X5 the
pay zone was much larger. Flowrates during the final buildup were recorded, Pi is initial

25
pressure of the reservoir at the start of the entire well test, flowrate is 0 bbl/day for wells with
analysis of only buildup test. The formation thickness evaluated during the well test is stated
with the expected pay zone thickness for the respective wells:
Wells Formation
Thickness(h) (ft)
Pi (psi) K (mD) S Actual PI
(bbl/d/psi)
Ideal PI
(bbl/d/psi)
X2 23-6-77 130
(10,640-10,769)
5703 317 2.8 34 40
X3 h 29-05-
82
100
(10,260- 10,860)
5190 411 -1.2 51 NA
X3 i 29-05-82 130
(10,260- 10,860)
5197 310 -1.3 51 NA
X5 09-06-82 72
(10,271-10,826)
5259 8081
(unrealisti
c)
56.7 64 150
X5 20-08-83 295
(10,260- 10,860
4285 810 25.4 64 150
X6 16-10-82 467
(10,107-10,550)
4822 105 9.4 33 250
X6 23-08-83 467
(10,107-10,550)
4216 300 60 33 250
Table 10 Well Test Results
X2 23rd June 1977
X2 Cartesian Plot
8 rate changes, the beginning looked like a double drawdown with different rates but it was a
single drawdown with constant rate. Final drawdown duration (11 Hrs) and buildup (12.5
Hrs) significant time, we will use the buildup section for analysis as longer analysis time
implies that a larger volume of the reservoir was being investigated, and it had a higher
number of data points with least disturbance.
X2 Buildup Log-Log Plot
Time function with full history was used, as data was effected by prior flow. Log-log was the
diagnostic plot as it was used for flow regime identification. Valve installed at the sandface
which is why wellbore storage effects were not seen in log-log plots specifically. It could be

26
seen that the DP was at almost double the value of MTR as it goes into the LTR, indicating
the presence of a single fault around Well X2.
Figure 25 X2 Buildup Log-Log Plot
Interpretation:
Producing Interval for Well X2 from Log analysis was found to be from 10,640 ft to 10,769
ft, this was the same thickness interval used for well test analysis. The distance to the fault
was found from the earliest signature when a fault was encountered, and this will correspond
to the lowest depth of the evaluated formation thickness in this case.
X2 Buildup Semilog Horner
Semilog plot was the specialised plot as it was used to determine the reservoir characteristics.
MTR Slope= -10.294
LTR Slope= -22.46
The LTR slope is at almost double the value of MTR as it goes into the LTR, further giving
validity to the presence of a single fault.

27
𝒓𝒊𝒏𝒗 = √
𝟎. 𝟎𝟎𝟎𝟐𝟔𝟑𝟔𝟕 ∗ 𝟒 ∗ 𝒌 ∗ 𝒕
𝟏. 𝟕𝟖𝟏 ∗ ∅ ∗ 𝝁 ∗ 𝒄𝒕
𝟎. 𝟎𝟎𝟎𝟐𝟔𝟑𝟔𝟕 ∗ 𝟒 ∗ 𝟑𝟏𝟕 ∗ 𝟏𝟑. 𝟏𝟒
𝟏. 𝟕𝟖𝟏 ∗ 𝟎. 𝟐𝟕 ∗ 𝟎. 𝟒𝟗 ∗ 𝟏. 𝟐𝟔𝟒𝒆 − 𝟓
𝒓𝒊𝒏𝒗 = 𝟏𝟐𝟏𝟓𝒇𝒕
Well X2 Injection test
X2 Cartesian Plot
To establish the formation break down pressure, an injectivity test was performed as per the
provided well test report. But the injection test here was further analyzed to determine the
mobility of the injected fluid in the formation, by using the fall-off test (7-18.3 Hours)
(Merrill et al., 1974).
There is no evidence of wellbore storage in the ETR.
Mobility of injection fluid(water) in the injected zone:
𝛌 𝑾 =
𝟏𝟔𝟐. 𝟔 ∗ 𝒒 ∗ 𝑩
𝒎 𝟏 ∗ 𝒉
=
𝟏𝟔𝟐. 𝟔 ∗ 𝟑𝟔𝟎𝟎 ∗ 𝟏
𝟐𝟕. 𝟏𝟔𝟐 ∗ 𝟔𝟕𝟓
𝛌 𝑾 = 𝟑𝟏. 𝟗𝟑 𝒎𝑫/𝒄𝑷
Well X3 ‘h’ 29th May 1982
X3 Cartesian Plot
Final duration of buildup (17.3 Hrs) had significant time with least amount of disturbance in
the signal and a high number of data points were recorded. We used this for analysis, as
longer analysis time implies that a larger volume of the reservoir was being investigated.

28
This plot showed a leaking fault encountered near well 3, by evaluating the rise of the curve
from the derivative plateau to the subsequent dip as seen in the figure below. The DP for
Radial flow was set according to the kh value obtained, as the formation thickness for the
well test was already known and so was the permeability.
For build-up the distance from the fault is given by:
MTR Slope= -10.294
LTR Slope= -22.46
𝟎. 𝟎𝟎𝟎𝟐𝟔𝟑𝟔𝟕 ∗ 𝟒 ∗ 𝟒𝟏𝟏 ∗ 𝟒𝟐. 𝟏
𝟏. 𝟕𝟖𝟏 ∗ 𝟎. 𝟐𝟑 ∗ 𝟎. 𝟒𝟗 ∗ 𝟏. 𝟑𝒆 − 𝟓
= 𝟐𝟔𝟒𝟓𝒇𝒕
It is now known that the fault present is closer to well X2 than X3.
Well X3 ‘l’ 29th May 1982
This well test had a higher number of data points (152 data points), and more fluid data to
input as compared to Well X3 ‘h’. Also with a larger formation thickness being penetrated for
the well test, this model yielded k and S values closer to the Well Test Report X3Rc.

29
X3 Cartesian Plot
Final duration of buildup (17.5 Hrs) had significant time with the least amount of disturbance
in the signal, we used this for analysis as longer analysis time implies that a larger volume of
the reservoir was being investigated.
As the underlying model for the curve match, a Closed system selected, with one side
selected as a constant pressure boundary which was interpreted as a sealing aquifer. [2]
MTR Slope= -54
LTR Slope= -118
𝟎. 𝟎𝟎𝟎𝟐𝟔𝟑𝟔𝟕 ∗ 𝟒 ∗ 𝟑𝟏𝟎 ∗ 𝟑𝟑
𝟏. 𝟕𝟖𝟏 ∗ 𝟎. 𝟐𝟓 ∗ 𝟎. 𝟒𝟗 ∗ 𝟏. 𝟐𝟐𝒆 − 𝟓
= 𝟐𝟎𝟏𝟑 𝒇𝒕

30
Well X5 9th June 1982
Interpretation:
Metering problems were quoted in the well test report which rendered the recorded
production rates as doubtful. Also, the Log-log plot was not reliable as permeability was
abnormally high, when setting up the DP.
Well X5 20th August 1983
X5 Cartesian Plot
Final Buildup (13 hrs duration) was used for the same reasons as stated for the earlier tests.
This well was showing signs of wellbore storage in the ETR.
Interpretation:
For a light oil, fluid compressibility and viscosity may change due to the change in pressure
in the wellbore (Kuchuk, Onur and Hollaender, 2010). This suggests why the ETR was not
matching with the assumed model. So as time goes by, a different wellbore storage
coefficient value will be applicable to the model, however during the matching process only

31
one value could be applied to the model. The Log-Log plot showed a half slope in the LTR
which would signify linear channelized flow.
Alternate Interpretation:
It can also be said that if the buildup test was made to flow for a longer period then perhaps
the LTR in the Log-Log plot would flatten into a DP justifying the presence of a fault.
In this specialized plot, the effective permeability value almost the same as the well test
report (X5Ra) permeability.
𝟎. 𝟎𝟎𝟎𝟐𝟔𝟑𝟔𝟕 ∗ 𝟒 ∗ 𝟖𝟏𝟎 ∗ 𝟏𝟑
𝟏. 𝟕𝟖𝟏 ∗ 𝟎. 𝟐𝟑 ∗ 𝟎. 𝟒𝟗 ∗ 𝟏. 𝟑𝒆 − 𝟓
= 𝟐𝟎𝟔𝟑 𝒇𝒕
Well X6 16th October 82
X6 Cartesian Plot
Final Buildup (16.5 Hrs) was used for the same reasons as stated for the earlier tests.
Seems to be constant pressure boundary or partially penetrating well from test

32
Interpretation :
The 9th
June 1982 well test showed a log-log signature dipping downwards in LTR, which
could be interpreted as the beginning of a derivative rollover (Stewart, 2011). Perhaps enough
time was not spent for the corresponding buildup test. So there might be a constant pressure
boundary signifying a closed system around well 6.
From log interpretation, at a depth of 10550ft, water was detected, and at 10575ft, a shale
layer present, had started signifying that there was a sealed aquifer. Very low permeability
value obtained, signifies an isolated system
Interpretation:
Very low radius of investigation.
𝟎. 𝟎𝟎𝟎𝟐𝟔𝟑𝟔𝟕 ∗ 𝟒 ∗ 𝟏𝟎𝟓 ∗ 𝟏𝟔. 𝟒
𝟏. 𝟕𝟖𝟏 ∗ 𝟎. 𝟐𝟑 ∗ 𝟎. 𝟒𝟗 ∗ 𝟏. 𝟎𝟕𝟕𝒆 − 𝟓
= 𝟗𝟏𝟕 𝒇𝒕
Well X6 23rd August 1983
X6 Cartesian Plot
Final Buildup (18 Hrs) was used for the same reasons as stated for the earlier tests.

33
Interpretation: The well test in 20th
August 1983 showed a wellbore storage in the log-log
plot and in the LTR, the curve seemed to be gradually increasing with an apparent unit slope
in LTR, which can be interpreted as a possibility of recharging of the reservoir pressure.[5]
This could be due to the presence of a leaking fault between wells X5 and X6.
Alternate Interpretation: Perhaps, if enough buildup time was given to this case, then it might
show a fault, which could explain the rise seen in the log-log plot.
Effective permeability on the well test report X6Rf was 500mD. There was abnormally high
skin, which can also be seen as the case in the well test report X6RF. Over here it was even
higher.
Integration of Well Test and Petrophysics:
The Initial pressure of 4215 psi for well X6 in 1983, and initial pressure of 4285 psi of well
X5 in 1983 signifies good communication between the formation of the wells. Which can
also be confirmed from the Pressure-Depth graph produced from the RFT data. This can be
interpreted as a leaky fault occurring between wells X5 and X6. From Log data, there was a
good correlation being derived between wells X4, X5 and X6, which can be a good indicator
that these 3 wells have no fault between them.
Integration of Well Test and Core Data:
From the core data of well X5, the permeability was found to be 611mD but from well test
the permeability was 810mD, the difference can be due to the assumption of the arithmetic
mean method used for the core data and it should be noted that the permeability during well
test is associated with the range of the formation thickness being evaluated and an effective
permeability value is obtained. Whereas the core value only represents a localized
permeability. Still, it can be deduced that the difference between the permeability values is
realistic.

34
4.4 Reservoir Simulation
4.4.1 OWC Determination
The OWC of the remaining wells was determined from the resistivity logs. The OWC was
confirmed from RFT for Wells X-5 and X-6.
Well X-1 X-2 X-3 X-4 X-5 X-6
OWC 10825 10825 10828 10830 10565 10550
Table 11 OWC for all Wells
Based on the table, the Well-Tops were created in Petrel and the OWC surface was
generated.
Figure 34 OWC Generated from Logs in Petrel
The free water level is assumed to be 20ft below OWC and corresponding surface has been
built to be used as the top of aquifer.
4.4.2 Relative Permeability and Capillary Pressure
The two sets of capillary pressure and relative permeability measurements were given for five
different types of sand in the reservoir. The sets marked A, and B belonged to Well X-6. The
capillary pressure in the B-set is 50 times higher than in the set B (order of 50-70 psi on set B
and order of 1.3 psi in set A) this difference could be due to a different measurement

35
technique used or a case of measurement error. Based on the fact that most of the reservoir
consists of high permeability sand the set A was used, as it was assumed to be a better
representative of the reservoir. The saturations in both sets were similar.
The shale region was assumed as Sand 5 due to similar permeability and porosity. Some
measurement rows were removed in the saturation curves due to anomalous values.
From the capillary pressure data for each rock type 1, 2 and 4, the rock in the sands was
poorly sorted and slightly coarse, for sand 3 – unsorted, for sand 5 – poorly sorted/slightly
fine. The curves were generated for all sands, as shown for some of the sands below:
Figure 32 Sand 1 kr vs Sw Figure 33 Sand 2 kr vs Sw
Figure 34 Sand 3 kr vs Sw Figure 35 Sand 4 kr vs Sw

36
4.4.3 Input data
 Logs: GR, CALI, Deep, Medium, Micro Resistivity, Density, Neutron, Calculated
Saturation (Archie), Facies log (manually created), Calculated porosity log from
Neutron-Density
 PVT
 Rock properties
 Core data for wells X-1, X-4 and X-5
 Porosity-Permeability data from X-1, X-2 and X-5
 Reservoir Surface map
 Well Test analysis results
 Manual calculations: GRV, Semi-Variograms,
 Functions: Water Saturation, Capillary pressures from relative permeability tests
 RFT results
Tools Used
 Log interpretation was performed in Techlog
 Full reservoir model with flow units was built in Petrel
 Simplified reservoir model simulations were done in Eclipse
 MS Excel was used for Monte-Carlo simulation and semi-variograms.
4.4.4 Grid Analysis and Model Design
The original grid size in Petrel was 50 X 50 X300. That was upscaled to 49 x 51 x 100 in the
interest of speeding up the simulation and the resulting STOIIP and distribution of properties
was not compromised. Vertical resolution was higher, as data taken from the logs was at
given depths. Total number of grid cells in Eclipse was 166100.
 STOIIP calculation from the reservoir model was 854,445,318 STB

37
 Dissolved gas 363,498,127 MSCF
 Water 722,161,522 STB (including the aquifer)
Log data was used for the existing exploration wells and deviation surveys:
Figure 35 Existing Exploration Wells
4.4.5 Facies
The Facies log was manually created in Petrel based on core permeability and porosity logs
for wells X-1, X-4 and X-5. Well X-6 had missing resistivity logs, except total resistivity.
Facies distribution in Petrel corresponded to flow units rather than actual geological facies.
Each flow unit had its own saturation and capillary pressure curve.
Figure 37 Flow units assigned from Logs

38
Since the reservoir itself consisted of different types of sandstone one stratigraphic zone was
assumed. The reservoir was however divided into 5 sandstone facies types based on the core
permeability and porosity from the wells X-1, X4 and X-5:
Facies Name Porosity range, cp Air Permeability range, mD
Sand 1 >27 >1000
Sand 2 20 to 25 500 to 1000
Sand 3 20 to 23 100 to 500
Sand 4 20 to 23 10 to 50
Sand 5 <20 <10
Table 12 Sand Flow Properties
Facies upscaled log data analysis and variograms
Distribution method used was Sequential Indicator Simulation, as deterministic methods such
as moving average and closest used unrealistic assumptions. Sequential Gaussian was used
for flow units permeability and porosity. The variograms considered a shallow marine
deposition environment. [1]
4.4.6 Petrophysical Properties
Sequential Gaussian distribution was used in order to distribute the petro-physical properties.
Deterministic methods such as moving average and closest were applied, but they used
unrealistic assumptions. Moving average tends to take the average permeability and porosity
values between a data set and tends to spread them across a layer giving an unrealistic
geological form, whereas the closest method tends to correlate data of the closest wells and
spread them across the created layers. [1]

39
Figure 38 Permeability (Sequential Gaussian Distribution)
Closest and moving average is best used when a large number of data sets are available from a
higher number of exploration wells, which in our case is only limited to 3 wells, due to which
Sequential Gaussian distribution was used to upscale and distribute permeability, porosity and
water saturation across layer correlating to the facies distribution.
Figure 39 Porosity (Sequential Gaussian Distribution)

40
Figure 40 Water Saturation (Sequential Gaussian Distribution)
4.4.7 Reservoir Simulation Results
MODELS MODEL DESCRIPTION FOE
(%)
FWCT
(%)
FOPT
(MSTB)
BASE
CASE
20 Producers and 19 Water Injectors 59.3 97.8 503
MODEL1 17 Producer and 16Water Injectors 61.3 97.7 520
MODEL 2 11 Producers and 8 Water Injectors 60.2 94.0 510.5
MODEL 3 18Producers, 8 Water injectors and 1 Gas
injector
58.6 92.6 497
MODEL 4 11 Producers, 8 Water Injectors and 1 Gas
Injector
61.3 97.7 520
MODEL 5 11 Producers, 8 Water Injectors and 1 Gas
Injector (30000 Injection and Production
Rate)
59.6 93.6 505
MODEL 6 18 Vertical Producers, 8 Water Injectors
and 1 Gas Injector
58.0 92.2 492
MODEL 7 11 Vertical Producers, 8 Water Injectors
and 1 Gas Injector
59.6 92.9 505
Table 13 Simulation Model Cases

41
The field development plans were carried out on Eclipse. The base case included 20 deviated
producers and 19 water injectors, whereas the initial exploration wells were converted to
injectors. The liquid production rate for all the producers and injectors was kept constant at
20,000 STB/day and 30,000 STB/day and the bottom hole pressures at 2000psi and 6500psi
respectively.
The water injectors were completed in the water leg of the model which tends to provide better
sweep of oil from the lower sections of the reservoir to the producers. With a higher number
of producers in the base case a steady production rate profile could not be obtained as not all
the wells were producing at a consistent rate and in turn producing far lesser than their
economic limit and also tend to produce more water due to which the field reaches the water
cut economic limit 98% in 20 years itself.
Figure 41 Base Case Water Cut profile

42
Figure 42 Base Case Oil Production Rate
Model 1-7 were modeled on the fact of reducing the number of producers and injectors while
providing the similar or even better oil recovery efficiency than the base case. Model 4 gives
the best FOE 61.3% compared to the other models, referring to the figure below we see that a
steady production plateau has been achieved in the first four years of production which is later
continued by a steady decrease in oil production.
Figure Model 4 Well Placement

43
Figure 43 Model 4 Oil Production Rate
Model 4 consisted of 11 deviated producers, 8 water injectors and a gas injector. The gas
injector in this case was used to re-inject the gas originally been produced from the reservoir
and was placed at the crest of the reservoir and completed in the first five layers of the reservoir
to sweep the attic oil from the top of the reservoir.
The reduction in water injectors and the addition of a gas injector also reduced the water cut in
the initial stages of production and correlated with oil production profile and plateaued in the
first four years reaching maximum production plateau in those years.
0
20
40
60
80
100
120
140
160
180
3000
3500
4000
4500
5000
5500
6000
0 5 10 15 20 25
000STB/DAY
PressurePSI
Years
FPR FOPR

44
Figure 44 Model 4 Field Oil Depletion
Figure 45 Model 4 Water Cut Profile
5 Drilling Facilities
5.1 Geology and Pressure prognosis
Since no information was available about the formation pore pressures and the geology above
the reservoir these data assist with the planning of the well. We referred to a geological data
available from a nearby field in the North Sea (one of the oil fields located in the north)[1]
.
Brent field was chosen in this case as it has the most data available with regards to the
lithological and chronological sequence.[2]
Where the pore-pressure and fracture pressure
prediction from seismic velocities were derived from amplitude variation with offset (AVO)
information. Pore pressure data up to the depth of 10,200ft was used where the chalk (cap rock)
was present.
Pressure prediction from the seismic were calibrated with the help of pressure data from one
well, and the other five wells were used to verify the predictions made by the seismic. [3]
0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1
3000
3500
4000
4500
5000
5500
6000
0 5 10 15 20 25
PressurePSI
Years
FPR FWCT

45
Pore pressure data was matched according to the lithology rather than the depth, which was
one of our assumptions. The overpressure region of about 0.74psi/ft was because of the
presence of the shale.
Figure 46 Stratigraphic Column for Brent vs. Seismic Pore Pressure Prediction[2][3]
Depth – TVDSS (ft) Lithology Pressure gradient
(psi/ft)
0-4100 sandstone (hutton sand) 0.46
4100-6300 shale (hutton clay,
balder, lista)
0.74
6300-8400 shaley limestone
(Shetland marl, Shetland
clay )
0.74
8400-8700 shale (humber group ) 0.74
8700-9500 shaley sandstone
(brent group )
0.74
9500-10100 chalk 0.74
10100-11000 sandstone 0.3
Table 34 Predicted Lithological Sequence with Pore-Pressures
Over-pressured region
Under-
pressured
region

46
5.2 Drilling Fluid selection
The selected drilling fluids must be able to carry out a number of functions such as transferring
energy to down-hole drilling system, controlling the well, cooling and lubricating the drill-bit.
The reservoir section was normally pressured according to the data given, but the formation
above the reservoir was overpressured in the shale region. The chosen mud density is below
the fracture pressure but above the pore pressure, having an overbalance of about 250psi, as
greater care must be taken not to damage the environment. Formation is drilled using WBM
(water based muds) as it is less damaging to the environment. The fluid cost is also taken into
consideration, as no data is available about the lithology. Shale shakers should also be used in
order to remove the solids (drill cuttings) from the drill muds. Desanders and hydro cyclones
may also be used as solid control equipment.
5.3 Directional plan
Well profile is an S type well which consists of two build up sections. Kick off point is taken
to be around 1500ft TVDSS. Kick off point is chosen to be in the consolidated formation found
below 1500ft TVDSS. First BU section is taken at 1°/100ft which ends at a tangent angle of
38°, which can be drilled using a conventional BHA. Second BU section is at 8°/100 ft. This
angle is chosen such that an ESP maybe easily accommodated and can have a maximum
efficiency. Horizontal wells reduce the cost of drilling wells, and increase the drainage area.
Figure 47 Horizontal Well Profile

47
Section
TVDSS
( ft )
Cumulative
TVDSS
( ft )
Measured
Depth
( ft )
Total
MD, ft
Inclination angle
( degrees )
Horizontal
Displacement
( ft )
start end Interval total
Vertical
section
1500 1500 1500 1500 0 0 0 0
BU 1 3560 5060 3842 5342 0 38 1241 1241
Tangential
Section
4740 9800 6050 11393 38 38 3759 5000
BU 2 600 10400 711 12104 38 90 325 5325
Horizontal
section
0 10400 1200 13304 90 90 1200 6525
Table 15 Horizontal Well Trajectory
5.4 Drilling Schedule
Year Well
count
Wells
Completed
Time taken (yrs) Cumulative Years
2017
1
1 gas injectors,
2 producers
0.17 0.17
2 0.17 0.34
3 0.16 0.50
4
4 producers
0.14 0.63
5 0.13 0.76
6 0.12 0.88
7 0.12 1.01
2018
8
4 producers
0.13 1.13
9 0.13 1.26
10 0.13 1.39
11 0.13 1.51
12
1 producer, 3
water injectors
0.13 1.64
13 0.13 1.76
14 0.13 1.89
15 0.13 2.02
2019
16
4 water
injectors
0.13 2.14
17 0.13 2.27
18 0.13 2.39
19 0.13 2.52
20 1 water injector 0.14 2.66
Table 16 Drilling Schedule
5.5 Casing and Cementing program
Casing depths and sizes were chosen according to the expected pore pressures from the
geological and pore pressure prognosis, the burst and collapse loads were calculated with
safety factors of 1.1 and 1.0 respectively. The casing and hole specifications are given below:

48
Casing
Name
Hole
size
OD
(in)
ID (in) Weight
(lbm/ft)
Burst
Load
(psi)
Collapse
Load (psi)
Grade Setting
Depth
Conductor 36” 30 28 - - - - 200
Surface 24” 20 19 106.5 1122 690 J – 55 1500
Intermediate 17
½”
13
3/8
12.415 68 3067 1886 J – 55 4100
Production 12
¼”
9
5/8
8.535 53.5 7931 6825 C – 90 10050
Liner 8 ½” 7 6.094 32 10760 9740 C – 95 10900
Tubing 5.5 5.012 14.5 8290 7250 N - 80 10150
Table 17 Casing Specifications
5.6 Bits and BHA
PDC Bit FMR3961ZS • Suitable for soft formation( Chalk and lime stone)
• Can drill the entire section in a with a single drill bit.
• High ROP, high bit run time.
• RSS ensures the stability of hole.
• Drilling time reduced by avoid tripping time. Hence cost
saving.
PDM[4]
Power Drive
Exceed System
• Highly deviated wells (above 80degrees)
• Reduces Run time
Roller
Reamer[6]
On-gauge
Torque
Reduction
reamer
• Reduces down-hole torque and doglegs
• Maintain bore hole quality
• Maintains hole gauge for abrasive conditions.
Spiral
Drill
Collar[5]
Drillco drill-
collar
• Provision of drilling weight is the most universal
application of drill collars.
• Hole size integrity results from proper drill collar sizing,
enabling the desired casing size to be run to bottom.
• Spiral drill collars reduce the area of contact between the
drill collar and the hole wall, a helpful feature when
differential sticking is a problem.
Drill Pipe TBPK-
127X9,19
 Can be used in vertical and horizontal
Table 18 Bottom Hole Assembly
5.7 Cementing Procedure
 Class B cement is recommended for shallow depths and used for both conductor and
surface casing. These two casings are cemented all the way to surface.

49
 For intermediate casing class C cement is used. This cement becomes hard relatively
quick, because of high c3s content. Hence saves rig time. The top of cement for
intermediate casing is 300ft in to the surface casing.
 Two stage cementing is used for production casing. First stage cementing is done with
the TOC (Top of Cement) of 300ft above bottom of hole and the second stage
cementing is done at depth where intermediate casing ends, till 300ft in to the
intermediate casing.
 Production liner is cemented with class D cement, with the TOC till the top of liner.
Class D cement is well known for their retardation capability and their ability to work
satisfactorily in deep wells, with high temperature and pressure.
 All the cement used are in API standards. Due to the high temperature and pressure in
our reservoir, the setting time of cements is less hence reducing rig layoff time. [3]
CASING CEMENT
CLASS
CEMENT
DENSITY
(lbs/gal)
NO. OF.
STAGES
TOP OF CEMENT
(TOC)
Conductor
casing
Class - B 15.6 Single stage Up to surface
Surface
casing
Class - B 15.6 Single stage Up to surface
Intermediate
casing
Class - C 14.8 Single stage Up to 300ft in to surface
casing
Production
casing
Class - D 16.4 Two stage Stage 1 – Bottom of hole
up to 300ft in annulus
Stage 2 – 300ft in to the
previous casing, from
bottom of previous casing
Production
liner
Class - D 16.4 Single stage Up to 300ft in to
production casing
Table 19 Cement Specification

50
5.8 Risk Assessment
 From the environmental report, an earthquake[7]
took place (recent in the sense of
geological terms) and our field is right where the epicentre was, meaning it is a
tectonically active zone. Sensible selecting of cement need to be considered. To reduce
chance of annular blow out, the BOPs should always be in place.
 As seen by the seismic pore pressure prediction, there may be unidentified zones which
are extremely overpressured and under-pressured above the chalk zone, which may lead
to hole collapse. Overpressured salts[8]
can cause casings to collapse.
 In case of extreme lost circulation, LCM mud may be used or cement may also be used.
 For clay swelling and bit balling, polymers maybe used which inhibit reaction of clays.
For well control issues, regular training to the drilling crew, primary and secondary
control are always in place. For poor hole cleaning, the right mud weight should always
be selected.

51
Figure 48 Casing Setting Depth with respect to Pressure

52
5.9 New technology (Geo-steering)
In the process of drilling a borehole, geo-steering is the act of adjusting the borehole position
(inclination and azimuth angles) to reach one or more geological targets. These changes are
based on geological information gathered while drilling.
The complex geological structured reservoirs like North Sea demand a high power and reliable
drilling system. The LWD comprises azimuthal gamma ray, azimuthal density neutron
measurement and array resistivity. The placement of well can be accurately controlled by the
operator, by using the real time log data measured by a LWD [9]
. Also, an optional web based
real time monitoring system can be used to control the trajectory of the well from onshore.
This combination of BHA will provide required sharp changes in well path, as per the geology.
The dogleg angles of 7-8ᵒ
/100ft can be achieved and it is more than sufficient to meet
requirements. The selected RSS is suitable for wide range of LWD tools [1]
. Vibrations, shock
and pressure while drilling are also available with azimuthal wellbore images. By using the
aggressive PDC drill bit with above BHA, it is relatively easy to drill both hard and soft
formation [2]
. The real time monitoring system enables the drilling team to make timely geo-
steering decisions. An average rate of penetration of 30m/hr can be achieved, which is almost
50% more than the conventional RSS and BHA.
Advantages
 High quality hole in relatively short time can be drilled.
 Accurate and real time bottom hole dataset available, so no need to stop drilling for geo-
steering decisions.
 Azimuthal wellbore images are available.
 Sharpe changes in well path can be done.
 High rate of penetration. Hence drilling time reduced.

53
6 Production Technology
6.1 Well Production/Injection Constraints
Minimum producer BHP(Bubble Point Pressure, Sand Production Problems): Fluid is to
flow above bubble point to avoid separation of gas and oil in the well. So as the bubble point
pressure for the reservoir fluid was 1800psi, the minimum limit on the BHP is going to be
2000psi. This will also help the ESP operate normally, even without a gas separator. The
following BHP vs Reservoir Pressure range is to be avoided to prevent sand production:
Figure 49 Sand Production Triangle (derived from similar formation) [1]
Maximum injector BHP: Fracture pressure from the drilling data was found to be above
10,000psi at depths below 12,000 ft. So the injector pressure is set at maximum, 6,000psi.
Fracturing: Fracturing will not be required as the reservoir has good enough permeability, so
the extra cost and time does not have to be invested for this procedure.
Maximum Well Production Rate: 20,000 STB/Day
Maximum Well Injection Rate: 30,000 STB/Day
Updated Reservoir Modelling with realistic production constraints: Using analysis from
production software PIPESIM, the intial reservoir model of 20 producers and 19 water injectors,
was reduced to that of only 11 producers, 8 water injectors and 1 gas producer. With the same
amount of recovery, over 20 years, and a steadier decline in fluid production rates. All due to
analysis on the suitable type of wells, achievable production/injection rates and completions.
0
1000
2000
3000
4000
5000
6000
7000
0 1000 2000 3000 4000 5000 6000
ProducingBottomHolepressure
Reservoir Pressure
Formation Failure Envelope
Sand Free
Production
Sand
Production
Region

54
6.2 Surface Facilities
Fluid Processing and availability: The gas and water produced will be separated and
reinjected. As gas will be an economically insignificant amount, considering the factor of a
geographically dense market competition . Oil will be transported through pipelines.
Costing of Process Facilities: 20% of the total cost will be $533 million.
Rate of Reserves Depletion: An average of 70,000 STB/Day of reservoir fluid will be
produced over a period of 20 years.
Recovery Mechanisms: Primary recovery is natural flow. Water Injection will be done using
sea water and separated water from the produced reservoir fluid.Gas Injection will also be
used as there will be dissolved gas in the reservoir fluid which will be separated and primarily
used for gas injection as flaring is not allowed by UK Environmental Law.
Platform: At water depth (98 ft), the field could be developed at subsea with the development
of the Monopod platform. However, the following considerations were taken into account:
1. High production rates, and the necessity to process large volumes of liquids and store
up to 1 Million barrels of oil, while waiting on the construction of the pipeline.
2. Primary recovery will be without artificial lift, however, at some point the artificial lift
will be installed requiring Extra Electrical power generation or Extra gas compression
3. Secondary recovery planned by water support therefore the water treatment will need to
be performed on field
4. Some well treatments such as scale removal are also expected
5. FPSO cannot be used due to environmental regulations
6. Produced gas will be re-injected due to environmental regulations.
As a result, the steel jacket platform development is recommended.
Pipeline: Due to the lack of available oil pipelines near the field and environmental
regulations restricting the use of a floating vessel to transport the oil to the nearest shore, a

55
pipeline needs to be built that could handle a maximum flow rate of 69,000bbl/day to be
transported over a distance of 250kms. Based on the network simulations carried out on
pipeline diameters ranging from 15 – 30in. the minimum recommended diameter was 25in.
Further it was seen from the figure below that any further in increase in pipe size above 25in.
had minimal effect on the flow.
The minimum flowing pressure required to transport the oil to a distance of 250km should not
fall below 3000psia, any further decrease below this shall restrict the flow. Further it can be
seen from the figure below any further in increase in pipe size above 25in has minimal effect
on the flow, therefore 25in pipeline is recommended.
Separator: The recommended separator pressure range is between 50 and 150 psi. Since the
oil that is produced is light oil with high shrinkage 3 stage separation is recommended prior
sending oil to the pipeline. This will reduce the water in the pipeline which is turn will reduce
the possibility of scale formation. Maximizing gas separation will assure that all of the gas is
sent to sale. 3-phase horizontal separators is recommended in order to export oil that meets
sales specification and remove all of the water and gas that will be used for reinjection.A 3-
stage separator is recommended that can handle up to 50,000- 200,000 bbl/day with an
internal diameter ranging from 14-16ft[8]
in order to export oil that meets sales specification
and remove all of the water and gas that will be used for reinjection. The new technologies
such as PipeSeparator or Multipipe were not considered due to environmental regulations.
Riser: Sensitivity analysis on the riser size was performed. Based on the calculation of
maximum flow rate the liner diameter could be from 21 to 23 inches.
Compressors: From the network analysis it will be required to process 230 mmscf of gas per
day, as all wells will not be put in production at the same time the gas amount per day will not
exceed 180 mmscf. The suggested compressor is LTS-1 or LTS-2, 33000HP, 180mmscfd.[7]

56
Multiphase flow meters: As the wells were extremely high rate and produced high quality
oil, the exact amount of knowledge is vital to understand how much oil will be supplied to the
process facility. Therefore it is recommended to install multiphase flow meters for each well.
The data received from the multiphase flow meters will help achieve a better representative
history match of the reservoir model and help in further production stimulation decisions.
Design and Optimization of Production Network:
The production network includes 11 wells with chokes and risers, all risers assumed length
300ft and elevation 100 ft. The Platform point is simply where fluid merges and flows straight
to a separator. Only one separator has gas and water is separated at 100% efficiency (which in
reality may not be the case depending on selected separators). This will be a 3 stage-separator,
practically recommended. Gas and water flow into the gathering point (water injection facility
on the platform and possible gas injection point). A booster is added after the separator unit to
create a pressure in order to flow oil stream down the 250km pipeline. Schematic includes
wells, chokes, risers, separator, sinks, multi-phase booster and oil process plant.
Single Well simulation setup
Figure 50 Production Network Schematic

57
6.3 Principal Well Design (inflow level)
Well stimulation: From well test reports skin reached up to 60+ values. Also during
perforation, to unblock plugging, (or during drilling) acid stimulation will need to be used. Or
reperforation can be used.
Introduction of Artificial Lift to maintain required Well rates
From the reservoir simulation analysis the water production will significantly increase four
years into production. The wells will stop flowing naturally once the water cut reaches 60-
65% and the reservoir pressure drops to 2900 psi. At that point artificial lift will need to be
installed. The expected pressure drop during the first year of production is from 4600 to 3600
psi. As due to the increase of a water cut of only 10%, it will not be possible to hold the
production of 20,000 bbl of oil per day as planned. Based on the analysis it is recommended
to run artificial lift after the first year of production.
Recommended form of artificial lift
Below is the summary flowrate received for ESP and Gas lift at different water cuts. The
maximum gas lift injection rate is selected as comparison point, reservoir pressure 2900 psi.
Water Cut, %
Gas Lift ESP
Flowrate, stb/d Flowrate, stb/d
60 12496.39 20819.46
65 11208.22 19932.91
70 9615.536 18599.89
75 7877.752 16276.45
80 6258.031 10525.14
85 4926.919 n/a
90 3909.66 n/a
Table 21 Gas Lift vs ESP
Choice of the ESP
Based on the rates above and the offshore location, the choice of artificial lift would be
between gas lift and ESP. Because of the high water cuts ESP would be the primary choice.
The ESP will not be able to produce, the maximum water cut possible is 80 %. The ESP will
operate normally even without a gas separator as the bubble point pressure will not be

58
achieved at the ESP depth for designed rates. From the available catalog, the chosen ESP is
REDA H22500N based on design rate, power consumption, number of required stages (less is
better), and efficiency.
ESP Power, HP Number of Stages Efficiency, %
REDA H22500N 314.5322 34 79
CENTRILIFT HC19000 372.6817 36 66
REDA HN20000 490.2211 99 50
Table 22 ESP Selection
Some degree of sand production is expected from the reservoir initially, but it should stop by
the time ESP will be started. From the plot of the ESP operation, an 80% watercut will not be
possible. Recommended water management measures would be workover and re-perforation
and usage of ICD’s. The final liquid rate at 80% water cut is 10525.14 bbls/day.
6.4 Principal Well Design (outflow level)
Completion design requirements:
 Wireline access
 Ability to inject fluids (chemicals)
Perforation
From the results of sensitivity analysis for the vertical well following perforation parameters
are recommended: (Perforation design settings in Appendix)
Perforation density Perforation
length
Perforation
diameter
Vertical well 6 shots per foot 9 inches 0.22 to 0.24 inches
Horizontal well 4 shots per foot 7 inches 0.23 to 0.26 inches
Table 23 Perforation Sensitivity Results
Sand Production: Exploration wells only initially produced sand (production data of X-2).
From the core of the exploration well X-5 Brinell‘s Hardness Number varied from 6kg/mm2
to 29 kg/mm2 (statistical analysis (Appendix): mean value 10.2kg/mm2) which indicated that
the formation layered with friable and consolidated sand. It is recommended to:
 Access to artificial lift
 Downhole metering

59
1. Perforate stronger rock (Brinell’s Hardness number>10)
2. Ensure wells are ramped up (brought to production) slowly
3. Produce the wells at a low, constant rate and high BHFP than potential,
Zonal Control
Production zones are associated with the high permeability sands. The thickness of oil
saturated zone varies from 250 to 600 ft with thickness increasing towards the north-west of
the reservoir. One producing zone will be perforated as no significant impermeable layers are
expected.
Subsurface Safety Valves are to be set at 100ft below the sea floor in order to reduce the
amount of potential spill because of the high rate we are expecting. For the reference the
MMS regulation (US Minerals Management Service) was used as a good practice. According
to MMS, this is as high as the valve can be installed. Schlumberger also follows these
regulations for offshore development. [9]
Flow assurance components:
Scaling is not anticipated to be a major problem as the reservoir fluid composition is low in
CO2 (Caron Dioxide), and no considerable S (Sulphur) and H2S (Hydrogen Sulphide)
content. However, due to possible injection of seawater, the low solubility BaSO4 scaling can
be removed by using scale inhibitors.
Inlfow Control Devices that will block the water or re-perforation would need to be for
higher water cuts. ICDS can also potentially make natural flow longer by cutting off water
production intervals. If ICD’s are not installed then re-perforation may be required, therefore
the completion design should allow that.

60
Recommended completion string: Both completions are designed for high rate wells. Both
completions can be used both for production and injection.
Completion Option 1
Following modifications to be made to
original completion:
5.5in. production tubing instead of 7in.
tubing with 5.5in. long tail pipe and
7in. perforated liner. This completion
utilizes polished Bore Receptacle and
includes side pocket mandrel for
chemical injection.
ICDs’s should be installed along the
tailpipe. The tailpipe to be perforated.
This completion is more expensive and
subject to economics consideration
Completion Option 2
This completion doesn’t have a long
tail pipe which limits the ability to
perform measurements downhole but it
allows higher inflow through the 7in.
liner.
Since it is a platform development,
access to the well is not restricted.
Further modelling is performed with
this type of completion as a cheaper
option.
Table 24 Completion String Options

61
Selection of the completion type Vertical vs Horizontal
Sensitivity Vertical
Completion
Horizontal
Completion
Maximum flow rate @separator pressure
50psi and initial reservoir conditions
(0.88% water cut)
44666 STB/D 45623 STB/D
How long will the well flow naturally at
taking into account increase of water cut
and reservoir depletion to 2900 psi
60% water cut 60% water cut
Sensitivity to formation damage –
damaged zone permeability 100 to 10 md
Production drop by
over 6000 STB/D
Production drop by
630 STB/D
Sensitivity to formation damage –
compacted zone permeability 100 t0 10 md
Production drop by
nearly 30000 STB/D
Production drop by
nearly 5000 STB/D
Sensitivity to tubing size at separator
pressure 50 psi
Rate starts to differ significantly when tubing
is more than 5.5 inches, horizontal
completion rates are significantly higher.
Since drilling only allows 5.5 inch tubing
there is no difference between the two
completions
Sensitivity to damage zone diameter,
damage zone permeability 100 mD
Loss of almost 3000
STB/D
Loss of 700 STB/D
Sensitivity to vertical permeability, range
50 to 250 mD
Rate decrease by 500
STB/D
Rate decrease by 700
STB/D
Sensitivity to horizontal permeability,
range 100 to 1000 mD
Rate reduction over
12000 STB/D
Rate reduction by
500 STB/D
Tubing size sensitivity to deliver over
20000 STB/D
5in ID 5in ID
Table 25 Sensitivities, Vertical vs Horizontal Completion
Recommended Production Well Design
Horizontal wells gives better rates, are less sensitive to formation damage and flow naturally
at a lower reservoir pressure. There is usually less uncertainty for horizontal permeability
As seen from analysis the vertical wells are extremely sensitive to the permeability change
and can have significant reduction in rate because of it. The recommended well completion is
horizontal or deviated.

62
6.4 Detailed Well Design
Well Models and Schematics:
Figure 51 Vertical well profile (Reservoir shape – hexagon, shape factor 27.6[2]

63
6.6 Reservoir Management & Monitoring
Uncertainty/Mitigation: To predict the performance of the designed wells and facilities it
was necessary to consider potential problems during the life time of the wells. Based on the
analysis of geology of the formation, rock characteristics, reservoir and fluid characteristics,
the summary of the potential production problems is shown below. Subsea workover is
expected to be kept at minimum:
Issue Why Where Risk Mitigation
Formation damage In high permeability
zones high level of
loss of drilling
mud/cement is
expected
Reservoir
sand
Reduced
production,
skin
Underbalanced
drilling
Water breakthrough in
late water injection
stages
Reservoir had an
aquifer, and we are
planning water
injection
Well Producing too
much water –
increases costs
to process and
utilize
Scale
Installation of
ICDs to isolate
high water inflow
zones
Scale Since sea water used
for injection the
scale occurrence is
possible
Tubing,
riser,
pipeline
Decreased flow Appropriate access
to the wellbore for
maintenance
(chemical injection
sub with control
lines
Gas Slugs As from well model
analysis gas slug
occurs with the
higher pressure drop
between well head
and reservoir
Tubing Increased
pressure in the
tubing (burst
potential)
If goes through
ESP –
overheating of
the ESP
Selection of proper
tubing diameter
ESP with AGH
device
Gaslift as form of
Artificial lift
Gas breakthrough As the gas is
planned to be
injected there is a
chance of gas
breakthrough
Completion Increase of
processing
costs, reduced
recovery of oil
ESP
overheating
Installation of ICD
Backpressure Since we have 6
wells flowing into
the platform the
wellhead pressure
difference is
possible which will
Well head Decreased flow
from individual
wells
Install the
production control
chokes

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