Field Development Plan

Field Development Project (G11DP)

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Field Development Project (G11DP) Report

20th

JUNE 2012

Team X:

Balzarelli, Enrico

Chayeenate, Kanpich

Ilchibayeva, Aigul

O’Neill, Adrian

Otumudia, Ephraim

Wang, Le

Weeramethachai, Deephrom

MSc Petroleum Engineering,

Institute of Petroleum Engineering

Heriot-Watt University


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Table of Contents

LIST OF FIGURES ...................................................................................................... iv

LIST OF TABLES ....................................................................................................... vi

LIST OF ABBREVIATIONS ....................................................................................... vii

1 EXECUTIVE SUMMARY ................................................................................... 1

2 TECHNICAL SUMMARY ................................................................................... 3

2.1 Structural Configuration ..................................................................................... 3

2.2 Formation Evaluation ......................................................................................... 4

2.3 HYDROCARBONS IN PLACE ........................................................................... 6

2.4 Reservoir Engineering ....................................................................................... 7

2.5 Field Development Plan ..................................................................................... 9

2.6 Drilling ............................................................................................................. 11

2.7 Production ....................................................................................................... 12

2.8 Surface Facilities ............................................................................................. 13

2.9 Economics ....................................................................................................... 14

3 FIELD DESCRIPTION ..................................................................................... 16

3.1 STRUCTURAL CONFIGURATION .................................................................. 16

3.2 GEOLOGY AND RESERVOIR DESCRIPTION ............................................... 18

3.2.1 Stratigraphy and Lithology ............................................................................... 18

3.2.2 Seal ................................................................................................................. 19

3.2.3 Core Observations ........................................................................................... 20

3.2.4 Depositional Environment ................................................................................ 21

3.2.5 Geostatistical Reservoir Characterisation ........................................................ 21

3.2.6 Lorenz plot ....................................................................................................... 22

3.3 FORMATION EVALUATION ............................................................................ 24

3.3.1 Petrophysical Evaluation .................................................................................. 24

3.3.2 Repeat Formation Tester ................................................................................. 29

3.4 RESERVOIR FLUID PROPERTIES................................................................. 31

3.5 SPECIAL CORE ANALYSIS ............................................................................ 33

3.6 HYDROCARBONS IN PLACE ......................................................................... 37

3.6.1 Deterministic Reserves .................................................................................... 37

3.6.2 Probabilistic Reserves ..................................................................................... 38

3.7 WELL PERFORMANCE .................................................................................. 39

3.7.1 Well Test Analysis ........................................................................................... 39

3.7.2 Material Balance Analysis ................................................................................ 40


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3.8 RESERVOIR MODELLING APPROACH ......................................................... 44

3.8.1 Static Model ..................................................................................................... 45

3.8.2 Dynamic Model ................................................................................................ 48

4 DEVELOPMENT AND MANAGEMENT PLAN................................................ 61

4.1 DEVELOPMENT PLAN, RESERVES AND PRODUCTION PROFILES ........... 61

4.1.1 Development Plan ........................................................................................... 61

4.1.2 Reserves ......................................................................................................... 62

4.1.3 Production Profile ............................................................................................ 62

4.2 DRILLING ........................................................................................................ 63

4.2.1 Drilling Facilities ............................................................................................... 63

4.2.2 Well Planning ................................................................................................... 64

4.3 PRODUCTION TECHNOLOGY ....................................................................... 70

4.4 PRODUCTION AND PROCESS FACILITIES .................................................. 75

4.4.1 FPSO with subsea wells .................................................................................. 76

4.4.2 Topsides Facilities ........................................................................................... 77

4.4.3 Transportation ................................................................................................. 78

4.5 PROJECT PLANNING ..................................................................................... 79

4.6 ENVIRONMENTAL IMPACT AND ABATEMENT ............................................. 80

4.7 ABANDONMENT ............................................................................................. 81

4.8 ECONOMICS AND COMMERCIAL CONSIDERATIONS ................................ 81

4.8.1 Company Corporate Profile ............................................................................. 81

4.8.2 Assumptions for Cash Flow Modelling ............................................................. 82

4.8.3 Fiscal Regime .................................................................................................. 83

4.8.4 Sensitivity Analysis .......................................................................................... 84

4.8.5 Alternative Development Plans ........................................................................ 86

4.8.6 Commercial Awareness ................................................................................... 88

5 REFERENCES ................................................................................................ 90

6 APPENDICES ................................................................................................. 92

6.1 APPENDIX A – GEOLOGICAL PART .............................................................. 92

6.1.1 APPENDIX A1 – Petrophysical Summary of Six Appraisal Wells ..................... 92

6.1.2 APPENDIX A2 – Composite Logs of Six Appraisal Wells ................................. 93

6.2 APPENDIX B – RESERVOIR ENGINERING PART ......................................... 99

6.2.1 APPENDIX B1 – Special Core Analysis Summary of Core Plugs from Wells X1, X4 and X5 ............................................................................................................. 99

6.2.2 APPENDIX B2 – Variations of inputs used to calculate STOIIP in each zone 107

6.2.3 APPENDIX B3 – Probabilistic Determination of Reserves ............................. 109


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6.2.4 APPENDIX B4 – Sensitivity Analysis of Reservoir Simulation ........................ 110

6.3 APPENDIX C – DRILLING PART .................................................................. 111

6.3.1 APPENDIX C1- Pressure Distribution ............................................................ 111

6.3.2 APPENDIX C2 – Fracture Pressure Spreadsheet Calculation ....................... 111

6.3.3 APPENDIX C3 – Casing Setting Depth Calculation ....................................... 114

6.3.4 APPENDIX C4 – Well Schematic Design and Drilling Section Lithology ........ 117

6.3.5 APPENDIX C5 – Cement Calculation Example ............................................. 119

6.3.6 APPENDIX C6-Directional Drilling Well Location and Trajectory .................... 122

Deviated Well ........................................................................................................... 122

6.3.7 APPENDIX C8 – Casing Design Calculation Example (Adams, 1985) .......... 124

6.3.8 APPENDIX C9 – Drillstring Design Calculation .............................................. 129

6.4 APPENDIX D – PRODUCTION TECHNOLOGY PART ................................. 133

6.4.1 APPENDIX D1 – Tubing Design Calculation Example ................................... 133

6.4.2 APPENDIX D2 –Pipesim Simulation Diagram ................................................ 134

6.4.3 APPENDIX D3 – Wellflo Sensitivity Analyses ................................................ 135

6.4.4 APPENDIX D4 –Gas Lift Design .................................................................... 137

6.5 APPENDIX E – ECONOMIC PART ............................................................... 139


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LIST OF FIGURES

Figure 2.1: Top structure map ...................................................................................... 3

Figure 2.2: Cross-section in the SW-NE direction ........................................................ 4

Figure 2.3: Proposed locations of producers and injectors for the base case production strategy ............................................................................................................. 8

Figure 2.4: Production profile of the X-field with a two year build up period ............... 11

Figure 3.1: Top structure map .................................................................................... 16

Figure 3.2: Interpreted 2D seismic reflection line ....................................................... 17

Figure 3.3: Cross-section in the SW-NE direction ...................................................... 18

Figure 3.4: Gamma ray, density and sonic logs to illustrate the sharp sequence of lithologies of turbidite sandstone in well X1 ..................................................... 19

Figure 3.5: Core photograph from well X5 ................................................................. 20

Figure 3.6: Unordered Lorenz plot ............................................................................. 23

Figure 3.7: Ordered Lorenz plot ................................................................................. 23

Figure 3.8: Correlation between density porosity and core porosity for well X1 .......... 26

Figure 3.9: Pickett Plot for Rw in well X1 ................................................................... 27

Figure 3.10: Poro-perm correlation for well X1 ........................................................... 28

Figure 3.11: RFT Pressure Plot of X Field ................................................................. 30

Figure 3.12: Mercury-Air Capillary Pressure Curve of Well X5 ................................... 34

Figure 3.13: Leverett J Function Curve of Well X5 ..................................................... 36

Figure 3.14: Modified Leverett J Function Curve of Well X5 ....................................... 36

Figure 3.15: Energy plot of the northern tank ............................................................. 41

Figure 3.16: Energy Plot of the Southern Tank .......................................................... 42

Figure 3.17: Analytical Method for OOIP Estimation of Northern Tank ....................... 42

Figure 3.18: Analytical Method for OOIP Estimation of Southern Tank ...................... 43

Figure 3.19: Production profile using material balance simulation .............................. 44

Figure 3.20: Illustration of the top of the reservoir, indicating the two fault locations used in the model ........................................................................................................ 46

Figure 3.21: Permeability distribution on the fine grid model ...................................... 47

Figure 3.22: Permeability distribution on the coarse grid model ................................. 47

Figure 3.23: Fluid Property of Live Oil (PVTO) ........................................................... 50

Figure 3.24: Relationship between total recoverable reserves and peak oil production from Central North Sea Fields ................................................................................. 53

Figure 3.25: Proposed locations of producers and injectors for the base case production strategy ........................................................................................................... 55


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Figure 3.26: Base Case Production Profile of X field .................................................. 56

Figure 4.1: Production profile for the base case (with build-up period) ....................... 63

Figure 4.2: Drilling Time Estimation. (T.W, 1992) ....................................................... 67

Figure 4.3: Completion schematic. (Davies, 2011) ..................................................... 71

Figure 4.4: Gas Lift Performance ............................................................................... 74

Figure 4.5: Water/oil/gas process scheme for the FPSO’s topside facilities ............... 78

Figure 4.6: Spider diagram indicating the most important uncertainties when calculating NPV ................................................................................................................ 85

Figure 4.7: Variation of NPV due to varying oil price from base case ($80/bbl) .......... 85

Figure 4.8: Variation of NPV due to varying oil price with a linear relationship between oil price and FPSO cost ....................................................................................... 86


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LIST OF TABLES

Table 2.1: Oil-water contacts in the X-field appraisal wells ........................................... 5

Table 2.2: Deterministic range of STOIIP and reserves ................................................ 6

Table 2.3: Probabilistic Definition of P10, P50 and P90 ................................................ 6

Table 2.4: Base case economic parameters for the 135,000 bopd oil processing capable FPSO .............................................................................................................. 15

Table 3.1: Statistical data for core horizontal permeability (mD) ................................. 22

Table 3.2: Statistical data for core porosity (%) .......................................................... 22

Table 3.3: Sand interval (TVDSS/ft) ........................................................................... 24

Table 3.4: Determined oil-water contacts (OWC) ....................................................... 29

Table 3.5: Summary of sampling conditions and reservoir fluid properties of wells X1 and X2 using PVT analysis. ................................................................................... 31

Table 3.6: Composition and properties of reservoir fluid from wells X1 and X2. .......... 32

Table 3.7: Two-phase interfacial tension and contact angle (Best, 2002) ................... 35

Table 3.8: Deterministic range of STOIIP and reserves. ............................................. 38

Table 3.9: Probabilistic Definition of P10, P50 and P90 .............................................. 38

Table 3.10: Data achieved from well test interpretation .............................................. 39

Table 3.11: kv/kh ratio for each zone determined from core data of wells X1 and X5 . 49

Table 3.12: Rock type curve assigned for each zone ................................................. 50

Table 3.13: Pressure vs. Depth (PRVD) of X field ...................................................... 51

Table 3.14: Dissolved gas concentration vs. Depth (RSVD) of X field ........................ 51

Table 3.15: Sensitivity analysis on number and type of wells to justify base case production strategy (Cases 1 – 5) ..................................................................................... 55

Table 4.1:Possible Risks and Uncertainties in Drilling Program .................................. 69

Table 4.2: Well Performance Analysis. ....................................................................... 72

Table 4.3: FPSO specifications .................................................................................. 77

Table 4.4: Estimated abandonment and Opex costs of FPSOs of similar fields and from Que$tor (Oberstoetter, 2011) ......................................................................... 83

Table 4.5: Surplus royalty rate applied to companies in Greenland ............................ 84

Table 4.6: Economic analysis of different development types .................................... 87


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LIST OF ABBREVIATIONS

BHA Bottomhole Assembly

BMP Bureau of Minerals and Petroleum

BOP Blow Out Preventer

bopd Barrels of Oil per Day

CAPEX Capital Expenditure

CCE Constant Composition Expansion

CV Coefficient of Variation

DNCF Discounted Net Cash Flow

DST Drill Stem Test

FPSO Floating Production, Storage and Offloading

GBS Gravity Based Structure

GOR Gas Oil Ratio

GR Gamma Ray

HCIIP Hydrocarbons Initially In Place

II Injectivity Index

IRR Internal Rate of Return

JNCC Joint Nature Conservation Committee

kh Horizontal Permeability

Kh Permeability-Thickness

kv Vertical Permeability

LNG Liquefied Natural Gas

MCO Maximum Capital Outlay

MD Measured Depth

MMO Marine Mammal Observer

MMSTB Million Stock Tank Barrels

MWD Measurement While Drilling

NCF Net Cash Flow

NPV Net Present Value

NPVI Net Present Value Index

NTG Net to Gross Ratio

Ø Porosity

OBM Oil Based Mud


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OPEP Oil Pollution Emergency Plan

OPEX Operational Expenditure

OWC Oil Water Contact

PAM Passive Acoustic Monitoring

PDC Polycrystalline Diamond Cutters

PI Productivity Index

PVT Pressure Volume Temperature

RCAL Routine Core Analysis

RCB Roller Cone Bit

RFT Repeated Formation Tester

ROP Rate Of Penetration

RSS Rotary Steerable System

Rt True Resistivity

Rw Water Resistivity

S Skin Factor

SCAL Special Core Analysis

SD Standard Deviation

STOIIP Stock Tank Oil Initially In Place

Sw Water Saturation

TCS Terminal Cash Surplus

TGB Temporary Guide Base

TVDSS True vertical Depth Subsea

USD The United States Dollar

Vsh Shale Volume

WAG Water Alternate Gas

WBM Water Based Mud

WOB Weight On Bit


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1 EXECUTIVE SUMMARY

The potential development of an oilfield off the southern coast of Greenland has been outlined

in this field development plan. The field is located in 120 metres of water depth in block

2008/13. Six appraisal wells have already been drilled, giving fluid and reservoir information

about the field. This, along with some other sources of data, has been used to produce a devel-

opment plan to economically produce the hydrocarbons.

This field is an anticline reservoir, compromising mostly sandstone and a STOIIP of approxi-

mately 860 MMSTB of relatively light oil (40° API). The reservoir consists of five sand layers

underlying a seal, comprised of chalk (in the north and east of the field) and shale (in the south

and west of the field).

Evaluation of the data from the appraisal wells has allowed Mungo Energy to estimate the re-

coverable reserves. Deterministic and probabilistic methods were used to predict the P50 sce-

nario. Both methods provide very similar results of 470 MMSTB. The greatest uncertainty in this

calculation is the gross rock volume. Therefore, it is suggested that a 3D seismic survey be car-

ried out on the field to check that the gross rock volume is correct and identify any further faults

or compartments not found initially, which may alter reserves.

It has been decided that an FPSO, with an oil capacity of 150,000 bopd, will be purchased to

produce from the field and contain all the other surface facilities. This will include the ability to

handle 300 MMscf/day of gas and have the capability for reinjection back into the reservoir.

Moreover, it was seen that the FPSO will leave a smaller impact on the environment than the

available alternatives, vital because it is important to leave a positive legacy in Greenland.

The drilling phase will begin after the end of the development phase in 2013 and will be carried

out using semi-submersible drilling rig. The expected duration for drilling the seven producers,

three water injectors and two gas injectors is 430 days. Consequently, the first oil is anticipated

in Q1 2015, before the plateau production is reached two years later in 2017, lasting until 2021


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before production decline. The main limiting factor of the recovery factor of the field is the gas

production due to gas cusping into the production wells. If any viable alternatives become feasi-

ble then the recovery of the field can be significantly enhanced.

Pressure maintenance has to be adopted because of the expected weak aquifer support. Water

injection will start at the end of the second year of production to gain more information about the

aquifer strength. Whereas, gas injection will commence from first oil since a gas market is local

end exporting is not considered economical. The produced oil will be processed and stored on-

board the FPSO and exported by shuttle tankers to the Newfoundland transshipment terminal

located on the northeast edge of Placentia Bay, approximately 1700 km far.

As inceasing water cuts occur some sand production is to be expected. Therefore, expandable

screens will be installed when this issue becomes apparent, although it is not expected for a

number of years after first oil. Moreover, as the production starts to decline gas lift will be

installed in the wells to maintain the productivity of the wells.

Economic analysis of the field was performed using a base case of $80/bbl and a discount rate

of 10% to calculate NPV. Making a vast number of educated assumptions, the development

plan to be used was economically evaluated. It was found that purchasing an FPSO with a

150,000 bbl/d oil processing capacity provided the highest NPV (USD 1.0 billion) and the best

balance between project payback (nine years) and maximum capital outlay (USD 4,050 million),

with an IRR of 14%. By evaluating the variation of oil price and, its relationship with the FPSO

cost, it was found that the minimum oil price to ensure a positive NPV is $39/bbl. The project will

fit in well with the strategic focus of Mungo Energy since they focus on emerging plays, light oil

and allows them to spread their geographical risk through diversification. However, since they

are currently embarking upon a large-scale investment process it may not be the best time to

start a new project with such a large MCO. Therefore, it is advised to look into selling part of the

project to other companies to reduce the intial project outlay and spread the risk of working in

the previously undeveloped Greenland.


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2 TECHNICAL SUMMARY

The reservoir that is to be evaluated is situated approximately 70 km off the south coast of

Greenland in block 2008/13. The water depth is 120m and six appraisal wells data have

been used to evaluate the field.

2.1 Structural Configuration

An anticline structure illustrated in Figure 2.1 is a massive sandstone reservoir of Jurassic age.

It is located 9,900 feet subsea. According to the data from six well logs and core data the reser-

voir was divided into two sands and five layers. The Main sand is laterally continuous, divided

into 4 layers of different permeabilities. While the fifth layer of turbidite origin is the Ribble sand.

Moreover, this reservoir is sealed by chalk and shale layers in the northeast and southwest di-

rections respectively.

Figure 2.1: Top structure map


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RFT data and well test analysis indicated two discontinuities away from wells X5 and X6. This

was suspected to be two sealing faults, which separate these wells from a northern compart-

ment. The oil-water contact (OWC) in the northern compartment is 280 feet higher according to

RFT and well logs interpretation. The field’s cross section on a SW-NE direction through wells

X1, X2 and X5 is illustrated on Figure 2.2.

Figure 2.2: Cross-section in the SW-NE direction

The coarsening-upward trend observed on density logs as well as bioturbation seen on core

samples are signs of a shallow marine environment of sedimental deposition.

2.2 Formation Evaluation

In the X-field, six wells wireline logs have been evaluated. The oil bearing zone, porosity, water

saturation, net to gross ratio and permeability were then interpreted. The porosity (Ø) model

has been determined using the density logs. Water saturation (Sw) was calculated using

Archie‘s equation.

Shale volume (Vsh) model has been interpreted using the neutron-density or density-sonic

methods because gamma ray log is likely to be influenced by mud or radioactive elements in

the formation, which needs to be further researched. Net to gross (NTG) ratio model can be

calculated using the Vsh, Sw and Ø. Subsequently, cut-off values were set for shale volume (<


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0.8), water saturation (< 0.7) and porosity (> 0.1). Any values out with these will not contribute

to NTG.

Core data was only supplied for wells X1, X4 and X5. Core porosity should be corrected from

surface condition to in-situ conditions. Permeability can be calculated using porosity-

permeability relationship, generated by crossplots before correcting core permeability at surface

to in-situ condition.

The wells X1, X2, X3 and X4 have five layers, whilst the wells X5 and X6 have only four layers.

This result came from composite logs of all six appraisal wells. The OWC of each well is dem-

onstrated in Table 2.1.

Table 2.1: Oil-water contacts in the X-field appraisal wells

Wells X1, X2, X3, X4 Wells X5, X6

Low case (ft TVDSS)

Base case (ft TVDSS)

High case (ft TVDSS)

Low case (ft TVDSS)



10810 10840 10860 10480 10500 10550

It is clear that wells X5 and X6 have a higher OWC than the other wells. The reason for this will

be investigated using other methods.

The Repeat Formation Tester (RFT) acquired from appraisal wells indicates the possibility of a

perched water contact in the X-field. A deep contact is seen in well X3 at 10,840 feet subsea

and a shallow one is seen in well X5 at 10,560 feet subsea. This 300 feet difference of fluid con-

tact is also confirmed by welltest interpretation where there is a faulted system separating wells

X5 and X6 from the rest. RFT illustrates the common oil gradient with different positioned water

gradients. Therefore, only one fluid property can be assumed to be the same for oil reservoirs

between reservoir compartments. From PVT data obtained from wells X1 and X2 the reservoir

is undersaturated with initial pressure of 3,900 psi above bubble point pressure. The oil quality

is good (40° API) with very low concentration of impurities. Most of the sand intervals contain

very high permeability as reflected by very high well productivity indexes (average PI of 50


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b/d/psi) in past welltests. Moreover, it also has a water/oil mobility ratio less than 1.0, which is

favourable for water/oil displacement process.

2.3 HYDROCARBONS IN PLACE

A range of values of petrophysical parameters and fluid properties were used to estimate a pos-

sible range of values for the hydrocarbons initially in place (HCIIP) for each of the five zones in

the reservoir. These were then summed to find a range of totals for the entire reservoir. Table

2.2 illustrates the range of stock tank oil initially in place (STOIIP) and reserves for each zone

and then finally for the complete reservoir.

Table 2.2: Deterministic range of STOIIP and reserves

STOIIP (MMbbls) Reserves (MMbbls)

Zone Minimum Most Likely Maximum Minimum Most Likely Maximum

1 59 109 152 27 60 106

2 141 274 380 64 151 266

3 30 93 149 13 51 104

4 173 278 346 78 153 242

5 46 108 232 21 60 163

Total 449 862 1259 202 474 881

Using the variations of the petrophysical properties discussed above a probabilistic calculation

of the hydrocarbons was then performed to determine the P10, P50 and P90 scenarios, as indi-

cated in Table 2.3.

Table 2.3: Probabilistic Definition of P10, P50 and P90

STOIIP (MMbbls) Reserves (MMbbls)

P10 P50 P90 P10 P50 P90

737 860 995 389 460 536

It was noted that the parameter which created the most uncertainty in the calculation of re-

serves is the gross rock volume of each zone. Therefore, it is suggested that a 3D seismic sur-

vey be carried out on the field to check that the gross rock volume of each layer is correct and

identify any further faults or compartments not found initially.


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2.4 Reservoir Engineering

The field started production in February 1982. However, about 1,100 psi of reservoir pressure

drop was experienced during the first year of production. The material balance analysis can be

performed based on available production data and static bottomhole pressure survey from wells

X3 and X5 to determine the reservoir drive mechanism and STOIIP of each reservoir compart-

ment. The preliminary results show that the reservoir is dominated by solution gas drive with

very limited aquifer support. The estimated STOIIP of the northern and southern compartments

are 174 and 734 MMSTB, respectively. The quick simulation run under pressure maintenance

by gas and water injections gives a recovery factor of 51%.

Two static geological models were constructed in the Petrel software: a fine and a coarse grid

model. The fine model has a grid size of 50x50 metres and a total of 500,000 grids

(160x125x25 cells). Whereas, the coarse model of 100x100 metre grids, which was upscaled to

minimise simulation time, consists of 126,000 grids (80x63x25 cells). The main uncertainty dur-

ing the model creation is the fault orientation and position.

To optimise the simulation run-time without compromising on the numerical dispersion effect,

both the structure and properties of the fine-scaled geological model are scaled up by a factor of

four. This results in the grid dimensions (X-Y-Z) of 80x63x25 with a total of 126,000 cells in the

dynamic model. The rock properties (i.e. porosity, permeability and NTG) are directly obtained

upscaled properties from the static model. The single black oil PVT table obtained from the

downhole sample of well X1 is used to model fluid properties throughout the reservoir. Up to ten

tables of three-phase relative permeability and capillary pressure data are generated from

SCAL data from wells X1, X4 and X5 and assigned to each reservoir rock type for water satura-

tion modelling. After initialising the model with two sets of fluid contacts (10,840 and 10,560 ft

ss), the total STOIIP in the dynamic model is determined to be 898 MMSTB, which is close to

volume in the static model (842 MMSTB).


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Once the dynamic model has been set up, the production strategy can be developed to optimise

the field recovery factor. The oil producers are placed at the crest of structure and produced

from zones two to four. Due to lack of aquifer support, the peripheral water injectors are planned

on the third year of production to inject seawater to zone five below the OWC for maintaining

reservoir pressure and sweeping oil to producers. As a result of the lack of gas market and

regulation about gas flaring in Greenland, gas injectors are required from the beginning of pro-

duction to reinject 85% of produced gas back into zone one for underground gas storage and

pressure maintenance purposes.

To establish the base case production strategy of the X-field, multiple development scenarios

involving various numbers of wells, their position, and completion types were carried out. From

the NPV estimations, the base case scenario is based on a 20 year production profile at the

plateau rate of 135,000 bopd with seven oil producers, five water injectors and two gas injec-

tors, providing an oil recovery of 53.1%. Figure 3.1 illustrates the proposed locations of produc-

ers and injectors for the base case production strategy.

Figure 2.3: Proposed locations of producers and injectors for the base case production strategy


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The sensitivity analysis on various uncertain input parameters of the dynamic model that can

affect the field recovery factor were then investigated. It is found that pressure maintenance, the

kv/kh ratio and modelled permeability are the three parameters that have the greatest impact on

recovery factor of the X-field. Moreover, the polymer flooding method is also not recommended

for the X-field to improve water flooding efficiency since the water/oil mobility ratio is already

less than one. It should be noted that there are still a number of remaining uncertainties in the

dynamic model that require further investigation, including thermal fracturing in the water injec-

tion process, gas-oil miscibility effect in gas reinjection process, other production improvement

methods like WAG, miscible gas flooding, chemical flooding, etc.

2.5 Field Development Plan

Before the commencement of drilling it has been decided that a 3D seismic survey is to be car-

ried out so that understanding of the field can be significantly enhanced. This will allow for the

identification of further faults and to confirm the location of known ones.

The field will be developed first by drilling seven production wells, the minimum needed to reach

the maximum oil processing capacity of the chosen production facilities of 135,000 bopd. Since

there is no economical method of exporting the gas, due to the remoteness of the field and gas

flaring is not a choice, the produced gas must be treated and then reinjected back into the res-

ervoir. Therefore, two gas injection wells have been planned and must be operational from first

oil production (in 2015).

In order to gain invaluable data about the field it was decided that the reservoir pressure should

be allowed to decline for the first two years. This will be long enough to determine the potential

drive mechanisms and strength of the aquifer (one of the main uncertainties of the field), yet not

too long to ensure an undersaturated reservoir remains. This was deemed reasonable because

we are approximately 3,900 psi above the bubble point pressure.


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The second phase of the drilling programme involves the drilling of five water injection wells two

years after the start of production (2017). This will lead to pressure support, to enhance the re-

covery from the field.

Once these phases have been completed it is expected that more wells or workovers will be

needed to further enhance production. Vast amounts of information will be known, allowing full

evaluation of field performance to be performed.

Through the use of these fourteen initial wells the production profile from the X-field has been

estimated. It was expected that it would take three years to perform the 3D seismic survey and

drilling operations before oil production starts (2015). Oil production would then build up slowly

to the plateau production rate of 135,000 after two more years (2017). Figure 2.4 illustrates the

production profile that is envisioned. A plateau production of four years (2017 – 2021) is ex-

pected before gas cusping to the wells causes the maximum gas processing capacity to be

reached and the liquid production from wells must be cut back. This gas cusping is the main

limiting factor in the recovery of the oil reserves. If an economic alternative to reinjection is

found then it is expected that the recovery factor will increase dramatically.


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Figure 2.4: Production profile of the X-field with a two year build up period

2.6 Drilling

The drilling program starts with formation pressure analysis. The normal pressure gradient of

formation (0.47 psi/ft) is obtained from well test data, which is only slightly different from that of

the North Sea (0.45 psi/ft). The fracture gradient curve is constructed using Matthew and Kelly’s

and Ben Eaton’s equations. The results show that the fracture gradient calculated from Ben

Eaton is lower than that of Matthew and Kelly. Thus, to be conservative the Ben Eaton fracture

gradient is applied. The well is design using a bottom to top approach and a target production

rate of 135,000 bopd, starting from a 7“ liner at 11,000 ft TVD, 9 5/8“ intermediate casing at

8,400 ft TVD, 13 3/8“ surface casing at 3,670 ft TVD and 18 5/8“ conductor pipe. Casing selec-

tion is based on determining the grade and weight needed to withstand any possible loads.

The mud program is established according to mud weight used in appraisal wells. No overpres-

sure zones are observed both from appraisal well’s mud program and log data. However, if

there is an abnormal pressure zone, it will be detected using MWD technology. To drill the sec-

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

2016 2018 2020 2022 2024 2026 2028 2030 2032 2034

0

40

00

08

00

00

12

00

00

Liq

uid

Flo

wra

te,

[ST

B/d

]

0

1E

+8

2E

+8

3E

+8

4E

+8

Liq

uid

Pro

du

ctio

n V

olu

me

, [ST

B]

Symbol legend

Oil production rate Oil production cumulative

Base Case Production Profile of X Field (with Build-up Period)


Page | 12

tion above reservoir, water based mud (WBM) will be employed and then oil based mud (OBM)

will be used throughout the reservoir section, to minimise formation damage.

After investigating the well completion diagram from the appraisal well, multistage cementing is

applied for intermediate casing to eliminate extreme hydrostatic pressures and reduce cost. For

the other casings, single-stage cementing is used. API class A cement is selected because it is

widely available and its performance can be easily modified by adding additives.

Deviated wells with 38.2° deviation will be drilled from a semi-submersible drilling rig using a

rotary steerable system (RSS) combined with an MWD sub to ensure that the well path follows

the plan. Roller cone bits are planned to use in soft formations with WBM. Then for the last two

layers, which are shale and sandstone, a PDC bit is selected together with OBM. Due to the

unavailability of off-set well data, drilling time is estimated by published data based on the North

Sea area and calculated to be approximately 30 days per well. Drillpipe design is based on

burst, collapse and tension resistance. The calculation shows a 16.6-lb/ft, 4 ½“ drillpipe is suit-

bale. A proper design of BHA will keep the pipe in tension and eliminate drilling problems that

might occur during drilling operations.

2.7 Production

The X-field will be produced using seven producers, five water injectors and three gas injectors.

The producers are deviated wells with approximately 38° of deviation and they are completed

using wellhead assemblies on individual guide bases, steel templates structures and are tied

back to a production manifold. Using a riser the produced fluids will be transferred to the FPSO

for processing.

The wells after having been cased and cemented will be completed and the solution proposed

is a tubing completion with annular packer. Subsequently, the production casing will be perfo-

rated in the pay interval. The main motivation behind this choice is that the geological uncertain-

ties forced the production engineer to adopt a flexible and modifiable solution. The uncertainties


Page | 13

are mainly related to the possibility of water coning and gas cusping for when a plug off or se-

lected intervals is needed.

The wellhead type selected is a spool type and this also deal with the uncertainties about the

future possibility of having workovers and recompletions.

The wellhead pressure required to transport the produced fluids from down hole to the FPSO

considering the pressure losses along the flow lines has been calculated. With the FPSO’s op-

erating pressure set at 200 psi the minimum well head pressure that must been sustained is

350 psi.

Since the expected production rate for the whole field is relatively high, artificial lift will not be

needed in the early phase of the project. For a reservoir pressure of below 2,500 psi artificial lift

will have to be considered. The best results are obtained with the use of gas lift and the gas lift

design shows that the deepest unloading valve will be set at approximately 7,000 feet TVD.

A sensitivity study was carried out to identify the key parameters which influence the production

flow rate. The rate depends primarily on reservoir permeability, water cut, GOR, skin, tubing

size and wellhead pressure. These parameters control the flow rate by controlling both the in-

flow and the outflow performances. The parameter that mostly affects the flow rate are the tub-

ing internal diameter, with its maximum at 5.044”, and the reservoir pressure, that if maintained

at 4,000 psi will give the target rate.

2.8 Surface Facilities

Greenland is subjected to sea-ice, icebergs and harsh environmental conditions. Therefore, a

drilling rig and platform for production from the X-field should be designed to withstand or avoid

the impact of these conditions.

After considering several options for a platform, it was found that the gravity based structure

(GBS) and an FPSO will be suitable to operate in Greenland, taking account of the environ-

mental conditions. However, these GBS and FPSO need to be designed specifically for ice-


Page | 14

bergs environment. They are only a few kind of these platforms in the world, including the

Hibernia field GBS and the Terra Nova FPSO. These platforms have been analysed as a possi-

ble means of development of the X-field and it was seen from the cash flow model that the pur-

chase of Hibernia field GBS will results in a negative NPV for this project. This is because the

size of the reservoir is smaller than the Hibernia field. However, the costs of the ice-resistant

Terra Nova FPSO gave a positive NPV which justifies the Terra Nova FPSO. Hence, the Terra

Nova FPSO was selected as the best suitable platform.

A jack up drilling rig or a semi-submersible rig was considered as a possible means of drilling in

Greenland. The semi-submersible rig was selected over the jack up due to its stability against

wave action and high capability to move off location when there is a threat of an iceberg that will

damage the rig. Although the jack up rig is less expensive, it can only be used when the sea is

ice-free resulting in seasonal operation. On the other hand, the semi-submersible allows an all-

year round drilling operation with or without an ice-free sea.

2.9 Economics

The economics of the field is one of the most important aspects of the development plan. It is

vital to consider how the project will benefit the company and its shareholders. The main eco-

nomics consideration was to choose between different development plans: a gravity based

structure (GBS); and two different capacity FPSOs. It was found that the FPSO with 135,000

bopd oil processing capacity was more beneficial to Mungo Energy than the 200,000 bopd

FPSO because it provided 30% more NPV to the company, a total of USD 1,005 million. More-

over, the maximum capital outlay (MCO) is significantly less for this development option than

the two alternatives. The GBS option was ruled out because they initial Capex was so high

(USD 10 billion) such that a negative NPV was resulted.

However, it has been suggested that the company should create a joint venture with more oil

companies, other than the 12.5% equity stake with Nunaoil. This has been suggested because


Page | 15

Mungo Energy is currently in the process of a large-scale investment process and capital is

somewhat limited. Therefore, to reduce the MCO from USD 4.05 billion to below USD 1 billion

an equity stake of 80% of the project needs to be sold to other companies. This provides the

major advantage that a significant NPV is still achieved and experience in the vast potential of

Greenland is attained, with Mungo Energy still in prime position to take advantage of these re-

sources. The main economic parameters of the X-field project are illustrated in Table 2.4.

Table 2.4: Base case economic parameters for the 135,000 bopd oil processing capable FPSO

NPV MCO IRR Payback period

USD millions USD millions % Years

1,008 4,050 14 9

In order to evaluate the field and find the oil price that is required to ensure the project remains

economically profitable, sensitivities were performed on numerous parameters. By varying just

the oil price of the project it was seen that a minimum of price of $68/bbl was required to

achieve a positive NPV. However, it was noted that if the oil price was to drop it is evident that

the price to construct the FPSO cost would drop accordingly. Assuming a linear relationship

between the two it was found that an oil price of $39/bbl was needed for the NPV to become

positive in this case. Clearly, this is a much more accurate interpretation, resulting in a much

safer project for the company.

The X-field fits in extremely well with the strategic focus of Mungo Energy, leading to more

value to its shareholders. Since Mungo Energy has 88% of its NPV in Africa it is a good idea for

the company to attempt some diversification to spread out its geographical risk. Moreover, the

company has a strong tradition in creating value in numerous countries, especially in emerging

plays. Both of these fit perfectly with the characterisation of Greenland. However, it may be im-

portant to consider that Mungo Energy has no experience in Greenland and, in fact, there has

been no local production at all, indicating that there is a significant capital risk required to begin

operations and there is no previous knowledge to learn from.


Page | 16

3 FIELD DESCRIPTION

3.1 STRUCTURAL CONFIGURATION

The field, illustrated in Figure 3.1, is an anticline structure which dips steeply on the western

flank. The crest of the reservoir is at 9900 feet subsea. The dimensions of the field are approxi-

mately 16,400 x 24,600 feet, with an area of 9,261 acres. The reservoir is from the Jurassic pe-

riod and divided into two segments: the northern compartment and main section, separated by

what is suspected to be a fault.

Figure 3.1: Top structure map

During appraisal a 2D seismic survey was conducted running from the NNW-SSE, demon-

strated by the solid straight line in Figure 3.1, in order to attempt to understand the subsurface

structure and geometry. Although the quality of the seismic map is relatively poor, the anticline

shape of the reservoir is distinguishable (the dashed purple line). Figure 3.2 illustrates the

seismic reflection trace across the well X1. From the seismic map it is clear that the reservoir is

situated on a fault, possibly listric, indicated as the red line. The orange and blue lines on the

map show reservoir limits and indicates its continuity. The shape and dimensions of the top

structure map gives the idea of NW-SE direction of shoreline. The green and dotted-pink lines


Page | 17

are interval of the top chalk seal. The reservoir is more curved than top chalk layer which gives

an idea of an unconformable lying seal.

Figure 3.2: Interpreted 2D seismic reflection line

Log data, together with the seismic map interpretation, gives an idea that the reservoir consists

of two sands: a Ribble and a Main sand. The Main sand is thick and massive, whereas, the

Ribble sand is interbeded with shale.

Although, there is no fault indications on the top structure map, seismic map interpretation, well

test analysis and RFT data all indicate its presence. There are two intersected faults of ap-

proximately 90° which separates the northern compartment from the remaining section. The

presence of fault results in two different OWCs, higher on northern part for 280 ft. Figure 3.3

illustrates the field’s cross-section on a SW-NE direction through wells X1, X2 and X5, as indi-

cated by the dashed straight line on Figure 3.1.


Page | 18

Figure 3.3: Cross-section in the SW-NE direction

3.2 GEOLOGY AND RESERVOIR DESCRIPTION

3.2.1 Stratigraphy and Lithology

The gamma ray (GR) log is usually used to correlate zones. However, the response from the

GR logs is potentially unreliable because radioactive elements in the drilling mud may have af-

fected the results. Therefore, core data, density and sonic logs were used for the correlation

between wells. According to the well log correlation and core data analysis the reservoir is di-

vided into five layers and two different sands: the Main and Ribble sand as discussed above.

The Main sand is laterally continuous, divided into 4 layers of different permeabilities of around

600 feet thick in total. Whereas, the fifth layer, Ribble sand, was interpreted to be turbidite

sandstone.

According to Shanmugam (1997) turbidite sandstones have sharp contacts between lithologies

and beds are commonly 1-10 cm thick and spatially extensive. The sonic, density and GR log

responses in the interval of10160 to 10200 ft TVDSS of well X1 are illustrated in Figure 3.4.

Thin sand layers interbeded with shale can clearly be seen. The lithologies change sharply,

possibly generated during turbidite currents in a deep marine environment. The layer of turbidite


Page | 19

sandstones overlie the Main sand in the SW region. However, it is not seen on the northern part

of the reservoir as it is probably eroded or pinched-out.

The X-field is a massive sandstone reservoir of Jurassic age. Although its permeability ranges

from 0.01 mD to 5,000 mD, the field has good reservoir characteristics. Layers 2 and 4 have

been identified as high permeable zones of up to 5,000 mD.

Figure 3.4: Gamma ray, density and sonic logs to illustrate the sharp sequence of lithologies of

turbidite sandstone in well X1

3.2.2 Seal

The X-field has two seals:

Chalk Seal: In the North and East of the field (wells X3, X4, X5 and X6) – identified from

the extremely low GR log response (i.e. less than 20 GAPI);


Page | 20

Shale Seal: In the South and West of the field (wells X1 and X2) – from the high GR log

response (i.e. more than 90 GAPI).

3.2.3 Core Observations

The core samples for the X-field were taken for wells X1 and X5. Well X1 is in the main seg-

ment, whereas, well X5 is in the northern compartment of the field. Sampling depths are

10422.1–10553 feet and 10921.3–10912.6 feet measured depth (MD) for X1 and X5 respec-

tively.

Figure 3.5: Core photograph from well X5

Core analysis data is divided into two following groups:

Texture:

– Grain size: fine to medium;

– Grain sorting: well sorted;


Page | 21

– Colour: grey to brown;

Sedimentary structures:

– Primary structures:

• Low angle lamination.

– Secondary structures, as indicated in Figure 3.5:

• Bioturbation, illustrated as the dashed green circle;

• Post-depositional dewatering-related deformation (e.g. closed fractures,

slumping, illustrated as the red circle).

3.2.4 Depositional Environment

Depositional environment of the X-field is considered to be in a shallow marine environment for

subsequent reasons:

Coarsening-upward trend is observed from the density log caused by shoreline progra-

dation;

Rock core samples show bioturbation – a sign of marine life;

Laminated sand with interbeded mud is seen on core samples, possibly produced by

storm-waves.

3.2.5 Geostatistical Reservoir Characterisation

Core horizontal permeability and porosity were used to apply geostatistical methods for reser-

voir characterisation. The reservoir is considered to be heterogeneous for the following reasons:

Measures of Central Tendency: Averages for permeability are all quite different from each

other, demonstrated in Table 3.1, indicating a non-homogenous reservoir. However, it has been

noted that the averages for porosity are relatively close to each other, demonstrated in Table

3.2, indicating that porosity is a relatively uniform property.


Page | 22

Table 3.1: Statistical data for core horizontal permeability (mD)

Well X1 Well X4 Well X5

Arithmetical average 733 783 563

Geometric average 211 353 44

Harmonic average 0.7 13.7 0.5

Mode 1,300 1,600 1,500

Median 455 670 69

SD 802 691 789

CV 1.1 0.9 1.4

Measures of Variability: Values of standard deviation (SD) for core horizontal permeability are

close to the mean value, whereas, in homogeneous formations these values should be far from

each other. Coefficient of variation (CV) is an absolute measure of dispersion and a homoge-

nous reservoir will measure CV (permeability) ≤ 0.5. The CV for the wells in field X vary be-

tween 0.9 and 1.4, indicating the reservoir is quite heterogeneous.

Table 3.2: Statistical data for core porosity (%)

Well X1 Well X4 Well X5

Arithmetical average 22.6 24.1 20.9

Geometric average 21.7 23.5 20.0

Harmonic average 20.2 23.6 18.9

Mode 27.1 25.1 26.4

Median 24.3 24.6 21.6

SD 5.6 3.0 5.2

CV 0.2 0.1 0.2

3.2.6 Lorenz plot

A Lorenz plot has been used to analyse the field’s flow and storage capacity. Figure 3.6 illus-

trates the unordered Lorenz plot where points on the plot which deflects from the straight diago-

nal line indicate layering, fracturing and porosity changes. For example, in well X4, it is possible

to indicate five segments (layers): two segments with higher flow capacity (and higher produc-

tion potential); two segments with higher storage capacity (with subsequent lower production

potential); and one segment of similar capacities to flow and storage (Pranter, 1999).


Page | 23

Figure 3.6: Unordered Lorenz plot

As demonstrated in Figure 3.6 wells X1 and X4 are layered in similar way which indicates lat-

eral continuity of zones. However, the zone thicknesses and their capacities may be different.

Whereas, well X5 (located in the northern segment) has less layers and is distinguished by a

thicker zone with significant storage capacity. Although differences between wells are indicated,

a general trend can be represented (Pranter, 1999).

Figure 3.7: Ordered Lorenz plot

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.2 0.4 0.6 0.8 1

Frac

tio

nal

of

tota

l flo

w c

apac

ity

(pe

rmea

bili

ty x

th

ickn

ess)

Fraction of total storage capacity (porosity x thickness)

Unordered Lorenz Plot

X1

X4

X5

diagonal

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.2 0.4 0.6 0.8 1

Frac

tio

n o

f To

tal f

low

cap

acit

y (p

erm

eab

ility

x t

hic

knes

s)

Fraction of total storage capacity (porosity x thickness)

Ordered Lorenz Plot

X1

X4

X5

diagonal


Page | 24

An ordered Lorenz plot is illustrated in Figure 3.7. The reason for this plot is to understand the

significance of the interpreted zones. It is clear that the degree of heterogeneity between wells

X1 and X4 is similar. Whereas, well X5 is more heterogeneous due to its higher deflection from

the straight, diagonal line that indicates a uniform reservoir.

3.3 FORMATION EVALUATION

3.3.1 Petrophysical Evaluation

In this oil field the petrophysical evaluation has been conducted on six exploration wells, each

containing: gamma ray (GR); sonic; calliper; neutron porosity; density and resistivity (long nor-

mal and short normal) log data. The objective of the log interpretation is to determine the follow-

ing parameters:

Oil bearing zone

Porosity

Water saturation

Net to Gross ratio

Permeability

Table 3.3: Sand interval (TVDSS/ft)

X1 X2 X3

Top Bottom Thickness Top Bottom Thickness Top Bottom Thickness

340 1330 990 300 1600 1300 6369 6502 133

1850 2050 200 2100 2660 560 8118 8850 732

6800 9100 2300 2900 6400 3500 8860 8885 25

9180 9600 420 6410 9730 3320 8898 9076 178

9600 9890 290 9750 9950 200 9094 9110 16

10420 11230 810 10200 11600 1400 9326 10940 1614

X4 X5 X6

Top Bottom Thickness Top Bottom Thickness Top Bottom Thickness

5393 5430 37 6214 6402 188 9308 9325 17

6620 6662 42 8114 8212 98 9341 9466 125

8043 8060 17 9298 9312 14 9501 10540 1039

8706 8715 9 9383 9582 199

9134 9151 17

9460 11350 1890


Page | 25

Using the resistivity log and GR log we have been able to identify oil bearing zones and sand

intervals from the surface to the bottom sand. Table 3.3 shows the sand interval (including

shaley sand) for all six wells.

There are many methods to determine porosity (e.g. from core, density log, neutron porosity,

sonic and resistivity log). Since density porosity can be matched best with core porosity, as indi-

cated in Figure 3.88. Here we use density log to determine porosity. It is noticeable that the

core porosity given in software is the porosity measured at surface, it is essential to convert to

in-situ condition according to the hardcopy information. The porosity from density formula is

illustrated in equation 2.1:

bma

shma

2.1

Matrix density, ρma, is from average core data, and shale density, ρsh, has been used as typical

number 2.45g/cc.

The Archie equation, illustrated in equation 2.2, was then used to obtain the water saturation,

Sw. However, before this the true resistivity must be corrected, using a Tornado chart.

t

w

m

n

wR

RaS

, assume a=0.62, m=2.15, n=2 2.2

Ø = Porosity

Rw = Water resistivity

Rt = True resistivity

There are two methods that can be used to get a value for water resistivity, Rw.

The first is to check the water analysis from the data of the water. The given water salin-

ity and borehole temperature can be used to read Rw, using the resistivity of NaCl solu-

tions chart Gen-9.


Page | 26

The second method is to use equation 2.3 to calculate Rw. Where true resistivity, Rt, is

the lowest recorded resistivity from the LLD log in the water zone and Ø is the corre-

sponding porosity. Detail summary of water saturation calculation is shown in APPEN-

DIX A1 – Petrophysical Summary of Six Appraisal Wells.

F

RR t

w , where15.2

62.0

F 2.3

Figure 3.8: Correlation between density porosity and core porosity for well X1

Core porosity and density porosity


Page | 27

Pickett plot is a graphical solution to Archie’s equation so that plotting resistivity against porosity

(both in log scale) will produce linear arrangement of data. Rw is read from the graph, as illus-

trate in Figure 3.9.

Figure 3.9: Pickett Plot for Rw in well X1

To determine the value of net to gross ratio (NTG), the shale volume (Vsh), water saturation (Sw)

and porosity (Ø) of the zones were all considered. Since the GR logs used have been influ-

enced by mud or other factors it was not possible to use GR logs to determine Vsh. Therefore,

the neutron-density or density-sonic methods were used to calculate shale volume. Vsh for well

X4 was calculated using the density-sonic, whereas neutron-density was used for the other five

wells.

Subsequently, we set cut-off values for shale volume (< 0.8), water saturation (< 0.7) and poros-

ity (> 0.1). Any values out with these will not contribute to NTG. Details of each layer, and their

Rw=0.025


Page | 28

corresponding petrophysical properties, are shown in APPENDIX A1 – Petrophysical Sum-

mary of Six Appraisal Wells.

Figure 3.10: Poro-perm correlation for well X1

Permeability can be calculated using the porosity-permeability relationship derived from core

data of wells X1, X4, and X5. Basically, the Klinkenberg correction should be applied to convert

core permeability measured by gas at laboratory condition to liquid at reservoir condition.

Based on the given correlation in one of DST report, the kliquid = 0.25*kair. The cross plot be-

tween corrected liquid permeability and in-situ porosity of well X1 in the log-log scale is illus-

trated in Figure 3.10.

The above figure illustrates that for wells X1, the in-situ core porosity and permeability correlate

closely – the correlated coefficient (CC) value is higher than 0.9. However, for well X4 the CC is

significantly lower. That is because core porosity is gained vertically, well X1 and X5 have the


Page | 29

data of vertical permeability, but well X4 has only horizontal permeability data. This may explain

why well X4 calculated permeability does not match closely with the core permeability. From the

core porosity and core permeability correlation, we can calculate permeability within the reser-

voir using the porosity calculated by density log.

APPENDIX A2 – Composite Logs of Six Appraisal Wells illustrates the composite logs of all

six appraisal wells, which include all the information about the interpreted oil bearing zone, po-

rosity, water saturation, and permeability. Based on this result, we can subdivide our reservoir

into different zones. The wells X1, X2, X3 and X4 have five layers, whilst the wells X5 and X6

have only four layers. This is further demonstration that the area which wells X5 and X6 are

located is unlike the area where the other wells are located.

Finally, the oil water contact (OWC) from each well can be determined and these are shown in

Table 3.4:

Table 3.4: Determined oil-water contacts (OWC)

Wells X1, X2, X3, X4 Wells X5, X6

Low case (ft TVDSS)



Low case (ft TVDSS)



10810 10840 10860 10480 10500 10550

It is clear that wells X5 and X6 have a higher OWC than the other wells. The reason for which

will be investigated using other methods.

3.3.2 Repeat Formation Tester

The Repeat Formation Tester (RFT) was run in wells X1, X2, X3, and X5 to collect downhole

fluid samples and establish fluid contacts within the X field. The pressure depth plot, illustrated

in Figure 3.11, clearly illustrates the common oil gradient with different positioned water gradi-

ents. The most likely cause of this fluid contact variation would be a perched water contact or

trapped water, which is afterward supported by pressure transient response in the wells X5 and

X6. These two different free water levels (FWLs) observed at 10,840 and 10,560 feet subsea


Page | 30

are consistent to the OWCs determined from the petrophysical analysis of logs. Moreover, the

fluid gradients in both oil and water zones interpreted from RFT data are also in good agree-

ment with in-situ fluid densities analysed from fluid samples of wells X1 and X2.

Figure 3.11: RFT Pressure Plot of X Field

9800

10000

10200

10400

10600

10800

11000

11200

11400

11600

5300 5500 5700 5900 6100 6300

De

pth

(ft

ss)

Formation Pressure (psi)

RFT Pressure Plot of X Field

X1 X3 X5 Oil Gradient Water Gradient#1 Water Gradient#2

OWC@-10560 ft ss

OWC@-10840 ft ss

Oil Gradient, 0.3 psi/ft(PVT Sample of X1,

Oil density of 0.698 g/cc)

Water Gradient, 0.48 psi/ft (Water Sample of X2,

Salinity ~ 150,000 ppm)

supercharge

supercharge


Page | 31

3.4 RESERVOIR FLUID PROPERTIES

During the drilling of appraisal wells X1 and X2 fluid samples were gathered. There were two

downhole samples taken at a depth of 10,362 ft MD from well X1 and three wellhead samples

from well X2. The PVT analysis of selected samples consisted of the following tests and meas-

urements:

Single-stage and multi-stage separation tests

Bubble-point determination

Constant Composition Expansion (CCE)

Differential expansion

Viscosity

The summary of validated fluid properties is illustrated in Table 3.5.

Table 3.5: Summary of sampling conditions and reservoir fluid properties of wells X1 and X2 using PVT analysis.

Well Unit X1 X2

Sample No.

2809/21 2674-40 22478-152

Sampling Point

Bottomhole Wellhead Wellhead

Formation P. psi 5628 6000 5707

Formation T. deg F 245 250 250

Wellhead P. psi N/A 2375 2375

Wellhead T. deg F N/A 66.5 66.5

Pb @ Reservoir T. psi 1895 1813 1785

GOR ft3/bbl 527 501 494

Density @ Reservoir T. and P. G/ML 0.698 0.706 0.701

Density @Reservoir T and Pb G/ML 0.661 0.670 0.665

Density of stock tank oil G/ML 0.816 0.823 0.830

Viscosity @ Reservoir T. and P. CP 0.48 0.5 0.49

Viscosity @Reservoir T and Pb CP 0.43 0.39 0.34

Bo @ Reservoir T. and P. rb/STB 1.32 1.32 1.33

Bo @Reservoir T and Pb rb/STB 1.39 1.39 1.40

Co between Reservoir P and Pb vol/vol/psi 14x10-6 12.9x10-6 13x10-6

The PVT results illustrate a strong resemblance between the three tests. It indicates that the X

field is an undersaturated oil reservoir with no gas cap since the initial reservoir pressure is well


Page | 32

above the saturation pressure – approximately 3,800 psi above. The oil has average density of

39 – 42 °API and contains a low concentration of impurities. It is a low-shrinkage oil with an ini-

tial gas solubility of about 500 scf/STB. Since the oil has a lower viscosity than water (μ < 1cP),

a relatively high flow rate and stable displacement is to be expected during a water flooding pro-

ject. The composition and properties of reservoir fluid from both wells are tabulated in Table

3.6.

Table 3.6: Composition and properties of reservoir fluid from wells X1 and X2.

Component or Property Unit X1 X2

No. 2809/21 No. 2674-40 No. 22478-152

Methane Mol Percent 26.38 23.37 22.68

Ethane Mol Percent 9.84 8.32 6.98

Propane Mol Percent 9.45 8.61 9.28

Iso-Butane Mol Percent 1.3 1.21 1.27

N-Butane Mol Percent 4.76 5 4.52

Iso-Pentane Mol Percent 1.55 1.62 1.39

N-Pentane Mol Percent 2.72 3.06 2.49

Hexanes Mol Percent 3.89 3.58 3.04

Heptane Plus Mol Percent 38.73 43.77 44.59

Carbon Dioxide Mol Percent 0.4 0.66 0.68

Nitrogen Mol Percent 0.98 0.8 1.08

Molecular Weight 109.02 - 113.88

Molecular Weight of C7+ fraction 225.37 - 210.97

Density under S.C. G/ML - - -

Density of C7+ fraction under S.C. G/ML 0.8487 - 0.8424

Using the information from the above analysis of the reservoir fluid it has been found that we

can analyse the dynamic model using a black oil simulator (I.e.e Schlumberger E100) using

three phases in order to forecast oil, gas and water behaviour that is presented in the reservoir.

The criterion for a black oil model is laid out below, all of which are satisfied:

100 < GOR < 2,500

30 < API < 40


Page | 33

Boi < 2 rb/STB

Heptane + > 30 mol%

PVTp, a Petroleum Expert PVT Package, was used to calibrate the fluid model again from the

actual PVT data from well X1. This well was chosen because it was the only bottomhole sample

taken and likely to be most representative of the reservoir fluid. The phase property tables were

then exported into a format suitable for ECLIPSE.

Fluid Contents of the Northern Section

It has, however, been noted that there has not been any fluid samples taken in the northern

section of the reservoir. Since a fault has been identified that removes wells X5 and X6 from the

other wells, we are not certain that the fluids seen in this region are comparable with those seen

from the samples taken. Therefore, it would is recommended to take a fluid sample in this re-

gion when the next well is drilled there to remove this uncertainty. Nevertheless, using the RFT

data it has been shown that the oil gradients in both sections of the reservoir are the same, im-

plying that the oil in each region is of very similar quantity and we have assumed the fluid to

have constant properties throughout.

3.5 SPECIAL CORE ANALYSIS

In addition to the routine core analysis (RCAL) presented in the petrophysics section, special

core analysis (SCAL) was carried out on some core plugs taken from different depths of wells

X1, X4 and X5. It consisted of the two following experiments:

Capillary pressure obtained by Mercury injection test

Residual oil saturation obtained in Toluene/Air imbibition experiment

The laboratory experiment revealed that 37 out of 46 core plugs had irreducible water saturation

(Swirr) less than 15% and transition zone smaller than ten feet. Comparing to the total oil column

in the structure (400 – 600 ft) and 300 ft difference of fluid contact between the two compart-


Page | 34

ments, the transition zone effect on volumetric calculation and recovery factor prediction will be

insignificant. Figure 3.12 demonstrates an example of mercury/air capillary pressure measured

from core plugs of well X5. It is clear that the high permeable core plugs would have lower water

saturation and smaller transition zone than the tighter ones.

Figure 3.12: Mercury-Air Capillary Pressure Curve of Well X5

The residual oil saturation (Sor) from 48 core plugs varies between 15% and 41% depending on

the porosity, permeability and initial fluid saturation value. The average Sor is in the range of 29

– 32%.

The summary results of SCAL experiments performed on core plugs of wells X1, X4 and X5 can

be found in APPENDIX B1 – Special Core Analysis Summary of Core Plugs from Wells X1,

X4 and X5. To make use of capillary pressure data, it is required to convert these data from the

mercury-air system (laboratory condition) to an oil-water system (initial reservoir condition) using

equation 3.1:

airMercuryairMercury

wateroilwateroilairMercurywateroilR PcPcPc

//

////

cos

cos

3.1

0

200

400

600

800

1000

1200

1400

1600

0 10 20 30 40 50 60 70 80 90 100

PC H

g/A

ir (p

sig)

Sw (%)

Mercury-Air Capillary Pressure Curve of Well X5

X5, #1 (Por 11.3%, Perm 1mD)

X5, #22 (Por 17.6%, Perm 320mD)

X5, #66 (Por 22.6%, Perm 100mD)

X5, #89 (Por 19.0%, Perm 1mD)

X5, #119 (Por 18.6%, Perm 6mD)

X5, #148 (Por 23.6%, Perm 670mD)

X5, #150 (Por 16.2%, Perm 1mD)

X5, #185 (Por 26.6%, Perm 1800mD)

X5, #219 (Por 26.3%, Perm 2000mD)

X5, #254 (Por 27.4%, Perm 3600mD)

X5, #281 (Por 24.8%, Perm 870mD)

X5, #296 (Por 23.1%, Perm 350mD)

X5, #331 (Por 16.2%, Perm 38mD)


Page | 35

In the absence of interfacial tension and contact angle values, all of the constant terms required

in the calculation are referred to in Table 3.7.

Table 3.7: Two-phase interfacial tension and contact angle (Best, 2002)

Fluid Interaction Interfacial Tension (Dynes/cm) Contact Angle (°)

Mercury-Air 484 130

Oil-Water 15 0

Given the above assumption, the ratio between Pc oil/water and Pc mercury/air is approxi-

mately 20:1. Subsequently, equation 3. 2 can be used to convert the capillary pressure at reser-

voir condition to be the height above free water level (FWL).

g

Pch

hw

R

3. 2

To obtain a universal curve for each reservoir rock type, the Leverett J function was then used

to combine all capillary pressure data within the same lithology. The Leverett J function is de-

fined in equation 3. 3.

cos

2/1

kPc

J

R

3. 3

Figure 3.13 illustrates an example of the J function plot for a set of capillary pressure data from

well X5. It is difficult to establish the universal curve due to variation of rock properties from dif-

ferent rock types. Considering the different tortuosity in the various rocks by plotting J with nor-

malized water saturation, Sw* = (Sw-Swc)/(1-Swc), results in better correlation as shown in

Figure 3.14.


Page | 36

Figure 3.13: Leverett J Function Curve of Well X5

Figure 3.14: Modified Leverett J Function Curve of Well X5

0

100

200

300

400

500

600

0 10 20 30 40 50 60 70 80 90 100

Dim

en

sio

nle

ss J

Fun

ctio

n

Sw (%)

Leverett J Function Curve of Well X5

X5, #1 (Por 11.3%, Perm 1mD)

X5, #22 (Por 17.6%, Perm 320mD)

X5, #66 (Por 22.6%, Perm 100mD)

X5, #89 (Por 19.0%, Perm 1mD)

X5, #119 (Por 18.6%, Perm 6mD)

X5, #148 (Por 23.6%, Perm 670mD)

X5, #150 (Por 16.2%, Perm 1mD)

X5, #185 (Por 26.6%, Perm 1800mD)

X5, #219 (Por 26.3%, Perm 2000mD)

X5, #254 (Por 27.4%, Perm 3600mD)

X5, #281 (Por 24.8%, Perm 870mD)

X5, #296 (Por 23.1%, Perm 350mD)

X5, #331 (Por 16.2%, Perm 38mD)

y = 0.1696x-1.844

R² = 0.9468

0

50

100

150

200

250

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00

Dim

en

sio

nle

ss J

Fun

ctio

n

Sw*

Modified Leverett J Function Curve of Well X5

X5, #1 (Por 11.3%, Perm 1mD)

X5, #22 (Por 17.6%, Perm 320mD)

X5, #66 (Por 22.6%, Perm 100mD)

X5, #89 (Por 19.0%, Perm 1mD)

X5, #119 (Por 18.6%, Perm 6mD)

X5, #148 (Por 23.6%, Perm 670mD)

X5, #150 (Por 16.2%, Perm 1mD)

X5, #185 (Por 26.6%, Perm 1800mD)

X5, #219 (Por 26.3%, Perm 2000mD)

X5, #254 (Por 27.4%, Perm 3600mD)

X5, #281 (Por 24.8%, Perm 870mD)

X5, #296 (Por 23.1%, Perm 350mD)

X5, #331 (Por 16.2%, Perm 38mD)

Power (X5, #148 (Por 23.6%, Perm 670mD))


Page | 37

From the master curve, illustrated in Figure 3.14, the pore size distribution index, λ, can be de-

termined. Therefore, the relative permeability of oil-water system can be calculated through the

Brooks and Corey method (1964), expressed using equations 3. 4 and 3. 5.

)32

(*,

wrwrw SptendKK 3. 4

)2

(2*1*1,

wwroro SSptendKK 3. 5

For this field, up to ten tables of three phase relative permeability and capillary pressure data for

specific rock types and compartments have been provided as shown in APPENDIX B1 – Spe-

cial Core Analysis Summary of Core Plugs from Wells X1, X4 and X5. It should be noted

that the right rock curve table should be appropriately assigned to the right reservoir rock type in

the dynamic model so that Pc-derived fluid saturation profile matches with the wireline log-

derived water saturation.

Since the SCAL experiment for the gas-oil system is unavailable, the gas-oil relative permeabil-

ity was initially assumed to be a straight line with zero gas-oil capillary pressure. However, this

assumption would be invalid when the gas-oil miscibility effect is considered during gas reinjec-

tion. Without simulating the dynamic model under compositional mode, “pseudo miscible” gas-

oil relative permeability might be generated to simulate the effects of gas-oil miscibility effect on

reservoir performance.

3.6 HYDROCARBONS IN PLACE

3.6.1 Deterministic Reserves

A range of values for gross rock volume, petrophysical parameters and fluid properties were

used to estimate a possible range of values for the hydrocarbons initially in place (HCIIP) for

each of the five zones in the reservoir. These were then summed to find a range of totals for the


Page | 38

entire reservoir. Table 3.8 illustrates the range of STOIIP and reserves for each zone and then

finally for the complete reservoir. The variations of petrophysical properties (i.e. porosity, oil

saturation and net to gross ratio) that are used to determine STOIIP are illustrated in APPEN-

DIX B2 – Variations of inputs used to calculate STOIIP in each zone.

Table 3.8: Deterministic range of STOIIP and reserves.

STOIIP (MMSTB) Reserves (MMSTB)

Zone Minimum Most Likely Maximum Minimum Most Likely Maximum

1 59 109 152 27 60 106

2 141 274 380 64 151 266

3 30 93 149 13 51 104

4 173 278 346 78 153 242

5 46 108 232 21 60 163

Total 449 862 1259 202 474 881

3.6.2 Probabilistic Reserves

Using the variations of the petrophysical properties discussed above a probabilistic calculation

of the hydrocarbons was performed to determine the P10, P50 and P90 scenarios, as indicated

in Table 3.9. The illustration of the Monte Carlo simulation results is indicated in APPENDIX B3

– Probabilistic Determination of Reserves.

Table 3.9: Probabilistic Definition of P10, P50 and P90

STOIIP (MMSTB) Reserves (MMSTB)

P10 P50 P90 P10 P50 P90

737 860 995 389 460 536

It was noted that the parameter which created the most uncertainty in the calculation of re-

serves is the gross rock volume of each zone. The correlation that was achieved between the

wells has been assumed to act throughout the entire reservoir. This is clearly a significant as-

sumption that could easily be proved incorrect by further examination. Therefore, it is suggested

that a 3D seismic survey be carried out on the field to check that the gross rock volume of each

layer is correct and identify any further faults or compartments not found initially.


Page | 39

3.7 WELL PERFORMANCE

3.7.1 Well Test Analysis

There were a total of eight drill stem tests (DSTs) performed on the appraisal wells X2, X3, X5

and X6 (two tests performed on each). All DSTs were performed in oil-bearing zones, with the

exception of one test in well X2 which was performed in the aquifer. From the available flow rate

and pressure data, it is found that most of data drawdown data is too short and noisy to be used

for analysis, so build-up data is chosen as main interpretation. The results of the interpretation

of the well test data is illustrated in Table 3.10.

Table 3.10: Data achieved from well test interpretation

Well Test Date Depth (ft MD)

Kh (md-ft)

k (mD)

Skin PI (b/d/psi)

Flow Rate (bopd)

Heterogeneity

X2

BU

17/06/77 11040-11060

66378 98 120 11 -3600 Discontinuity 2300' away from wellbore

Fall-off 7088 11 70 2 -3600

DD/BU 21/06/77

10715-10750; 10766-10778

35143 270 1.5 35 8580 Discontinuity 1000' away from wellbore

X3

DD/BU 6-7/03/82 11759-11784

60900 342 1.7 53 10663 Distance to fault = 220'

DD/BU 29/05/82 41000 230 0 51 20390

X5

DD/BU 24/02/82

10982-11054

213500 1873 14.5 101 7460

DD/BU 09/06/82 602400 2008 70 79 12010

DD/BU 20/08/83 223000 817 22 64 15600

Two discontinui-ties 600' and 700' away from wellbore

X6

DD/BU 16/10/82

10748-10798

211500 504 60 33 19530

DD/BU 23/08/83 113644 243 50 26 15000

Two discontinui-ties 400' and 800‘ away from wellbore


Page | 40

The middle time response (infinite-acting radial flow period) is clearly seen in most of the tests,

allowing an estimate of average formation permeability and wellbore skin factor. The results

indicate that well test permeability is consistent to core permeability. However, the late time re-

sponse, which gives useful information about the reservoir heterogeneity (i.e. no flow bounda-

ries, closed boundaries, constant pressure boundaries, etc) is ambiguous in most tests. This

could be due to either too short a test period (only 12 – 24 hours for each drawdown and build-

up period) or poor quality of gauge pressure data itself.

The most important feature to notice here is that in wells X5 and X6, where we have already

found from log interpretation and RFT data examination that there is a different OWC than from

the other wells; we can see some late-time boundary effects. It was interpreted that these devia-

tions from infinite-acting, radial flow in the middle-time region was due to the presence of an ‘L-

shaped’ fault close to these wells because the late-time region began to level out at a value of

approximately four times the MTR plateau value. This fault is positioned approximately 600 feet

from well X5 and 400 feet from well X6. This fault is the reason for the variation in OWC, and

separates this region from the rest of the reservoir. There is, however, still some uncertainty

about the exact location of this fault since we don’t know how close to well X4 the fault is.

Clearly, there is an uncertainty in the range for the size of the compartmentalised fault region. It

is recommended that a DST is performed in well X4 to establish how far the fault is from this

well, allowing us to define the exact location of the fault.

3.7.2 Material Balance Analysis

The material balance method is used to analyse the first year of production data and early pe-

riod of average reservoir pressure decline trend from wells X3 and X5, which are located in the

different reservoir compartments. The objectives of this analysis can be summarised as follows:

Quantify original oil in-place (OOIP) of each reservoir compartment;

Determine the main reservoir drive mechanism of each reservoir compartments;

Determine the fault orientation and connectivity between reservoir compartments;


Page | 41

Predict the recovery factor (RF) of the X field

To achieve the above objectives, the material balance model has been set up using MBAL (Pe-

troleum Expert software). The model has been set up to consist of two separate tanks, repre-

senting the northern and southern compartments where wells X5 and X3 are located, respec-

tively. The linkage between the tanks is used to model fault transmissibility, which is currently

assumed to be zero (no communication between fault blocks). The tank parameter is individu-

ally estimated using the petrophysical analysis, core data, and production history for each com-

partment. Whereas, the fluid model is mutually used from the Black oil PVT table generated in

the reservoir fluids section above.

Figure 3.15: Energy plot of the northern tank

When the model has been completely set up, there are several history matching methods avail-

able in MBAL that can be used to validate the model against past production history and the

average pressure decline trend. Firstly, the energy plot is used to identify the main drive

mechanism(s) within each compartment. Figure 3.15 and Figure 3.16 indicate that fluid expan-

sion is dominant mechanism in the Northern tank, while the gas injection is dominant energy in

the Southern tank because gas reinjection had been implemented in this compartment from the

beginning of production. The water influx does not contribute energy in either compartment,

suggesting that the aquifer support may be minimal. However, the long term field performance

during the production phase would help to reconfirm the presence of aquifer support.


Page | 42

Figure 3.16: Energy Plot of the Southern Tank

Once the main drive mechanism is identified the analytical method is then used to estimate the

original oil in-place (OOIP) of each compartment. This analysis leads to OOIPs of 174 and 734

MMSTB for the Northern and Southern compartments respectively (see Figure 3.17 and Figure

3.18). Based on this estimate, it is then combined together with previous information about dis-

tance to the fault observed from well tests of wells X5 and X6 to relocate the fault in the static

model more accurately.

Figure 3.17: Analytical Method for OOIP Estimation of Northern Tank


Page | 43

Figure 3.18: Analytical Method for OOIP Estimation of Southern Tank

By creating material balance models of each compartment and linking them to type well models,

it is possible to predict field performance and recovery factor. All of the assumptions used below

will be refined in the reservoir simulation study. However, as a starting point, the following are

assumed to proceed in the construction of a base case forecasting model.

Number of wells = 7 producers, 5 water injectors, and 2 gas injectors

Well productivity index (PI) = 50 b/d/psi, Well injectivity index (II) = 11 b/d/psi

Total field oil rate = 135,000 bopd

Voidage replacement ratio of water = 1.0

85% of produced gas is reinjected back into reservoir

The results show that the X field is capable of producing for up to thirty years with seven years

of production plateau at 135,000 bopd. The total cumulative oil production is 465 MMSTB,

which is a recovery factor of approximately 51%, as illustrated in Figure 3.19.


Page | 44

Figure 3.19: Production profile using material balance simulation

Although the material balance analysis can provide us useful information about OOIP and re-

serves, there are still some uncertainties associated with this analysis. For example, the histori-

cal production data and average pressure decline trend used in this analysis might be too short

to reflect the actual field behaviour. Moreover, some parameters still remain unknown i.e.

transmissibility of the fault, possibility of additional faults and the degree of aquifer support.

Therefore, it is strongly recommended that collecting further reliable data (production, pressure,

PVT) during production phase would be vital so that MBAL model can be recalibrated against

dynamic reservoir simulation.

3.8 RESERVOIR MODELLING APPROACH

The reservoir modelling approach consists of two parts: building the static model and then a

number of different dynamic simulations on it. Both of these were completed using Petrel.


Page | 45

3.8.1 Static Model

To construct a geological model of the X-field the petrophysical data, the top structure contours

and core porosity and permeability were input into Petrel. Six horizons and five zones were then

identified in Petrel according to core permeability data and well logs (density, sonic and gamma

ray). Zone 1 is recognised by its high heterogeneity, generated during turbidity current as men-

tioned above. Zones 2 and 4 are identified as highly permeable layers. A distinctive feature of

the model is the pattern of highly heterogeneous Zone 1 which is not seen in wells X5 and X6. It

is estimated that this is due to erosion or pinch-out. Therefore, towards the north the model only

has four zones. Each zone was divided into five layers. Consequently, in the southern segment

there are twenty-five layers in the model.

Moreover, well test and RFT data analysis established two intersecting faults which divided the

field into two segments as mentioned before. Although the fault distance from each well was

found from well test analysis, its orientation, the fault angle, transmissibility and area of seg-

ments are uncertain. Some of these parameters assumed as follows:

Fault orientation, fault angle and area of segments – from material balance study led to

changing the fault orientation as illustrated in Figure 3.20;

Fault transmissibility – assumed a sealing fault, with sensitivities performed in simula-

tions;

Displacement due to faulting – no displacement.


Page | 46

Figure 3.20: Illustration of the top of the reservoir, indicating the two fault locations used in the

model

After the above assumptions were made, a fine and a coarse 3D grid model were constructed.

The fine model, illustrated in Figure 3.21, has a grid size of 50x50 metres and a total of 500,000

grids (160x125x25 cells). Whereas, the coarse upscaled model of 100x100 metre grids, dem-

onstrated in Figure 3.22, consists of 126,000 grids (80x63x25 cells). Log values that fall within

a cell were then averaged to produce an upscaled property. The arithmetic mean was used as

the averaging method because the reservoir is layered horizontally (Help Manual, 2011).


Page | 47

Figure 3.21: Permeability distribution on the fine grid model

These upscaled well logs were then used in facies and petrophysical modelling. In the model

the stochastic algorithm was preferred to the deterministic one because its data distribution will

be more similar to the real case.

Figure 3.22: Permeability distribution on the coarse grid model


Page | 48

The coarse grid model was constructed so that there are less grids to use for dynamic simula-

tion. Properties from the fine grid model were transferred to the coarse grid model using vol-

ume-weighted arithmetic averaging. Additionally, permeability was upscaled by both volume-

weighted arithmetic and geometric averaging to see what the effect was. Although the model

with geometrical averaging seems less permeable, they were relatively similar.

The STOIIP calculation is the final step in the static model construction. The volume calculated

in Petrel is then compared to the one found using material balance analysis. This is performed

to ensure that the created model is accurate and that the fault location is of the correct size. The

STOIIP was determined to be 842 MMSTB, which is similar to that from material balance analy-

sis (908 MMSTB), indicating the model can be assumed to be representative.

3.8.2 Dynamic Model

The reservoir simulation study is carried out to extensively evaluate the well and field perform-

ance to provide the optimal development strategy of the X-field can be established. The dy-

namic model is built in the Petrel reservoir engineering software, allowing for rapid model set-up

and operation.

3.8.2.1 Dynamic Model Set Up

Model Geometry

The 3D grid system used in the dynamic study is a Cartesian grid type with corner point geome-

try. The grid size in the horizontal direction is 100 x 100 metres and the vertical thickness is

equal to the depth as defined in the layering process. Initially, the full-field model was built with

the grid size in the horizontal direction of 50 x 50 metres. To optimise the simulation run-time

without compromising on the numerical dispersion effect, there was a need to scale up both the

structure and properties of the fine-scaled geological model by a factor of four. This results in

the grid dimensions (X-Y-Z) of 80x63x25. There is a total of 126,000 cells in the dynamic model.


Page | 49

A single fault has been identified in the reservoir and included when constructing the static

model. Since there is insufficient information to confirm the degree of communication between

both compartments, the fault transmissibility and diffusivity across the fault is initially set to be

zero.

Since the material balance analysis indicates an unsupportive aquifer system, except for the

water cells under the OWC, neither analytical nor numerical aquifer model is to be modelled.

Rock and Fluid Properties

The basic rock properties, comprising the net-to-gross ratio, porosity, permeability, water satura-

tion and hydrocarbon saturation, were modelled by assigning a value to each cell using scaled

up properties. It was assumed that the horizontal permeability is similar in both X and Y direc-

tions. On the other hand, the vertical permeability is calculated by simply multiplying the hori-

zontal permeability with average kv/kh ratio for each zone as illustrated in Table 3.11.

Table 3.11: kv/kh ratio for each zone determined from core data of wells X1 and X5

Zone

Ratio of horizontal to vertical permeability (kv/kh)

Northern Compartment Southern Compartment

Min Max Avg Min Max Avg

1 Pinch-out 0.02 0.02 0.02

2 0.14 0.86 0.39 0.65 1.00 0.80

3 0.46 1.00 0.78 0.41 0.89 0.63

4 0.10 0.92 0.17 0.77 1.00 0.89

5 0.05 0.85 0.20 0.03 0.94 0.13

All available PVT samples from the appraisal wells have been reviewed to get a representative

one for describing the fluid properties of the X-field. The black oil PVT table obtained from cali-

brating fluid model against PVT lab result of well X1 is used throughout this study because it

was taken in-situ and, therefore, will be more representative. The live oil PVT model is illus-

trated in Figure 3.23 and the same was repeated for dry gas. It has also been assumed that


Page | 50

most of the gas would remain segregated after reinjection into the secondary gas cap and that

there is negligible change in PVT.

Figure 3.23: Fluid Property of Live Oil (PVTO)

SCAL Properties

Table 3.12: Rock type curve assigned for each zone

Zone

Rock Curve Table

Northern Compartment Southern Compartment

Porosity/ Permeability Range Swi Porosity/ Permeability Range Swi

1 Pinch-out Ø>27%, Kair>1000mD 0.15

2 22%<Ø<25%,

500mD<Kair<1000mD 0.1

22%<Ø<25%, 500mD<Kair<1000mD

0.12

3 20%<Ø<23%, 10mD<Kair<50mD 0.35 20%<Ø<23%, 10mD<Kair<50mD 0.35

4 22%<Ø<25%,

500mD<Kair<1000mD 0.1

22%<Ø<25%, 500mD<Kair<1000mD

0.12

5 20%<Ø<23%,

100mD<Kair<500mD 0.15

20%<Ø<23%, 100mD<Kair<500mD

0.16

0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800

0 400 800 1200 1600 2000 2400 2800 3200 3600 4000 4400 4800 5200 5600 6000 6400 6800

Pressure, [psi]

11.1

1.2

1.3

1.4

1.5

1.6

1.7

1.8

1.9

22.1

2.2

2.3

Liq

uid

Fo

rma

tio

n V

olu

me

Fa

cto

r, [

RB

/ST

B]

0.2

0.4

0.6

0.8

11.2

1.4

1.6

1.8

Oil V

isco

sity

, [cP

]

00.2

0.4

0.6

0.8

11.2

1.4

1.6

1.8

22.2

2.4

2.6

Ga

s T

o L

iqu

id R

atio

, [M

SC

F/S

TB

]

Symbol legend

Oil formation volume factor (PVT_X1_FIT2_V3)

Oil viscosity (PVT_X1_FIT2_V3)

Solution gas-oil ratio (PVT_X1_FIT2_V3)


Page | 51

Up to ten tables of three-phase relative permeability and capillary pressure data were prepared

for each particular reservoir rock type in each compartment. Table 3.12 illustrates the selected

rock curve table for each zone.

During the model initialisation, the initial water saturation (Swi) was set into each grid cell as per

the assigned rock curve table. Nevertheless, the Leverett J function option in Eclipse is also

activated to ensure the representative water-oil capillary pressure for each zone is scaled ac-

cording to the grid block porosity and permeability. This could bring the water saturation derived

by Pc closer to the log data and improve the in place volume estimation.

Initialisation

Prior to use of the 3D reservoir simulation model it needs to be initialised at the initial condition.

The data, illustrated in Table 3.13 and

Table 3.14, are assigned to each reservoir compartment.

Table 3.13: Pressure vs. Depth (PRVD) of X field

Initialization type Pressure Initialization

Compartment Northern Southern

Pressure (psi) 5700 5700

Datum depth (ft) 10500 10500

Gas-oil contact (ft) 9760 (above top of reservoir) 9760 (above top of reservoir)

Oil-gas Pc (psi) 0 0

Water contact (ft) 10560 10840

Pc at water contact (psi) 0 0

Table 3.14: Dissolved gas concentration vs. Depth (RSVD) of X field

Rs Initialization Depth (ft) Rs

(MSCF/STB)

Northern Compartment

10560 0.505

9760 0.505

Southern Compartment

10840 0.505

9760 0.505


Page | 52

After initialisation, the OIIP of the dynamic model is determined to be 898 MMSTB, which is just

more than that of the static model (842 MMSTB). The main reason for this difference arises due

to the water saturation model. Assuming that the upscaled water saturation from the fine grid

static model is correct, it is possible that water saturation profiles generated by specified rock

curve tables may not perfectly match with upscaled log-derived water saturation model. This

problem could be resolved by initialising the dynamic model with another method, the “Enu-

meration”. Basically, all initial properties (pressure, saturation, Rs, etc) are explicitly defined into

each grid cell, yielding a more accurate fluid in-place calculation. However, this method is not

appropriate for input data of poor or inconsistent quality. The dynamic model will face instability

issue, i.e. fluid redistribution during initialisation if the properties of each grid cell are not well-

defined.

3.8.2.2 Production Strategy

Prior to simulating development scenarios, the well management (in terms of individual rate

production capacity) was investigated using nodal analysis. The detail of analysis will be fully

explained in the production engineering section later. In summary, the well is capable of produc-

ing up to 30,000 bbl/d via 4.5” OD tubing (3.958” ID) based on an average well productivity in-

dex of 50 b/d/psi from past well test results.

After the individual well rate has been determined, the actual operating flow rate might be also

adjusted to satisfy surface facility constraints and field target limits. Currently, there are no pro-

ducing fields in Greenland and, hence, the maximum oil production rate of X-field is analogued

from the information from similar fields in the Central North Sea area, which is considered to

have similar geological settings. Plateau production rates for all these fields are illustrated in

Figure 3.24. According to this relationship, the maximum oil production rate of X-field is indi-

cated to be 150,000 bopd at the estimated recoverable reserves of 470 MMSTB. Several op-

tions of surface production facilities to handle such a high level of production in offshore

Greenland will be examined in detail later.


Page | 53

Figure 3.24: Relationship between total recoverable reserves and peak oil production from

Central North Sea Fields

Although the past production data of wells X3, X5 and X6 during 1982 – 1983 indicate that the

wells are capable of producing 15,000–20,000 bopd, However, due to well integrity and safety

issues, none of these wells will be utilised during the full-field development. Therefore, a mini-

mum of seven new producers are required in the first phase of development to achieve 90% of

maximum design rate of surface facility (i.e. 135,000 bopd). All new wells will be drilled from the

same subsea template and be targeted at the crest of structure. The producers will be com-

pleted bottom-up in the main producing intervals (zones 2–4). Each well is expected to produce

around 20,000 bopd with a minimum bottomhole flowing pressure (BHFP) of 2500 psi. When

BHFP falls below 2500 psi some sources of artificial lift technologies (i.e. gas lift or ESP) will be

implemented to enhance the flow performance. In addition to this, water shut-off operations will

be conducted in high water-cut wells to prevent the well loading problem. Finally, the well will be

abandoned when oil production rate is less than 100 bopd or water-cut is higher than 95%.

0

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Total Recoverable Reserves vs. Peak Oil Production

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Page | 54

One of the major concerns regarding the ultimate recovery factor is that the X-field would not be

supported by a strong water drive mechanism, as indicated by the 1000 psi reservoir pressure

drop within the first two years of operation. It is, therefore, proposed to drill five peripheral water

injectors to maintain reservoir pressure sufficiently high to allow producers to flow naturally even

at a high water-cut. The water injection interval is zone 5 below the WOC. Although the well test

from well X2 indicates a poor injectivity index, it was recognised that this underestimates the

injectivity of the actual operation because the injection of seawater with colder temperature than

formation will create a thermally induced hydraulic fracture with a high injectivity index. The wa-

ter injection is planned after the second year of production to allow for timing of field perform-

ance review and to analyse the strength of the aquifer. Regardless of the thermal fracturing

phenomenon, the water injector is operated below the bottomhole injection pressure of 8,000

psi, ensuring it does not exceed the estimated fractured pressure gradient of formation.

Because of the lack of gas market and regulation about gas flaring in Greenland, it is assumed

that 85% of produced gas will be reinjected via two gas injectors into the top zone in order to

form a secondary gas cap for pressure maintenance at the beginning of production. The re-

maining 15% will be used as fuel and power generation for the surface production facilities.

Since there is no information about the degree of miscibility between the reservoir oil and in-

jected solution gas, it is assumed that both fluids are immiscible phases during the gas reinjec-

tion process.

To establish the base case production strategy of the X-field, multiple development scenarios

involving various number of wells, their position, and completion types was carried out, as

summarised in

Table 3.15. The results indicate that the incremental production gained by additional producers

is limited. Although the horizontal well option (case 5) yields the highest recovery factor, the

NPV is still lower than case 1 and requires a significantly larger project outlay (MCO), both un-


Page | 55

desirable to Mungo Energy. Therefore, the base case production strategy of X-field consists of

seven producers, five water injectors and two gas injectors.

Table 3.15: Sensitivity analysis on number and type of wells to justify base case production strategy (Cases 1 – 5)

Run Description Parameters FOPT

(MMSTB) FOE (%)

NPV (MMUSD)

1

Number of well and

Type

7 Producers (all deviated), 5 Water Injectors, 2 Gas Injectors

477 53.05 1,424

2 9 Producers (all deviated), 5 Wa-

ter Injectors, 2 Gas Injectors 478 53.16 1,382


ter Injectors, 2 Gas Injectors 479 53.29 928


ter Injectors, 2 Gas Injectors 480 53.43 910

5 6 Producers (4 horizontal and 2

deviated), 5 Water Injectors, 2 Gas Injectors

489 54.40 1,124

Figure 3.25 illustrates the proposed locations of the proposed wells in the 3D dynamic model.

Figure 3.26 demonstrates the production profile of the base case production strategy. The field

can produce for around twenty years with five years of plateau production at 135,000 bopd. The

total oil production cumulative is 477 MMSTB, considered to be a recovery factor of 53%.

Figure 3.25: Proposed locations of producers and injectors for the base case production strat-

egy


Page | 56

Figure 3.26: Base Case Production Profile of X field

3.8.2.3 Sensitivity Analysis

All possible sensitivity analysis on various uncertain input parameters of the dynamic model that

can affect the field recovery factor was investigated as follows:

Sensitivity on Modelled Permeability (Cases 6 – 7)

In the base case, the upscaled equivalent liquid permeability model has been used to model

inter-block flow in the reservoir simulation. However, as mentioned previously, the factor of 4 is

simply used to reduce air permeability measured from core plug to an equivalent liquid perme-

ability or Klinkenberg-corrected permeability. Without unsteady-state air permeability measure-

ment at different backpressure or steady-state liquid permeability measurement, the above as-

sumption on permeability correction is questionable. Therefore, two simulation runs using up-

scaled air permeability and 50% reduction of upscaled equivalent liquid permeability are simu-

lated as maximum and minimum cases.

Sensitivity on Plateau Production Rate (Cases 8 – 9)

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Base Case Production Profile of X Field


Page | 57

In the base case, the field production has been constrained at 135,000 bopd as per field per-

formance and capacity of available surface production facilities. Given a lower plateau rate,

considerably longer plateau times may be achieved. A slight decrease in ultimate reserves will

be attained for lower plateau rate as the trapped oil saturation behind the encroaching aquifer

flood front will be at higher pressure and, therefore, represent a higher equivalent surface vol-

ume left behind.

Sensitivity on Pressure Maintenance (Cases 10 – 12)

Given the indication of large pressure drop during the first year of production and lack of gas

market in the Greenland, reinjection of sea water and produced gas are considered to be impor-

tant in terms of pressure maintenance. Since it is much more difficult to predict behaviour of

storing produced gas as a secondary gas cap in the reservoir, the main pressure maintenance

of the X-field would depend on the performance of water reinjection.

Sensitivity on Gas Reinjection Fraction (Cases 13 – 15)

Although gas reinjection can improve the recovery factor by maintaining reservoir pressure and

squeezing oil below it to the nearby producers, the long term advantage of this secondary re-

covery method is still uncertain. By ignoring the gas-oil miscibility effect in the reservoir simula-

tion, it means that reinjected gas does not mix with the oil and stays as free gas in the reservoir.

Due to the large mobility variation between the phases, gas is able to move considerably faster

than the oil under the same pressure differential. Based on the current dynamic model, where

the vertical communication between zone one and other zones is very high, the higher gas rein-

jection fraction is introduced to the reservoir and an earlier gas breakthrough is observed at

nearby producers. Therefore, the recovery factor will be lower as gas reinjection fraction in-

creases.


Page | 58

Sensitivity on Bottomhole Injection Pressure of Water Injectors (Cases 16 – 18)

Since water injection is the predominant drive mechanism of the X-field, multiple runs on bot-

tomhole injection pressure have been run to find out the optimum operating point for the water

injectors. Since the average injectivity index within the aquifer is relative low (11 b/d/psi), the

maximum pressure difference across the sandface is required to achieve the highest injection

rate per well. In this case, the bottomhole injection pressure of each well should be close to the

estimated fracture pressure. If this condition is successfully met, the total field injection rate from

five water injectors will be close to a voidage replacement ratio of 1.0, which is sufficient to

maintain reservoir pressure of the X-field.

It should be noted that the bottomhole injection pressure of each well could be reduced if ther-

mal fracturing was induced. A concern is that such fractures can also cause the injected water

to by-pass the desired flood front and cause premature water breakthrough.

Sensitivity on Fault Transmissibility (Cases 19 – 22)

As a base case, a sealing fault with zero transmissibility was assumed. Four different values of

fault transmissibility multiplier (0.25, 0.5, 0.75 and 1.0) were analysed. The simulation results

show that the recovery factor slightly decreases when the degree of communication across the

fault increases. This is because the two producers in the northern compartment will now also

experience the gas cusping problem arising due to the gas reinjection in the southern compart-

ment.

Sensitivity on kv/kh Ratio (Cases 23 – 26)

Core data of wells X1, X4 and X5 indicate that vertical permeability is slightly less than that for

horizontal permeability, with an average kv/kh ratio of 0.7. Although it should be noted that the

data set is limited. To investigate the effect of the kv/kh ratio on the recovery factor, a range of

average kv/kh ratios was investigated. It is evident that a lower kv/kh ratio will decrease the

sweep efficiency of water injection and reduce the recovery factor.


Page | 59

Sensitivity on Polymer Flooding (Cases 27 – 29)

The objective of polymer flooding during a water injection project is to reduce the mobility of the

injected water, resulting in a more favourable fractional flow curve of injected water. This will

lead to a more efficient sweep pattern and reduce any viscous fingering effect. To identify the

efficiency of polymer flooding for the X-field three different values of polymer viscosity multiplier

(2.5, 5, and 12,5) were utilised to increase the viscosity of the injected water from the original

value (0.39 cP) to much more viscous values (i.e. 0.98cP, 1.96cP and 4.89 cP). However, the

results indicate less recovery factor in all cases. This is because it is much more difficult to inject

more viscous water below fracture pressure. The lower pump rate causes slow movement of the

flood front, resulting in poor sweep efficiency. Since the water/oil mobility ratio of X field is less

than one, water can displace oil in a piston-like manner. Therefore, it is unnecessary to use

polymer flooding to improve the sweep efficiency for this field.

A summary of all scenarios run to investigate effect of uncertain parameters on recovery factor

can be found in

APPENDIX B4 – Sensitivity Analysis of Reservoir Simulation.

3.8.2.4 Uncertainties of reservoir simulation

There are still a number of remaining uncertainties in the field and these are detailed below,

indicating possible measures to be taken to eliminate them:

Reservoir Architecture and Compartmentalisation

New 3D seismic data and well data drilled in the development phase will be used to up-

date the 3D static model.

Further well testing data will be used to confirm reservoir connectivity and/or compart-

mentalisation identified from large scaled 3D seismic data.

Water Injection Process


Page | 60

The thermal fracturing prediction requires a greater understanding of the stress sensitiv-

ity of the formation. The thermal fracturing model can be modelled using REVEAL (Pe-

troleum Expert software) and coupled to the 3D dynamic model for more accurate pre-

diction of water injection performance.

Gas Injection Process

Oil-gas miscibility effect can be modelled in either compositional simulator (E300) or use

of pseudo miscible gas-oil relative permeability curve (Valenti, 1986)..

The location of underground gas storage should be reviewed and planned according to

the updated reservoir structure obtained from new information during development

phase (3D seismic). If a separate fault block is identified then this would be an ideal po-

sition for gas storage as it will eliminate the gas cusping problem that limits the recovery

factor.

History Matching and Production Forecast

Further data acquisition for ongoing calibration of predictive reservoir models (simulation

and material balance analysis).

Production Improvement

Consider the use of water alternating gas (WAG) in the future.

Consider the enhance oil recovery (EOR) methods, i.e. miscible gas injection or chemi-

cal injection. However, economic justification should be further estimated for each alter-

native. These methods are to be considered in the future when production has begun to

decline.


Page | 61

4 DEVELOPMENT AND MANAGEMENT PLAN

4.1 DEVELOPMENT PLAN, RESERVES AND PRODUCTION

PROFILES

4.1.1 Development Plan

A 3D seismic survey is planned for before the start of drilling. This should allow the identification

of faults and definition of the areal extent of the reservoir.

The X-field will initially be developed in two stages, using a semi-submersible drilling rig. The

first stage is initiated when the seven producers and two gas injectors are to be drilled. The gas

will provide some solution gas drive, but the primary drive mechanism will be natural drive. This

allows us to learn much more information about the reservoir, including the strength of the aqui-

fer and any other drive mechanisms. The average reservoir pressure (about 5,800 psi) will be

allowed to drop, yet nowhere near to the bubble point pressure (Pb = 1,800 psi) to maintain an

undersaturated reservoir.

The second phase will contain the introduction of five water injection wells two years after the

start of production in the periphery of the reservoir for pressure support. It is estimated that this

significantly enhances the recovery from the field.

Once these drilling phases have been completed, vast more amounts of information about the

reservoir will be known and any other required drilling stages, infill drilling or EOR introduction

can be planned. This allows us to reduce some of the main uncertainties in the field (e.g. pres-

ence of other faults, location of the known fault, areal extent of reservoir, strength of aquifer,

etc), whilst not committing the full capital to the project up-front. An FPSO is to then be used as

the production facility with the export of oil to Placentia Bay, Newfoundland through the use of

tankers, whilst all produced gas will be used for power requirements on the FPSO or reinjected

back into the reservoir.


Page | 62

4.1.2 Reserves

As defined by the deterministic and probabilistic methods of determining hydrocarbons in place

above, the recoverable reserves was identified to be approximately 460 – 480 MMbbls. The use

of the dynamic model proved that it was possible to recover this amount of oil. However,

through the use of EOR techniques or new technologies in the future it may be that higher re-

coveries are possible. Moreover, the effect of the gas cusping is the main limiting issue of

achieving a higher recovery factor. Therefore, if it becomes possible to export the gas economi-

cally in the future then a significantly higher recovery factor may be achieved.

4.1.3 Production Profile

Using the base case of seven producers, five water injectors and two gas injectors described

above and a plateau rate of 135,000 bopd, limited by the FPSO’s surface facilities, the expected

production profile is previously illustrated in Figure 3.26. The plateau production is achieved for

five years before increased gas cusping leads to the maximum gas handling capacity being

reached and the need to reduce production from the affected well.

It was then decided that it was unlikely that the field would be able to produce at the full produc-

tion rate of 135,000 bopd from the first day of production. Therefore, when compiling the analy-

sis of the field it was decided that 50% and 75% of the plateau production would be produced in

the first and second year respectively (see Figure 4.1). This has the effect of decreasing the

NPV of the project from USD 5,050 milllion to USD 4,574 million.


Page | 63

Figure 4.1: Production profile for the base case (with build-up period)

4.2 DRILLING

4.2.1 Drilling Facilities

A jack up drilling rig or semi-submersible rig for drilling were both considered as alternatives for

the drilling programme. The high mobility of the semi-submersible rigs proves advantageous

because of the threat of icebergs in Greenland and its stability against wave action. The

drawback of jack up rigs is that they will only be able to be used when the sea is ice-free,

resulting in seasonal production. A semi-submersible drilling rig like The Henry Goodrich semi-

submersible, which was used in Newfoundland and was designed specifically for icebergs and

harsh environnments, is to be used.

Prior to the start of the drilling program, a fixed point on the sea bed has to be anchored in order

to allow the four guidelines to direct the drilling tools and casing from the rig to the sea bed. The

conductor will be hammered and the surface casing run and cemented. After this a BOP stack

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Base Case Production Profile of X Field (with Build-up Period)


Page | 64

and a marine riser will be installed. A typical marine BOP stack is arranged of, from top to bot-

tom: an annular preventer, a shear ram, two pipe ram and a blind ram. After the drilling program

has terminated a spool type wellhead is installed because it gives a large amount of flexibility to

allow for workovers and recompletions.

4.2.2 Well Planning

Well planning is one of the most challenging issues in the drilling aspect of the field develop-

ment project. Since we do not have offset well analysis, geology and pressure analysis are used

for well planning, using published data from nearby fields.

Pore Pressure Gradient

Mudweight, sonic log as well as density log data from appraisal wells have been analysed in

order to achieve pore pressure analysis. There is no sign of abnormal pressure zone above the

reservoir. Therefore, the assumption of the normal pressure gradient in the North Sea (0.47

psi/ft) is applied, illustrated in APPENDIX C1- Pressure Distribution

Fracture Pressure Gradient

The fracture pressure can be achieved by different ways. In this case, the Ben Eaton and Mat-

thews & Kelly equations are applied to predict the fracture gradient. Furthermore, it is highly

reliabile to carry out a leak off test after setting the casing to achieve the real fracture pressure.

Thus, the maximum mudweight for the next section is determined. The calculations of both

methods and graphs are illustrated in APPENDIX C1- Pressure Distribution and APPENDIX

C2 – Fracture Pressure Spreadsheet Calculation.

Casing Program

The drilling engineer must consider the lithology, geological conditions, borehole problems and

government regulations. Using the basic drilling principles, together with knowledge of the geo-

logical conditions, it is possible to identify where casing strings should be set. The casing pro-

gram is as follows:


Page | 65

18 5/8” Conductor Casing: Setting depth of approximately 200-300 ft is recommended.

13 3/8” Surface Casing: Provide strength for a blow out preventer (BOP); cover fresh

water shallow formations; maintain borehole integrity; and support the weight of casing

strings below surface casing. According to the sample calculation, fully explained in AP-

PENDIX C3 – Casing Setting Depth Calculation, a depth of 3,670 feet TVD is selected.

9 5/8” Intermediate Casing: Purpose concerns abnormally high formation pressures.

Due to the result obtained from calculation, demonstrated in APPENDIX C3 – Casing

Setting Depth Calculation, the minimum setting depth is 6,200 feet. However, after

checking the mud program of the appraisal well, there is no indication of any trouble

zones. Therefore, the setting depth of 8,400 feet TVD, just before drilling enter into the

reservoir zone, is also used.

7” Production Liner: In this case, the setting depth of production liner is located at

11,000 feet TVD, just below the reservoir which is strong enough to carry out a cement

job to achieve good wellbore integrity.

Mud and Cement Program

Based on the mud program report, seawater was used to drill the surface casing until 1,400 feet

with mud density of 9.23 lb/gal. However, according to lithology data, soft and unconsolidated

formations are dominant. These formations are sensitive and tend to swell and slough into the

borehole when drilling with a water based mud (WBM), leading to severe washout, ineffective

cutting transport and even borehole collapse. Therefore, a non dispersed-inhibited water-based

mud system should be applied down to the section above the reservoir (9,400 feet). An oil

based mud system (OBM) is used in the reservoir section to not damage the target zone. AP-

PENDIX C1- Pressure Distribution and


Page | 66

APPENDIX C4 – Well Schematic Design and Drilling Section Lithology show mud pressure

gradient and mud density applied along the hole respectively. (H.A & P., 1974) (Mahamed &

Mya, 1983)

To obtain a good cement operation it is important to seal off unconsolidated formations. The

purpose of the cementation process is to protect against corrosion, provide casing support and

prevent fluid migration and lost circulation. The most appropriate cement for the X-field is the

API Class A cement: This cement type is widely available and its performance can be changed

by the use of additives. Thus, it provides an adequate choice for the surface casing.

For the surface casing and production liner, single-stage cementing is chosen because a con-

tinuous cement column is to be placed in the annulus. In contrast, the intermediate casing will

utilise multistage cementing to eliminate extreme hydrostatic pressures on the formations and

high pump pressures. The calculation example of the cement process is further demonstrated in

APPENDIX C5 – Cement Calculation Example. (Adams, 1985)

Drilling Schedule

An estimation of the length of the drilling program has been made assuming: ROP decreases

with depth; starting at 100 ft/hr; cementing time fixed at sixty hours; and depth drilled per every

bit is set at 1,000 feet.

It takes approximately thirty days to drill one well, as illustrated in Figure 4.2. However, this is a

rough estimate since many other factors can affect the calculation (e.g. premature failure of the

bit).

Drilling Bit Selection

The selection of the drill bits was carried out by considering the lithology and the type of mud

used and possible formation damage. The main uncertainty is the lack of data describing the

formation above the reservoir. Analysis of the same region of the North Sea allowed estimation

of the lithology, this full lithology is illustrated in


Page | 67

APPENDIX C4 – Well Schematic Design and Drilling Section Lithology. The western and

southern region of the reservoir is different since the shale layer has been eroded.

Figure 4.2: Drilling Time Estimation. (T.W, 1992)

The first three layers are considered to be soft. Therefore, a roller cone bit (RCB) with long and

widely spaced teeth is proposed, with a relatively low weight on bit (WOB) and a high flow rate,

since a high ROP is expected. The last two layers (shale and reservoir) are considered to be

medium/hard. Since OBM has been selected, the PDC bit is recommended because it works

better with OBM due to its better lubrication properties, allowing a higher ROP. Moreover, a re-

duction of the number of trips is expected.

0

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Hammering the 26' conductor

Drilling the 16' surface casing

Cementing the surface casing

Drilling the 12 1/4' intermediate casing

Cementing the intermediate casing

Drilling the 8 1/2' production liner

Cementing the production liner


Page | 68

Directional Drilling

According to the pre-determined target zone, a build and hold type are recommended for drilling

deeper wells with large horizontal departures. The target was set at 11,000 feet TVDSS.

The target is located 6,560 feet (southeast) from drilling platform. The build up rate is set to be a

maximum of 3°/100 feet to minimise the key seat occurrence as well as the wear of the equip-

ment. Consequently, the well is to be drilled with a 38° deviation to achieve the target zone.

Well location and well trajectory planning are further demonstrated APPENDIX C6-Directional

Drilling Well Location and Trajectory.

Directional Drilling System and Surveying Method (IHRDC, 2012)

A rotary steerable system (RSS) is suggested for the drilling programme because it has the abil-

ity to drill directionally with continuous rotation from the surface. This system provides a wide

range of advantages compared with the use of mud motor drills.

In addition to this, this method allows operators to plan complex wellbore geometries, which

would not be achieved effectively or efficiently by conventional drilling. The BHA commands the

well path in the planned direction at the same time as keeping the orientation of the trajectory

separate from its rotation.

Casing Design

The casing string design is a critical issue for protection during both drilling and production

phases. It is usually designed to withstand severe operating conditions. The maximum load

concept is one of the most widely applied processes, examining possible drilling problems.

Graphical techniques are applied throughout the casing design procedures as depicted in AP-

PENDIX C8 – Casing Design Calculation Example (Adams, 1985) to select the most suit-

able weights, grades and section lengths of casing .Table in APPENDIX C8 – Casing Design

Calculation Example (Adams, 1985) shows the casing selections according to the following

criteria:


Page | 69

Burst Pressure;

Collapse Pressure;

Tension.

Drillstring Design (IHRDC, 2012)

A proper design of the drillstring can prevent drilling problems. To use an RSS a bottom hole

assembly consisting of the following parts is used: Non-magnetic drill collars; First String Stabi-

lizers; Jars; Reamers; Float subs; Circulating subs; Vibration dampeners; Downhole motor;

MWD/LWD tools; and Rotary steerable systems.

Drillpipe Selection (Adams, 1985)

The following information is the commonly used size of drillpipe available in the market: 3 ½”

13.30 lb/ft nominal; 4 ½” 16.60 lb/ft nominal; 5” 19.50 lb/ft nominal. The 4.5” 30 ft drillpipe is

most common and is selected. The drillpipes must always be applied in tension. Thus, proper

design of the BHA is essential. It is common to check the drillpipe regarding the expected burst,

collapse and tension loads. The resulting values from APPENDIX C9 – Drillstring Design Cal-

culation confirm that the 4.5” drillpipe can withstand the loads. (Adams, 1985) (IHRDC, 2012)

Risks and uncertainties

Possible risks and uncertainties have been summarized in the Table 4.1.

Table 4.1:Possible Risks and Uncertainties in Drilling Program

Risk/Uncertainty What is the R/U affecting What can account/ minimize the R/U

Geological description

- overpressure zones - natural fracture/ easily fracture zones - shallow gas pocket - hard/unconsolidated formations

- LWD/MWD - regional geology studies - 3-D seismic lines

Drilling Fluid - possibility to have a kick - possibility to have losses - reaction with formation clays LWD/MWD - use of inhibited muds - additives in stock

- LWD/MWD - use of inhibited muds - additives in stock


Page | 70

Differential sticking - Stop/delay the process - spiral collar/ centraliser

Well path - deviation from the planned path - directional survey

Cementing/Casing - lithology - fluid losses - reaction with clays - TOC

- LWD - CBL/VDL - Heavyweight and lightweight additives

Operation - Icebergs - Weather conditions

- Monitor weather conditions - monitor icebergs trajectory

4.3 PRODUCTION TECHNOLOGY

The main goal of the Production Engineer is to maximise production whilst minimising costs. In

this section, the issues regarding to production system will be explained.

Well Completion Design(IHRDC, 2012)

Completion design mainly refers to the zone of completion, well type, production type, and inter-

face between the reservoir and the wellbore. The wells are cased and perforated in the pay

zone and the main advantages of this kind of completions can be summarised as:

Reduce the probability of well control problems;

Facilitation of selective stimulation;

More informed selection of the zones to be completed;

Possibility of multizone completions.

The expected production rate for the whole field is relatively high, indicating that artificial lift will

not be needed in the early life of the project. However, gas lift or ESP systems may be consid-

ered as an option to reduce the flowing pressure or increase the flow rate after producing for

some time.

Completion String

The solution proposed for completing the well is a tubing completion with annulus packer. A

description of the main part and tools required is described below and is illustrated in Figure

4.3.


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Figure 4.3: Completion schematic. (Davies, 2011)

Tubing Design

The tubing must be designed to withstand all stresses that might happen during the daily opera-

tion and for unusual load conditions. The burst, collapse, tension loads and corrosion environ-

ment must not exceed that of the tubing resistance. The design procedure is shown in APPEN-

DIX D1 – Tubing Design Calculation Example, which leads to the proper tubing size selec-

tion. According to the table in APPENDIX D1 – Tubing Design Calculation Example, 4 ½”

tubing is selected based on the expected flow rate from reservoir engineer.

Well Performance Analysis

Selecting the correct well type is a critical issue. Vertical, deviated and horizontal wells will give

different flow rates and productivity indexes. According to the economics analysis, deviated

wells generate the maximum NPV over 20 years of development. Well performance from each

design is achieved by Wellflo software and illustrated in Table 4.2.


Page | 72

Table 4.2: Well Performance Analysis.

Well Type

PI Gas Rate Oil Produc-tion rate

drawdown Operating pressure

(STB/d/psi) (MMSCF/d) (STB/d) (psi) (psi)

Vertical 32.63 14.26 28515 873.66 4826.34

Deviated 59.68 15.71 31423 526.47 5173.53

Horizontal 256.06 15.9 31793 124.16 5575.84

The maximum PI is observed from the horizontal well due to the largest exposure to the reser-

voir zone. However, it should be noted that the cost of a horizontal well is significantly higher

than for deviated wells. Another advantage of selecting deviated wells is the lower risk.

The well can flow naturally at a rate of 2,473 STB/d with the pressure above 2,500 psi. Below

this value water and gas injection must be used for pressure maintenance in the reservoir.

Pipesim Simulations

Pipesim software is used to find that the minimum operating wellhead pressure is approximately

350 psi. The production network diagram can be seen in APPENDIX D2 –Pipesim Simulation

Diagram.

After the reservoir pressure reduces to 2,500 psi, the production rate is approximately 35,740

STB/d depicted in APPENDIX D2 –Pipesim Simulation Diagram. Clearly, water and gas injec-

tion are required to maintain reservoir pressure, thus, sustaining the target production rate as

135,000 STB/d.

WellFlo Sensitivity Analyses

Sensitivity analyses are carried out to identify the key parameters which influence the produc-

tion flow rate. The rate mostly depends on the reservoir permeability, water cut, GOR, skin, tub-

ing size and wellhead pressure. These parameters control the flow rate by controlling both the


Page | 73

inflow and the outflow performances. For the X-field, the parameters that have been analysed in

the sensitivity study are shown in APPENDIX D3 – Wellflo Sensitivity Analyses.

WellFlo Sensitivity Results

By applying the different parameters described above, changes in the production flow rate are

seen. After investigating the result, parameters such as reservoir pressure, effective permeabil-

ity and skin are able to influence the IPR curve. In contrast, changing GOR, tubing size and

wellhead pressure can control the VLP curve. Water cut, however, affects both IPR and VLP in

the way that reduces the production flow rate. It is important that the water cut is under strict

control in order to maintain the target rate. The optimum operating condition can be planned

according to the sensitivity result in order to achieve the highest NPV. APPENDIX D3 – Wellflo

Sensitivity Analyses further illustrates the variation of the parameters analysed affecting the

production rate. The main parameters to take note of are GOR and tubing size. The increasing

ID of the production tubing gives a higher flow rate until a limiting value of 6.52” is reached,

above which there are no operating points. The production GOR, as expected, shows a de-

creasing production rate while increasing.

Gas Lift (IHRDC, 2012)

Gas lift is one of the options which is considered in the X-field. All of the wells operate inside the

operating range of gas lifting (70°).

The flexibility of the system in handling various production rates and the possibility of changing

from continuous to intermittent mode when the reservoir productivity declines makes gas lifting

the best option for the X-field. The high GOR of the oil makes the gas lift more appropriate than

a pump-assisted lift method that is more sensitive to gas production. Furthermore, it can be eas-

ily operated in corrosive environments. Figure 4.4 shows that the gas lift system can deliver

higher flow rates at the same reservoir pressure. The detail of gas lift design is described in

APPENDIX D4 –Gas Lift Design .


Page | 74

When the well is completed, five gas lift valves will be installed but not yet operated, since the

reservoir can flow naturally. Then water and gas injection will be performed to maintain reservoir

pressure. When the pressure declines to 2,500 psi, the well will no longer flow and gas lift will

be required.

Figure 4.4: Gas Lift Performance

Well integrity

1. Sand Production

Sand production is not expected to be a problem at initially (tested up to 20,000 bopd). How-

ever, with the reservoir pressure decline and with increasing water cut, some sand production

can be expected.

Sand control equipment is not initially installed since the well’s productivity will be limited. On

the other hand, when the reservoir depleted and the water cut increases a workover will be re-

quired. Due to their operational advantages, like the simplicity to install and the lower cost com-

pared to other techniques, expandable screens are suggested.

2. Corrosion

Taking into account all the possible type and location of corrosion, corrosion inhibitors must be

planned.

0

5000

10000

15000

20000

25000

30000

35000

0 2000 4000 6000

Base Case

Layer Pressure (psi)

Oil

Pro

du

ctio

n

Rat

e (S

TB/d

)


Page | 75

3. Scale

The risk of scale formation is considered quite high since the water and surface temperature are

very low along the southern coast of Greenland. Two different techniques are proposed. The

first is to equip the surface flow line and surface facilities with insulating material to reduce the

effect of cold. Secondly, it is possible to use solid or liquid scale inhibitors. If the prevention

methods are not effective a removal technique must be employed – a pigging operation can be

performed.

4. Wax and Asphaltene

Under the temperature and pressure condition expected wax and asphaltene build up is likely.

Injection of wax inhibitors, solvents, surfactants or mechanical measures can be taken (e.g.

pigs, scrapers, balls, pistons).

4.4 PRODUCTION AND PROCESS FACILITIES

By evaluating these possible developments it was possible to eliminate some options. It was

found that the GBS like that of the Hibernia field and FPSO such as the Terra Nova and White

Rose FPSOs were the only platforms suitable for the conditions of Greenland to withstand or

avoid iceberg collisions:

Jack-Up Production System: Need to be moved when there is sea ice, resulting in seasonal

production, not an option as it would reduce annual production dramatically.

Gravity Based Structure (GBS): Allows a fixed storage facility to be placed on the seabed built

to endure an iceberg collision. By analysing the GBS used in the Hibernia field it was seen that

the initial outlay to purchase the GBS was too high to make our field profitable, costing US$10

billion. The Hibernia field is much larger than our field and we cannot justify this GBS.

FPSO: for production, processing and storage with extra equipment for iceberg protection and

the ability to disconnect and move off location to avoid destructive icebergs if needed. By ana-


Page | 76

lysing the costs of an iceberg-resistant FPSO from the Terra Nova and White Rose fields it was

found that these were much cheaper to purchase than the GBS – $2.8bn and $3.7bn respec-

tively.. The production profile that is possible results in a positive NPV of the field and a strong

reason for purchase of an FPSO using subsea wells.

4.4.1 FPSO with subsea wells

The unique ice-strengthened FPSO will be developed with subsea wells. This FPSO, which has

a length of 960 feet with a breadth of 149 feet, has a special capability to rapidly disconnect

from its risers and moorings and be taken away from location if it is anticipated that iceberg col-

lision will cause severe damage to vessel and potential risk to human life.

Similar to the Terra Nova field, the X-field will have a comprehensive ice management strategy

based on detection, monitoring, and deflection to prevent icebergs invading in the area in which

the FPSO and production facilities are located. The vessel will be equipped with high-resolution

ice-tracking radar. If a large iceberg moves towards the vessel and a collision with the FPSO is

likely, a standby vessel will attempt to tow it out of the path of the FPSO. (Vessel & ROV News,

2000)

In addition to this, there is a turret mooring system which serves as the mooring point for the

FPSO and allows the vessel to weathervane and disconnect from the riser easily (Vessel &

ROV News, 2000).

Moreover, the design requires the incorporation of some form of protection for the wellheads

due to the scouring action of icebergs which can be destructive. Therefore, the wellheads have

been placed in an ‘open glory hole’ to avoid icebergs colliding with it. This concept has been

effectively utilised in the Terra Nova field. Moreover, any subsea flowlines can be trenched and

backfilled with soil or concrete mats to prevent damage to them (Finch, 1998).

The main specifications of the chosen FPSO are indicated in Table 4.3.


Page | 77

Table 4.3: FPSO specifications

Function Production, processing and storage

Length 960 feet

Beam (Breadth) 150 feet

Height 92 feet

Storage Capacity 1,000,000 bbl

Oil Processing Capacity 150,000 b/d

Gas Processing Capacity 300 MMscf/d

Produced Water Capacity 35,000 b/d

Accommodation 200 people

The main advantages of using the FPSO over other options include:

Mobility: Ability to disconnect from the riser and mooring system and be moved off location.

Cost: Compared with the alternatives for an iceberg environment, FPSOs are cheaper.

Lower Risk: If it is found that the production forecast is overambitious or events in Greenland

make production unfeasible, the FPSO can be sold off to another user. However, it must also be

noted that there are not too many areas where iceberg-resistant FPSOs are needed and so the

company may not recoup as much of the initial cost as desired.

Pipelines: Eliminates the need to lay expensive long distance pipelines to Newfoundland.

4.4.2 Topsides Facilities

Using the Terra Nova FPSO as a comparison, since it has similar recoverable reserves, related

characteristics are needed. The Greenland FPSO has been designed to support a topside pay-

load of about 14,500 Te. The FPSO also supports a combined mooring and turret load of ap-

proximately 3,800 Te.

Facilities comprise of three stage separators (high pressure, intermediate and low pressure).

Wet crude is to be heated between the first and second stage to produce dead crude. Water is

to be further treated using hydrocyclones. The processing scheme is illustrated in Figure 4.5.


Page | 78

Four gas turbines generators with a power requirement of 38 MW are provided, plus two others

for contingency. These are to be located towards the stern of the vessel to keep them away

from the processing facilities and the living quarters as well as provide balance on the vessel.

The reason for generators is to eliminate the huge cost of running power cables from onshore.

Figure 4.5: Water/oil/gas process scheme for the FPSO’s topside facilities

4.4.3 Transportation

The fluids will be processed on board the FPSO and transported using shuttle tankers to the

Newfoundland transshipment terminal, Whiffen Head, located on the northeast edge of

Placentia Bay. Keystone Hardisty terminal in Alberta, which is expected to be in service by

Transcanada by late 2014, should also be investigated.

There is no economics method of exporting the produced gas and government regulations will

not allow us to flare all of the gas that is expected to be produced. Consequently, the produced

gas will be treated to remove associated oil and reinjected back into the reservoir. It has been

found that approximately 15% of the produced oil from similar production rate fields (e.g.

Fulmar) can be used for power generation (Ricketts, 2011).


Page | 79

4.5 PROJECT PLANNING


Page | 80

4.6 ENVIRONMENTAL IMPACT AND ABATEMENT

The environment for the X-field is relatively harsh. There is potential for icebergs, providing a

significant challenge for drilling and assembling the platform. The weather conditions are rela-

tively harsh, with severe waves and poor visibility due to fog. Sea wildlife is prosperous, where

there are many protected species, including blue whales, sperm whales and polar bears. More-

over, there are two nature reserves and a number of protected Important Bird Areas just north

of the X-field. The Greenland area is heavily reliant upon the fishing, whaling and tourism indus-

tries, with a busy shipping lane that passes nearby. All of these have the potential to be im-

pacted upon by operations.

The main major risk is the loss of well control, which may lead to a blow-out. This may result in

fires, causing a loss of capital and even loss of life. An Oil Pollution Emergency Plan (OPEP)

should be prepared. An emergency response plan will be implemented and a fire fighting sys-

tem should be set up.

There were also three moderate risks indicated. The waste discharged to sea, the noise gener-

ated by the planned 3D seismic survey and oil spills to sea. These risks will lead to the pollution

of fresh water, the disturbance of sea mammals and cause soil contamination. The mitigation

methods can be summarised as:

Any discharged chemicals should be collected at surface;

In accordance with principles within the Joint Nature Conservation Committee (JNCC) pro-

tocol, Marine Mammal Observers (MMO) and Passive Acoustic Monitoring (PAM) tech-

niques should be used;

Oil spill discharges to sea should be <15ppm;

Build an oil spill model.


Page | 81

4.7 ABANDONMENT

The aim is to: avoid contamination; maximise the reuse of items; minimise emissions; and

minimise the effect to other sea users. It has been estimated that the cost of abandonment

will be USD 300 million.

FPSO: The FPSO will be disconnected from the flexible risers and moved away from the

location. It will be brought to a port to be scrapped.

Wells: The casings, tubings and Xmas trees will be recovered to surface for either reuse or

recycling. The wells themselves will be plugged and abandoned, with the casing strings cut

a minimum of ten feet below the seabed.

Pipelines and Umbilicals: Those lying on the seabed will be either taken to surface and

reused or recycled or they may be buried under the seabed.

Seabed Structures: All seabed structures will be recovered to surface and taken onshore

for possible reuse or recycling. The subsea manifolds, which are piled into the ground,

should be cut with a minimum of 0.6 metres below the seabed.

Flexible Risers: Cleaned, flushed and retrieved to surface for reuse or recycling.

4.8 ECONOMICS AND COMMERCIAL CONSIDERATIONS

It is noted that the national oil company of Greenland, Nunaoil, has an equity stake of 12.5% in

the field. Consequently, all calculations of NPV should then be altered to only reflect Mungo

Energy’s interest in the field (87.5%).

4.8.1 Company Corporate Profile

Mungo Energy is leading international explorer with strong experience in Africa, particularly

Ghana and upcoming production in Uganda and Senegal, with 88% of the company’s NPV


Page | 82

there. The company’s growth strategy is centred on exploration and is currently undertaking a

large-scale investment process, illustrated by its exploration budget of USD 800 million in 2012.

4.8.2 Assumptions for Cash Flow Modelling

When constructing the cash flow model a number of assumptions were required to be made to

get an understanding of the economics of the project.

Oil Price: Set at $80/bbl in 2012 terms as a base case for the economic analysis. However,

variations of this were then applied as a sensitivity analysis to possible worldwide events that

may alter the price of oil. It was decided to include a low value of $50/bbl because future oil re-

serves are going to be produced from technologically challenging environments (i.e. deepwater

Brazil, Arctic sea, etc) ruling out the possibility of a low price of oil. A maximum of $150/bbl was

set. The price of gas is not considered here gas sales are not feasible in the region. This may

be the sale of gas becomes profitable.

Discount Rate: A rate of 10% nominal is then applied when calculating the NPV of the project

as a base case. Similarly, variations on this discount rate will be carried out to account for de-

viations in investment opportunities through time.

Depreciation: According to the regimes used in Greenland the capital costs are depreciated on

a 30% declining balance basis.

Abandonment: By analysing fields in the same region using similar iceberg-resistant FPSOs

(i.e. the Terra Nova and White Rose fields) and comparing with the estimates given by Que$tor

an abandonment cost of US$318 million has been estimated after the final year of production.

This included an uplift of 1.5 times the initial. These estimates are indicated in Table 4.4. The

range used for the abandonment costs is from $200 million to $1,000 million.


Page | 83

Table 4.4: Estimated abandonment and Opex costs of FPSOs of similar fields and from Que$tor (Oberstoetter, 2011)

Cost Terra Nova

FPSO

White Rose

FPSO

Que$tor Es-

timate

Estimated Abandonment for

Field (maximum times 1.5)

Abandonment US$ 212m US$ 173m US$ 170m US$ 318 m

Opex US$

149m/year

US$

127m/year

US$

100m/year US$ 220 m/year

Opex: A total operating cost was estimated using Que$tor and by analysing similar fields for

the field lifetime and an average was taken yearly, again including a 1.5 times uplift, as illus-

trated in Table 4.4

Transportation: Similarly, the cost of transporting the produced oil to the oil terminal was as-

sumed to be relatively similar to the Terra Nova and White Rose fields (both $2.75/bbl). An uplift

of 1.25 times was used to generate a tariff charge of $3.40/bbl. It was decided that this tariff

would not drop much below the $2.75/bbl rate discussed above and, therefore, it may vary be-

tween $2.50/bbl to $4.00/bbl.

Provision for Oil Spills: Since the field is isolated and there are no other companies operating

nearby it is important to consider the economics of an oil spill and whether Mungo Energy is

capable of covering any possible costs. An estimated $20 million per year is included in the sys-

tem to account for needed standby skimmers and ships that can be used in the case of an oil

spill.

Furthermore, it has been assumed that Mungo Energy uses a stand-alone model. This is a con-

servative approach that is usually taken by companies to ensure that the worst-case scenario is

always simulated.

4.8.3 Fiscal Regime

Bonus, Rentals and Fees: Annual rental fee of DKK 1,000,000 (Danish krone) is payable to

the Bureau of Minerals and Petroleum (BMP) as part of a production bonus.


Page | 84

Corporate Income Tax: Income tax is imposed at a base rate of 30%, with a 6% surcharge,

taking the total corporate tax rate to 31.6%, after taking royalties. However, it is also considered

that Greenland’s fiscal regime is relatively under-developed. This leads to some uncertainty in

how the fiscal regime may work in the future. Therefore, some sensitivity analysis on this taxa-

tion range is required to fully evaluate the economics of the field. It is suggested that Greenland

has already set relatively competitive taxes to attempt to encourage investment in the oil and

gas sector. Consequently, it is not envisaged that the tax rate will drop significantly in the near

future. From analysing the tax progression of other countries that have just started oil produc-

tion (e.g. Brazil and the UK) it can be seen that as production increases the tax system often

becomes more complicated and tax rates tend to increase. Therefore, we must a run sensitivity

to analyse the effect of a significantly higher tax rate (up to 70%).

Royalty: A surplus royalty is levied from the annual pre-tax rate of return. It is an accumulative

rate that increases with increasing levels of pre-tax rate of returns as illustrated in Table 4.5.

We then need to add the official Danish discount rate set by the Danish Central Bank, National-

banken. This was set at 2.0% to try and account for the low discount rate currently due to the

global financial crisis.

Table 4.5: Surplus royalty rate applied to companies in Greenland

Surplus Royalty Rate Pre-Tax Rate of Return Tiers

0% 0% – 23.75%

7.5% 23.75% – 31.25%

17.5% 31.25% – 38.75%

30% > 38.75%

4.8.4 Sensitivity Analysis

By analysing the spider diagram, illustrated in Figure 4.6, we are able to see that the uncertain-

ties which are most vital to the calculation of NPV are the oil price, the recovery factor, the tax

rate, the FPSO cost, the discount rate and exchange rate used. The remaining sensitivities

have minimal effect on the NPV of the field and will, therefore, not be investigated any further.


Page | 85

Figure 4.6: Spider diagram indicating the most important uncertainties when calculating NPV

Of these uncertainties the oil price, the tax rate and the discount rate are all almost completely

out with the control of the company (barring any pressure on the government to reduce taxes,

etc). Therefore, it is instrumental for the company to focus on the FPSO cost and the recovery

factor to ensure that the project does not become uneconomical. The recovery factor is over-

seen by the reservoir and production engineers.

Figure 4.7: Variation of NPV due to varying oil price from base case ($80/bbl)

It will be useful to find the oil price where the project becomes uneconomical. Due to the high

operating costs of the FPSO and the high Capex required to purchase the custom FPSO, the

break even oil price is relatively high at $68/bbl, as illustrated in Figure 4.7. However, it is noted

that if the oil price decreases it is likely that the cost of the X-field FPSO will also decrease.


Page | 86

Therefore, it is essential to run sensitivities on both the cost of the FPSO and the oil price to see

what price the field becomes uneconomical. Assuming a linear relationship between the reduc-

tion of oil price and reduction in FPSO cost, Figure 4.8 clearly illustrates a significant difference

in the minimum oil price to break even. Using this assumption, the oil price needed to break

even is $39/bbl, considerably lower than the first estimate.

Figure 4.8: Variation of NPV due to varying oil price with a linear relationship between oil price

and FPSO cost

4.8.5 Alternative Development Plans

For the development of the X-field in Greenland only two alternatives were considered to be

feasible: a GBS and an FPSO. A lease was initially thought to be the best scenario to reduce

risk. However, it was concluded that it is highly unlikely that an iceberg-resistant FPSO will be

available to lease. Hence, purchasing was the only option for the FPSO. Economic analysis of

the alternatives were considered and the results are listed in Table 4.6. It was assumed that an

FPSO with 200,000 bopd capacity costs 50% more than the 135,000 bopd capacity FPSO.

Clearly, the GBS structure has far too high an initial Capex and results in a negative NPV and a

substantial MCO.


Page | 87

Table 4.6: Economic analysis of different development types

Development Type NPV MCO IRR Payback Period

USD millions USD millions % Years

GBS -4,166 10,879 -1 Never

FPSO (135,00 bopd) 1,008 4,050 14 9

FPSO (200,00 bopd) 720 5,851 13 8

The IRR is a measure of project efficiency and it indicates which project will provide a higher

rate of return throughout the project field life. However, the issue with IRR is that it is sensitive

to the timing of cash flows, indicating that it is not the best way to compare these projects since

each alternative will run for different field lives.

The NPV is a measure of the profitability of the field. It vital for Mungo Energy because it repre-

sents the increase in cash to the company, indicating an increase in value for shareholders.

Since Mungo Energy is embarking on a large-scale investment process, it is vital for the project

to have as quick a payback period as possible to ensure the cash flow starts to become positive

as quickly as possible. Although the 200,000 bopd FPSO has a shorter payback period than the

135,000 bopd FPSO, it is only shorter by one year and an extra 29% added to the NPV out-

weighs this advantage. Moreover, since it has a significantly lower MCO then the outlay re-

quired from the company is much less, reducing the initial risk and reducing the pressure on the

already high exploration budget. Therefore, the 135,000 bopd capacity FPSO was chosen as

the development plan. The sample cash flow for this base case is illustrated in APPENDIX E –

ECONOMIC PART.

Since Mungo Energy is undertaking this large-scale investment process the MCO indicated by

the available alternatives may be too large for the company to consider this project with just the

12.5% NunaOil equity stake. Therefore, it should be recommended that the company should

consider sharing the risk and initial Capex with other oil companies. To reduce the MCO to a

value below USD 1,000 million, 80% equity stake should be split out amongst other operators.


Page | 88

This has the advantage that Mungo Energy will still gain massive invaluable experience in the

emerging Greenland basin yet still return a strong NPV (USD 230 million).

4.8.6 Commercial Awareness

The X-field project includes a number of advantages to Mungo Energy that will lead to a com-

mercial benefit to its employees and shareholders:

Diversification: 88% of company NPV is in Africa with 60% in Ghana alone. Diversifying their

assets to include different areas of the world will act to reduce their dependence on Africa.

Value Creation: Mungo Energy has a strong track record in multiple countries, proving its ex-

cellence in creating value in a number of countries around the world.

Emerging Play: A strategic focus on emerging plays, where technical ability and dynamism are

more important than financial clout. Greenland fits into this focus perfectly since there has been

no commercial hydrocarbons production to date.

Long Lifetime Field: Mungo Energy is currently relying on a small number of oil projects with

fast depletion rates. This tends to cause the length of noted recoverable reserves to be rela-

tively low. Since this field has an expected lifetime of approximately twenty years, it will contrib-

ute to extending the reserves life.

Light Oil: Strategic focus on light oil. The X-field oil fits perfectly into this strategy with 40 ºAPI.

Potential for Future Discoveries: Greenland is thought to hold vast resources but has yet to

be commercially proved. The first commercial production may lead to vast amounts of experi-

ence and a possible snowball effect in terms of investment in Greenland, which Mungo is in

prime position to exploit with its gained experience.

It is also vital to consider ways in which the project may not fit in with Mungo Energy’s strategic

focus:


Page | 89

Lack of Experience: Mungo Energy has had no experience in any sort of activity in Greenland

and may, therefore, not be in the best position to attempt to exploit any reserves in the area.

Possibly a joint venture with another company with experience (e.g. Cairn Energy) would be a

more suitable idea.

No Local Gas Market – Greenland is the least dense country in the world, with a population

with only approximately 55,000 people, and does not have extensive industrial activity. There-

fore, there is unlikely to be much of a market for the gas produced locally. Moreover, there is not

a market close by that is in need of any gas. The USA is becoming a net exporter of gas with

the shale gas production and Canada is the world’s third largest producer and exporter of gas.

The next closest region is Northern and Western Europe. However, they are vast distances

away and it is expensive to transport gas, requiring pipelines or liquefied natural gas (LNG) fa-

cilities.

No Local Production: There has been no commercial production of any hydrocarbons in

Greenland and, therefore, there is no local production facilities or networks which could be util-

ised. As the first commercial field, Mungo would have to ensure all facilities are set up before

production starts.

Large-Scale Investment Process: Mungo Energy is currently in the process of a large-scale

investment process to increase worldwide production from 80,000 boepd to 270,000 boepd by

2020. Consequently, it may not be a good time to be taking on a large-scale, high risk project.

However, the company does state that it is in a strong position to be able to double the size of

the company without problems of over-extending themselves.


Page | 90

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Wood Mackenzie: http://www.woodmacresearch.com/cgi-bin/wmprod/ups/country.xpg?id=-

600263064&BV_SessionID=021CDD94FF4E3AAF1D4AC8C63A5AE130.wmprod-01-

node1&BV_EngineID=no-engine

Schlumberger. (2011). Petrel 2011.1 Help Manual.

Shanmugam, G. (1997). The Bouma Sequence and the Turbidite Mind Set. Earth Science

Reviews 42 , 2012-229.

Slagle, K. A. (1962). Rheological Design of Cementing Operations. SPE , 323-326.

T.W.,et al (1992). Field Testing of a Cationic Polymer/Brine Drilling Fluid in the North Sea. SPE ,

425-434.

Valenti, N. P. (1986). Numerical Simulation of the North Sea Oil Field: Evaluating Reservoir

Depletion Strategies. SPE 15871 .

Vessel & ROV News. (22. March 2000). Abgerufen am 6. June 2012 von Offshore Shipping

Online: www.oilpubs.com/oso/article.asp?v1=4533


Page | 92

6 APPENDICES

6.1 APPENDIX A – GEOLOGICAL PART

6.1.1 APPENDIX A1 – Petrophysical Summary of Six Appraisal Wells

X1 Interval(TVDSS/ft) Average sand Thickness/ft

Average Ø

Average Sw

Average Vsh

Average NTG

layer1 10124-10247 13.25 0.2701 0.133 0.0918 0.215

layer2 10247-10429 176 0.2978 0.0337 0.0096 0.97

layer3 10429-10503 37 0.1925 0.0362 0.102 0.99

layer4 10503-10667 164 0.2678 0.0276 0.0159 1

layer5 10667-11149 23.7778 0.2024 0.2962 0.1476 0.89


Average Ø

Average Sw

Average Vsh

Average NTG

layer1 10447-10487 0 0 0 0 0

layer2 10487-10627 0.5 0.1064 0.6969 0.376 0.004

layer3 10627-10669 40.5 0.2945 0.0893 0.0404 0.96

layer4 10669-10766 25.5 0.2974 0.107 0.1383 0.8

layer5 10766-11320 8 0.2433 0.5822 0.1213 0.215


Average Ø

Average Sw

Average Vsh

Average NTG

layer1 10184-10262 0 0 0 0 0

layer2 10262-10418 172.5 0.2504 0.1283 0.003 1

layer3 10418-10531 127 0.2412 0.1989 0.0131 1

layer4 10531-10711 206 0.2677 0.1229 0.0028 1

layer5 10711-10963 45.5 0.2234 0.303 0.0098 0.95


Average Ø

Average Sw

Average Vsh

Average NTG

layer1 10228-10331 106.5 0.2348 0.1244 0.168 0.93

layer2 10331-10449 131 0.2615 0.041 0.1279 1

layer3 10449-10543 104 0.2561 0.0723 0.1941 1

layer4 10543-10775 257 0.2795 0.036 0.0918 1

layer5 10775-11246 16.9815 0.2383 0.3869 0.0493 0.88


Average Ø

Average Sw

Average Vsh

Average NTG

layer2 10019-10181 1.3636 0.21 0.6111 0.1146 0.0565

layer3 10181-10268 10.9615 0.2729 0.5122 0.0456 0.57

layer4 10268-10462 0 0 0 0 0

layer5 10462-10943 0 0 0 0 0


Average Ø

Average Sw

Average Vsh

Average NTG

layer2 10088-10126 12.1667 0.1556 0.3094 0.0655 0.89

layer3 10126-10298 189 0.2514 0.0869 0.0017 1

layer4 10298-10502 44.6 0.197 0.2523 0.0672 0.98

layer5 10502-11035 6.7188 0.1938 0.4508 0.0636 0.36


Page | 93

6.1.2 APPENDIX A2 – Composite Logs of Six Appraisal Wells

Well X1 Composite Log


Page | 94



Page | 95



Page | 96



Page | 97



Page | 98



Page | 99

6.2 APPENDIX B – RESERVOIR ENGINERING PART

6.2.1 APPENDIX B1 – Special Core Analysis Summary of Core Plugs from Wells

X1, X4 and X5

Mercury-Air Capillary Pressure

Well X1

0

200

400

600

800

1000

1200

1400

1600

0 10 20 30 40 50 60 70 80 90 100

PC

Hg

/Air

(psi

)

Sw (%)


X1, #59 (Por 22.9%, Perm 49mD)

X1, #71 (Por 28.2%, Perm 490mD)

X1, #111 (Por 30.0%, Perm 2600mD)

X1, #151 (Por 28.5%, Perm 3400mD)

X1, #174 (Por 19.4%, Perm 90mD)

X1, #208 (Por 14.9%, Perm 63mD)

X1, #258 (Por 26.0%, Perm 1000mD)

X1, #302 (Por 20.8%, Perm 240mD)

X1, #345 (Por 24.4%, Perm 620mD)

X1, #392 (Por 25.2%, Perm 380mD)

X1, #444 (Por 17.3%, Perm 85mD)

X1, #479 (Por 23.1%, Perm 69mD)

X1, #527 (Por 21.1%, Perm 110mD)

0

10

20

30

40

50

60

70

80

0 10 20 30 40 50 60 70 80 90 100

PC

OW

(psi

)

Sw (%)

Oil-Water Capillary Pressure Curve of Well X1

X1, #59 (Por 22.9%, Perm 49mD)

X1, #71 (Por 28.2%, Perm 490mD)

X1, #111 (Por 30.0%, Perm 2600mD)

X1, #151 (Por 28.5%, Perm 3400mD)

X1, #174 (Por 19.4%, Perm 90mD)

X1, #208 (Por 14.9%, Perm 63mD)

X1, #258 (Por 26.0%, Perm 1000mD)

X1, #302 (Por 20.8%, Perm 240mD)

X1, #345 (Por 24.4%, Perm 620mD)

X1, #392 (Por 25.2%, Perm 380mD)

X1, #444 (Por 17.3%, Perm 85mD)

X1, #479 (Por 23.1%, Perm 69mD)

X1, #527 (Por 21.1%, Perm 110mD)


Page | 100

Well X4

y = 2513.6x-1.902

0

100

200

300

400

500

600

0 10 20 30 40 50 60 70 80 90 100

Dim

en

sio

nle

ss J

Fun

ctio

n

Sw (%)


X1, #59 (Por 22.9%, Perm 49mD)

X1, #71 (Por 28.2%, Perm 490mD)

X1, #111 (Por 30.0%, Perm 2600mD)

X1, #151 (Por 28.5%, Perm 3400mD)

X1, #174 (Por 19.4%, Perm 90mD)

X1, #208 (Por 14.9%, Perm 63mD)

X1, #258 (Por 26.0%, Perm 1000mD)

X1, #302 (Por 20.8%, Perm 240mD)

X1, #345 (Por 24.4%, Perm 620mD)

X1, #392 (Por 25.2%, Perm 380mD)

X1, #444 (Por 17.3%, Perm 85mD)

X1, #479 (Por 23.1%, Perm 69mD)

X1, #527 (Por 21.1%, Perm 110mD)


0

100

200

300

400

500

600

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00

Dim

en

sio

nle

ss J

Fun

ctio

n

Sw*


X1, #59 (Por 22.9%, Perm 49mD)

X1, #71 (Por 28.2%, Perm 490mD)

X1, #111 (Por 30.0%, Perm 2600mD)

X1, #151 (Por 28.5%, Perm 3400mD)

X1, #174 (Por 19.4%, Perm 90mD)

X1, #208 (Por 14.9%, Perm 63mD)

X1, #258 (Por 26.0%, Perm 1000mD)

X1, #302 (Por 20.8%, Perm 240mD)

X1, #345 (Por 24.4%, Perm 620mD)

X1, #392 (Por 25.2%, Perm 380mD)

X1, #444 (Por 17.3%, Perm 85mD)

X1, #479 (Por 23.1%, Perm 69mD)

X1, #527 (Por 21.1%, Perm 110mD)

0

200

400

600

800

1000

1200

1400

1600

0 10 20 30 40 50 60 70 80 90 100

PC

Hg

/Air

(psi

g)

Sw (%)


X4, #4 (Por 27.3%, Perm 35mD)

X4, #31 (Por 20.7%, Perm 29mD)

X4, #39 (Por 24.8%, Perm 140mD)

X4, #62 (Por 22.4%, Perm 1700mD)

X4, #73 (Por 23.8%, Perm 2100mD)

X4, #110 (Por 25.5%, Perm 650mD)

X4, #139 (Por 27.0%, Perm 300mD)

X4, #162 (Por 17.3%, Perm 11mD)

X4, #201 (Por 21.1%, Perm 92mD)

X4, #225 (Por 27.4%, Perm 2300mD)

X4, #258 (Por 28.5%, Perm 1900mD)

X4, #286 (Por 21.1%, Perm 120mD)

X4, #319 (Por 25.6%, Perm 1000mD)

X4, #359 (Por 26.4%, Perm 960mD)

X4, #393 (Por 27.0%, Perm 220mD)

X4, #421 (Por 24.9%, Perm 1400mD)

X4, #456 (Por 16.8%, Perm 100mD)

X4, #496 (Por 25.5%, Perm 1300mD)

X4, #523 (Por 14.2%, Perm 68mD)

X4, #559 (Por 23.2%, Perm 970mD)


Page | 101

0

10

20

30

40

50

60

70

80

0 10 20 30 40 50 60 70 80 90 100

PC

OW

(psi

)

Sw (%)


X4, #4 (Por 27.3%, Perm 35mD)

X4, #31 (Por 20.7%, Perm 29mD)

X4, #39 (Por 24.8%, Perm 140mD)

X4, #62 (Por 22.4%, Perm 1700mD)

X4, #73 (Por 23.8%, Perm 2100mD)

X4, #110 (Por 25.5%, Perm 650mD)

X4, #139 (Por 27.0%, Perm 300mD)

X4, #162 (Por 17.3%, Perm 11mD)

X4, #201 (Por 21.1%, Perm 92mD)

X4, #225 (Por 27.4%, Perm 2300mD)

X4, #258 (Por 28.5%, Perm 1900mD)

X4, #286 (Por 21.1%, Perm 120mD)

X4, #319 (Por 25.6%, Perm 1000mD)

X4, #359 (Por 26.4%, Perm 960mD)

X4, #393 (Por 27.0%, Perm 220mD)

X4, #421 (Por 24.9%, Perm 1400mD)

X4, #456 (Por 16.8%, Perm 100mD)

X4, #496 (Por 25.5%, Perm 1300mD)

X4, #523 (Por 14.2%, Perm 68mD)

X4, #559 (Por 23.2%, Perm 970mD)

0

50

100

150

200

250

300

350

400

450

500

0 10 20 30 40 50 60 70 80 90 100

Dim

en

sio

nle

ss J

Fun

ctio

n

Sw (%)

Leverett J Function Curve of Welll X4

X4, #4 (Por 27.3%, Perm 35mD)

X4, #31 (Por 20.7%, Perm 29mD)

X4, #39 (Por 24.8%, Perm 140mD)

X4, #62 (Por 22.4%, Perm 1700mD)

X4, #73 (Por 23.8%, Perm 2100mD)

X4, #110 (Por 25.5%, Perm 650mD)

X4, #139 (Por 27.0%, Perm 300mD)

X4, #162 (Por 17.3%, Perm 11mD)

X4, #201 (Por 21.1%, Perm 92mD)

X4, #225 (Por 27.4%, Perm 2300mD)

X4, #258 (Por 28.5%, Perm 1900mD)

X4, #286 (Por 21.1%, Perm 120mD)

X4, #319 (Por 25.6%, Perm 1000mD)

X4, #359 (Por 26.4%, Perm 960mD)

X4, #393 (Por 27.0%, Perm 220mD)

X4, #421 (Por 24.9%, Perm 1400mD)

X4, #456 (Por 16.8%, Perm 100mD)

X4, #496 (Por 25.5%, Perm 1300mD)

X4, #523 (Por 14.2%, Perm 68mD)

X4, #559 (Por 23.2%, Perm 970mD)

y = 0.5126x-1.203

R² = 0.945

0

20

40

60

80

100

120

140

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00

Dim

en

sio

nle

ss J

Fun

ctio

n

Sw*


X4, #4 (Por 27.3%, Perm 35mD)

X4, #31 (Por 20.7%, Perm 29mD)

X4, #39 (Por 24.8%, Perm 140mD)

X4, #62 (Por 22.4%, Perm 1700mD)

X4, #73 (Por 23.8%, Perm 2100mD)

X4, #110 (Por 25.5%, Perm 650mD)

X4, #139 (Por 27.0%, Perm 300mD)

X4, #162 (Por 17.3%, Perm 11mD)

X4, #201 (Por 21.1%, Perm 92mD)

X4, #225 (Por 27.4%, Perm 2300mD)

X4, #258 (Por 28.5%, Perm 1900mD)

X4, #286 (Por 21.1%, Perm 120mD)

X4, #319 (Por 25.6%, Perm 1000mD)

X4, #359 (Por 26.4%, Perm 960mD)

X4, #393 (Por 27.0%, Perm 220mD)

X4, #421 (Por 24.9%, Perm 1400mD)

X4, #456 (Por 16.8%, Perm 100mD)

X4, #496 (Por 25.5%, Perm 1300mD)

X4, #523 (Por 14.2%, Perm 68mD)

X4, #559 (Por 23.2%, Perm 970mD)



Page | 102

Well X5

0

200

400

600

800

1000

1200

1400

1600

0 10 20 30 40 50 60 70 80 90 100

PC

Hg

/Air

(psi

g)

Sw (%)


X5, #1 (Por 11.3%, Perm 1mD)

X5, #22 (Por 17.6%, Perm 320mD)

X5, #66 (Por 22.6%, Perm 100mD)

X5, #89 (Por 19.0%, Perm 1mD)

X5, #119 (Por 18.6%, Perm 6mD)

X5, #148 (Por 23.6%, Perm 670mD)

X5, #150 (Por 16.2%, Perm 1mD)

X5, #185 (Por 26.6%, Perm 1800mD)

X5, #219 (Por 26.3%, Perm 2000mD)

X5, #254 (Por 27.4%, Perm 3600mD)

X5, #281 (Por 24.8%, Perm 870mD)

X5, #296 (Por 23.1%, Perm 350mD)

X5, #331 (Por 16.2%, Perm 38mD)

0

10

20

30

40

50

60

70

80

0 10 20 30 40 50 60 70 80 90 100

PC

OW

(psi

g)

Sw (%)


X5, #1 (Por 11.3%, Perm 1mD)

X5, #22 (Por 17.6%, Perm 320mD)

X5, #66 (Por 22.6%, Perm 100mD)

X5, #89 (Por 19.0%, Perm 1mD)

X5, #119 (Por 18.6%, Perm 6mD)

X5, #148 (Por 23.6%, Perm 670mD)

X5, #150 (Por 16.2%, Perm 1mD)

X5, #185 (Por 26.6%, Perm 1800mD)

X5, #219 (Por 26.3%, Perm 2000mD)

X5, #254 (Por 27.4%, Perm 3600mD)

X5, #281 (Por 24.8%, Perm 870mD)

X5, #296 (Por 23.1%, Perm 350mD)

X5, #331 (Por 16.2%, Perm 38mD)

0

100

200

300

400

500

600

0 10 20 30 40 50 60 70 80 90 100

Dim

en

sio

nle

ss J

Fun

ctio

n

Sw (%)


X5, #1 (Por 11.3%, Perm 1mD)

X5, #22 (Por 17.6%, Perm 320mD)

X5, #66 (Por 22.6%, Perm 100mD)

X5, #89 (Por 19.0%, Perm 1mD)

X5, #119 (Por 18.6%, Perm 6mD)

X5, #148 (Por 23.6%, Perm 670mD)

X5, #150 (Por 16.2%, Perm 1mD)

X5, #185 (Por 26.6%, Perm 1800mD)

X5, #219 (Por 26.3%, Perm 2000mD)

X5, #254 (Por 27.4%, Perm 3600mD)

X5, #281 (Por 24.8%, Perm 870mD)

X5, #296 (Por 23.1%, Perm 350mD)

X5, #331 (Por 16.2%, Perm 38mD)


Page | 103

Residual/Oil Saturation obtained in toluene/air imbibition experiments (counter current

imbibition)

Well X1

Sample No. Depth Porosity Permeability Residual saturation at initial saturation of

(ft) (%) (mD) 50% 75% 100%

59 10330.4 22.9 49 33 - 33

62 10333.2 24.8 3.9 15 - 15

776 10348.5 24.7 190 28 - 29

113 10385 27.3 680 30 - 30

150 10487.3 27.3 3600 - 21 22

190 10523.9 20.8 380 32 32 33

234 10565.3 16.3 69 32 35 35

279 10608.1 24.9 720 36 - 28

323 10647.6 27.9 1000 26 - 25

368 10690 28.6 2400 - 19 20

410 10778.9 18.9 250 - 39 41

456 10772.9 24.1 630 31 - 31

500 10965.7 22.1 270 32 33 34

550 11012.7 20.1 380 - 38 41

y = 0.1696x-1.844

R² = 0.9468

0

50

100

150

200

250

0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.70 0.80 0.90 1.00

Dim

en

sio

nle

ss J

Fun

ctio

n

Sw*


X5, #1 (Por 11.3%, Perm 1mD)

X5, #22 (Por 17.6%, Perm 320mD)

X5, #66 (Por 22.6%, Perm 100mD)

X5, #89 (Por 19.0%, Perm 1mD)

X5, #119 (Por 18.6%, Perm 6mD)

X5, #148 (Por 23.6%, Perm 670mD)

X5, #150 (Por 16.2%, Perm 1mD)

X5, #185 (Por 26.6%, Perm 1800mD)

X5, #219 (Por 26.3%, Perm 2000mD)

X5, #254 (Por 27.4%, Perm 3600mD)

X5, #281 (Por 24.8%, Perm 870mD)

X5, #296 (Por 23.1%, Perm 350mD)

X5, #331 (Por 16.2%, Perm 38mD)



Page | 104

Well X5


(ft) (%) (mD) 50% 75% 100%

5 10658.3 21.9 5.3 31 36 39

29 10701.1 18.7 36 34

35

64 10741.8 20.2 6.5 26

27

103 10795.5 24.6 10 25

27

127 10822.9 19.8 24 32

33

146 10844.3 22.2 320 35

35

155 10885.3 20.9 21 28

30

191 10925.4 26.4 890 28 34 34

222 10965 26.1 1600 24 26 29

250 10996.9 26.4 1900 28

28

276 11033.1 25.3 1000 28

29

283 11094.4 25.7 2000 19 26 26

299 11138.2 17.1 7.1 27

30

334 11185.4 20.3 97 35

36

Well X4


(ft) (%) (mD) 50% 75% 100%

9 11491.6 26.5 7.3 29 - 33

32 11549.5 23.1 67 33 - 34

59 11591.9 24 2800 37 - 29

68 11632 26.3 540 28 - 32

95 11672 24.7 1600 29 - 30

127 11713.4 23 8.8 31 34 36

151 11750.6 25.8 210 30 - 33

181 11790.2 23.2 23 26 - 28

219 11832 26.8 2000 31 - 32

244 11870.2 25.4 1500 26 - 30

271 11913 28.7 2000 32 - 33

306 11953.9 25.4 1300 34 - 35

340 11992.2 26.9 1000 30 - 32

375 12032.2 24.9 290 31 - 34

410 12071.1 14.2 62 25 - 25

445 12112.8 21.8 240 29 - 35

479 12150.2 26.1 740 30 - 33

515 12190.5 24.9 1000 30 - 32

548 12232.2 15.1 9.5 29 - 34

573 12263.3 21.9 690 26 - 30


Page | 105

3-phases relative permeability data of the Northern Compartment

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Krw

&K

ro

Sw

Water-Oil Relative Permeability Data (Northern Compartment)

Krw (Por>27, K>1000mD, OWC10560ftss, ribble sand)

Kro (Por>27, K>1000mD, OWC10560ftss, ribble sand)

Krw (22<Por<25, 500mD<K<1000mD, OWC10560ftss, mersey&lydell sand)

Kro (22<Por<25, 500mD<K<1000mD,

OWC10560ftss, mersey&lydell sand)

Krw (20<Por<23, 10mD<K<50mD, OWC10560ftss, clyde sand)

Kro (20<Por<23, 10mD<K<50mD,

OWC10560ftss, clyde sand)

Krw (20<Por<23, 100mD<K<500mD, OWC10560ftss, usk sand)

Kro (20<Por<23, 100mD<K<500mD,

OWC10560ftss, usk sand)

Krw (20<Por, 10mD<K, OWC10560ftss, forth sand)

Kro (20<Por, 10mD<K, OWC10560ftss, forth sand)

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Kro

&K

rg

So

Oil-Gas Relative Permeability Data (Northern Compartment)


Krg (Por>27, K>1000mD, OWC10560ftss, ribble sand)

Kro (22<Por<25, 500mD<K<1000mD, OWC10560ftss, mersey&lydell sand)

Krg (22<Por<25, 500mD<K<1000mD,


Kro (20<Por<23, 10mD<K<50mD, OWC10560ftss, clyde sand)

Krg (20<Por<23, 10mD<K<50mD,


Kro (20<Por<23, 100mD<K<500mD, OWC10560ftss, usk sand)

Krg (20<Por<23, 100mD<K<500mD,



Krg (20<Por, 10mD<K, OWC10560ftss, forth sand)


Page | 106

3-phases relative permeability data of the Southern Compartment

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Krw

&K

ro

Sw

Water-Oil Relative Permeability Data (Southern Compartment)

Krw (Por>27, K>1000mD, OWC10840ftss, ribble sand)


Krw (22<Por<25, 500mD<K<1000mD, OWC10840ftss, mersey&lydell sand)

Kro (22<Por<25, 500mD<K<1000mD,


Krw (20<Por<23, 10mD<K<50mD, OWC10840ftss, clyde sand)

Kro (20<Por<23, 10mD<K<50mD,


Krw (20<Por<23, 100mD<K<500mD, OWC10840ftss, usk sand)

Kro (20<Por<23, 100mD<K<500mD,


Krw (20<Por, 10mD<K, OWC10840ftss, forth sand)


0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Kro

&K

rg

So

Oil-Gas Relative Permeability Data (Southern Compartment)


Krg (Por>27, K>1000mD, OWC10840ftss, ribble sand)

Kro (22<Por<25, 500mD<K<1000mD, OWC10840ftss, mersey&lydell sand)

Krg (22<Por<25, 500mD<K<1000mD,


Kro (20<Por<23, 10mD<K<50mD, OWC10840ftss, clyde sand)

Krg (20<Por<23, 10mD<K<50mD,


Kro (20<Por<23, 100mD<K<500mD, OWC10840ftss, usk sand)

Krg (20<Por<23, 100mD<K<500mD,



Krg (20<Por, 10mD<K, OWC10840ftss, forth sand)


Page | 107

Water-Oil Capillary Pressure of the Northern and Southern Compartments

6.2.2 APPENDIX B2 – Variations of inputs used to calculate STOIIP in each zone

Zone 1 Min Most Likely Max

Gross Rock Volume 4017.6 5022 5286.316 MMft3

Net to Gross 0.93 0.93 1 frac

Porosity 0.15 0.2 0.24309 frac

Sw 0.1995 0.1287 0.1244 frac

Bo 1.35 1.33 1.32 rb/STB

Recovery Factor 45 55 70 frac

Oil-in place 59.19 108.98 151.81 MMBBLs

Reserves 26.63368285 59.94026443 106.2675 MMBBLS

Oil-in-Place (Monte Carlo) 108.982299




Porosity 0.1596 0.21316666 0.2615 frac

Sw 0.174225 0.1291 0.1025 frac

Bo 1.35 1.33 1.32 rb/STB

0.000

20.000

40.000

60.000

80.000

100.000

120.000

140.000

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1

Pco

w (

psi

)

Sw

Water-Oil Capillary Pressure Data

Pcow (Por>27, K>1000mD, OWC10840ftss, ribble sand)

Pcow (Por>27, K>1000mD, OWC10560ftss, ribble sand)

Pcow (22<Por<25, 500mD<K<1000mD, OWC10840ftss, mersey&lydell sand)

Pcow (22<Por<25, 500mD<K<1000mD, OWC10560ftss, mersey&lydell sand)

Pcow (20<Por<23, 10mD<K<50mD, OWC10840ftss, clyde sand)

Pcow (20<Por<23, 10mD<K<50mD, OWC10650ftss, clyde sand)

Pcow (20<Por<23, 100mD<K<500mD, OWC10840ftss, usk sand)

Pcow (20<Por<23, 100mD<K<500mD, OWC10560ftss, usk sand)

Pcow (20<Por, 10mD<K, OWC10840ftss, forth sand)

Pcow (20<Por, 10mD<K, OWC10560ftss, ush sand)


Page | 108



Reserves 63.56635 150.5566274 266.2445 MMBBLS





Porosity 0.159 0.2011467 0.2356 frac

Sw 0.5122 0.3535555 0.29835 frac

Bo 1.35 1.33 1.32 rb/STB



Reserves 13.30504828 50.97631501 104.143 MMBBLS




Net to Gross 0.873 0.97 1.00 frac

Porosity 0.225 0.26188 0.2974 frac

Sw 0.189225 0.10916 0.107 frac

Bo 1.35 1.33 1.32 rb/STB



Reserves 77.9747 152.7285203 241.9515 MMBBLS





Porosity 0.15 0.176192 0.21897 frac

Sw 0.52398 0.40382 0.34063 frac

Bo 1.35 1.33 1.32 rb/STB



Reserves 20.75816826 59.63395674 162.7138 MMBBLS



Page | 109

6.2.3 APPENDIX B3 – Probabilistic Determination of Reserves


Page | 110

6.2.4 APPENDIX B4 – Sensitivity Analysis of Reservoir Simulation

Run Sensitivity Parameters FOPT

(MMSTB) FOE (%)

1

Number of well and Type

7 Producers (all deviated), 5 Water Injectors, 2 Gas Injectors

477 53.05

2 9 Producers (all deviated), 5 Water Injectors,

2 Gas Injectors 478 53.16





5 6 Producers (4 horizontal and 2 deviated), 5

Water Injectors, 2 Gas Injectors 489 54.40

6 Permeability

Uncorrected air permeability 487 54.23

7 50% of corrected liquid permeability 450 50.02

8 Plateau Production Rate

50% of maximum operating rate (67500 b/d) 451 50.12

9 75% of maximum operating rate (101250 b/d) 474 52.70

10

Pressure Maintenance

Natural Depletion 193 21.46

11 Natural Depletion+Gas Reinjection 262 29.17

12 Natural Depletion+Water Injection 454 50.53

13

Gas reinjection fraction

0.90 478 53.20

14 0.95 466 51.81

15 1.00 450 50.09

16

BHP of injector

5000 psi 464 51.67

17 6000 psi 473 52.66

18 7000 psi 476 52.96

19

Fault Transmissibility

25% 471 52.35

20 50% 470 52.29

21 75% 469 52.23

22 100% 469 52.19

23

Kv/Kh

0.01 368 40.96

24 0.1 427 47.56

25 0.5 466 51.86

26 1 477 53.06

27 Polymer Flooding (polymer viscosity multi-

plier)

2.5 477 53.01

28 5 444 49.36

29 12.5 402 44.73

Note: Base Case: 7 Producers (all deviated), 5 Water injectors, 2 Gas injectors


Page | 111

6.3 APPENDIX C – DRILLING PART

6.3.1 APPENDIX C1- Pressure Distribution

6.3.2 APPENDIX C2 – Fracture Pressure Spreadsheet Calculation

Matthew and Kelly Equation:

Ben Eaton Equation:

Ko = Matrix Stress Coefficient, P = Wellbore Pressure, psi

D = Depth, ft, S = Overburden Stress, psi

V = Poisson’s Ratio, F = Fracture Gradient, psi/ft

Water Depth = 394 ft, Oil Gradient = 0.3 psi/ft

Normal Gradient = 0.47 psi/ft, Kick Factor = 0.5 lb/gal

0

2000

4000

6000

8000

10000

12000

14000

0 2000 4000 6000 8000 10000 12000 14000

Formation Gradient

Mud Gradient

Formation Pressre below Oil OWC

Oil Gradient

Fracture Gradient (Ben Eaton)

Fracture Gradient (Matthew&Kelly)

Pressure (psi)

De

pth

TV

DSS

(ft

)


Page | 112

Matthew & Kelly Approach

Depth TVDSS

Formation Fluid Pressure

Overburden Pressure

Matrix Stress

Depth Equivalent Louisiana South Texas

Fracture Gradient

Fracture Gradient

Fracture Presssure

ft psi psi psi ft Matrix Stress

Coefficient Matrix Stress

Coefficient psi/ft lb/gal psi

0 14.7 0

394 199.88 394 194.12 362.84

1000 484.7 1000 515.3 963.17 0.32 0.42 0.649596 12.49223077 649.596

2000 954.7 2000 1045.3 1953.83 0.4 0.5 0.68641 13.20019231 1372.82

3000 1424.7 3000 1575.3 2944.48 0.46 0.57 0.716446 13.77780769 2149.338

4000 1894.7 4000 2105.3 3935.14 0.51 0.62 0.74210075 14.27116827 2968.403

5000 2364.7 5000 2635.3 4925.79 0.57 0.66 0.7733642 14.87238846 3866.821

6000 2834.7 6000 3165.3 5916.44 0.62 0.705 0.799531 15.37559615 4797.186

7000 3304.7 7000 3695.3 6907.10 0.645 0.74 0.8125955 15.62683654 5688.1685

8000 3774.7 8000 4225.3 7897.75 0.685 0.77 0.833628813 16.03132332 6669.0305

9000 4244.7 9000 4755.3 8888.41 0.72 0.81 0.852057333 16.38571795 7668.516

10000 4714.7 10000 5285.3 9879.06 0.745 0.835 0.86522485 16.63893942 8652.2485

11000 5184.7 11000 5815.3 10869.71 0.76 0.86 0.873120727 16.79078322 9604.328

12000 5654.7 12000 6345.3 11860.37 0.795 0.88 0.891601125 17.14617548 10699.2135

13000 6124.7 13000 6875.3 12851.02 0.82 0.9 0.904803538 17.40006805 11762.446


Page | 113

Ben Eaton Approach

Depth Pore

Pressure Sea bed

Eaton's overburden stress

Equivalent Depth

Actual Fracture depth

Fracture Gra-dient

Fracture presure

Effective Fracture Gradient

Effective Fracture Pressure

ft psi ft psi/ft ft ft lb/gal psi lb/gal psi

0 14.7

394 185.18 0 0.845 156.48 156.48 11.80 96.01 3.91 80.14

1000 484.7 606 0.855 158.33 764.33 11.80 468.99 8.37 487.70

2000 954.7 1606 0.865 160.18 1766.18 12.60 1157.20 10.71 1113.72

3000 1424.7 2606 0.88 162.96 2768.96 13.30 1915.01 11.96 1866.41

4000 1894.7 3606 0.89 164.81 3770.81 14.00 2745.15 12.94 2692.54

5000 2364.7 4606 0.91 168.51 4774.51 14.40 3575.16 13.54 3520.10

6000 2834.7 5606 0.92 170.37 5776.37 15.00 4505.57 14.26 4447.57

7000 3304.7 6606 0.93 172.22 6778.22 15.35 5410.37 14.70 5350.54

8000 3774.7 7606 0.935 173.14 7779.14 15.60 6310.44 15.02 6249.26

9000 4244.7 8606 0.943 174.62 8780.62 16.10 7351.14 15.57 7287.69

10000 4714.7 9606 0.95 175.92 9781.92 16.30 8291.16 15.82 8226.66

11000 5184.7 10606 0.96 177.77 10783.77 16.60 9308.55 16.16 9242.64

12000 5654.7 11606 0.965 178.70 11784.70 16.85 10325.75 16.44 10258.66

13000 6124.7 12606 0.97 179.62 12785.62 17.15 11402.22 16.77 11333.76


Page | 114

6.3.3 APPENDIX C3 – Casing Setting Depth Calculation

Setting Depth Selection for Intermediate Casing

1. Maximum pressure at the total depth of well (11000 ft)

EMW = 10.75+0.3+0.3+0.2 = 11.55 lb/gal

Formation Pressure = 10.75 lb/gal (Actual mud weight)

Trip Margin = 0.3 lb/gal (Actual mud weight)

Surge Pressure = 0.3 lb/gal (Equivalent mud weight)

Safety Factor = 0.2 lb/gal (Equivalent mud weight)

2. Identify the formations that cannot withstand 11.55 lb/gal, then casing must be applied to

protect those formations.

The intersection point is the minimum tentative intermediate casing setting depth (8400 ft).

0

2000

4000

6000

8000

10000

12000

14000

0 2000 4000 6000 8000 10000 12000

Formation Gradient

Formation Pressre below Oil OWC

Oil Gradient

Fracture Gradient (Ben Eaton)

Pressure (psi)

De

pth

TV

DSS

(ft

)

6606 psi

8400 ft

11000 ft


Page | 115

3. It is common to check when running the casing to 8400 ft; the differential pipe sticking

might be occurred. Field studies carried out the typical values for the amount of differential

pressure that can be accepted before sticking happens:

Normal Pressure Zones 2000-2300 psi

Abnormal Pressure Zone 3000-3300 psi

The mud weight needed to drill to 8400 ft is:

Total required mud weight= 9.5 +0.3 (Trip Margin)=9.8 lb/gal

Pressure Difference = (9.8-9)(0.052)(8400)= 350 psi

Since the differential pressre is lower than the critical value, pipe can be run to 8400 ft with-

out the sticking problem., The tentative depth becomes the minimum actual setting depth.

Settign Depth Selection for Surface Casing

1. Determine the maximum pressure at the bottomhole

EWM = 10.75 +0.3+0.3+0.2=11.55 lb/gal

2. Assume that 11.55 lb/gal will be applied and determine differential sticking as follow;

(11.55-9)(0.052)(11000) = 1458.6 psi ˂ 2000 psi ; No pipe sticking

3. Using the fracture gradient curve and kick loading mud weight curve to find the depth

which the fracture gradient exceeds that of the kick.

EMWkick= equivalent mud weight at the depth of interest, lb/gal

Total depth = deepest interval, ft

∆M = incremental kick mud weight increase, lb/gal

OMW = original mud weight, lb/gal


Page | 116

4. A setting depth of 3670 ft is chosen.

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

12000

13000

14000

7.00 8.00 9.00 10.00 11.00 12.00 13.00 14.00 15.00 16.00 17.00 18.00

Fracture Gradient

EMW_Kick

Gradient (lb/gal) D

epth

(ft

)

3670 ft


Page | 117

6.3.4 APPENDIX C4 – Well Schematic Design and Drilling Section Lithology

Depth (ft)

TVD ss Hole Configuration

Hole

Size (in)

Casing

Size (in) Mud Type

694

2394

3670

8400

11000

26

16

12 1/4

8 1/2

18 5/8

13 3/8

9 5/8

7

Seawater/KCl

9.2 lb/gal

Seawater/KCl

9.5 lb/gal

Oil Based

Diesel/Kerosene

10.6 lb/gal


Page | 118

Drilling Section Lithology Ti

me

Litholostrati-

graphy Lithology and Indications

Depths (ft) TVDSS

Drilling Bits

0 Sea level

Qu

ate

rnar

y

soft glauconitic calcareous clay-stones and silt-stones

271 sea bed

Roller cone bits with long and widely space teeth are required to drill this soft part of formation.

Tert

iary

soft marlstones and claystones

9525

Cre

tate

ou

s

Chalk group

limestone

9755

late Cimmerian unconformity

Up

per

Ju

rass

ic

Kimmeridge Clay forma-

tion

shale, fine to coarse well sorted sandstone 10251

PDC bits are suggested since the mud used is OBM, for reducing the number of trips and for the medium to hard nature of the forma-tion.

Fulmar for-mation

medium to very fine well sorted sandstone,

1152

early cimmerian unconformity

Tria

ssic

siltstones and shales

12835


Page | 119

6.3.5 APPENDIX C5 – Cement Calculation Example

Surface Casing

Set 13 3/8 in, 54.5-lb in 16 in hole at 3670 ft. Use API class A cement (Diatomaceous Earth

20%)

Slurry Properties:

Fluid Properties Slurry Drilling Mud

n’ (Fluid flow behaviour index) 0.2 0.47

K’ (Fluid consistency index, lb/secn’ /sq ft) 0.312 0.01

Density (lb/gal) 12.4 9.2

(Slagle, 1962)

1. Determine n‘ and K‘ of drilling mud:

PV = Plastic viscosity, cp

YP = Yield point, lbf/100 ft2

N = The range extension factor of the torque spring

According to the Drilling Engineering Book (Adams, 1985);

PV= 7 cp; YP =11 lbf/100 ft2; N=1

Flow Channels:

Hole Annulus 16 in: De = 2.625 in Area = 0.42 sq. ft

Casing 13 3/8 ; De =12.615 in Area = 0.8679 sq. ft


Page | 120

Critical Velocity for Slurry in Annulus:

Vc= Critical velocity, ft/second

ρ = Slurry density, lb/gal

Frictional Pressure-Drop Calculation:

Cement in pipe

Cement in Annulus


Page | 121

Critical Velocity for Drilling Mud in Annulus

Frictional Pressure-Drop Calculation:

Drilling Mud in Pipe

Drilling Mud in Annulus

Hydraulic Analysis Just Before Bumping Top Plug:

Hydrostatic Pressure in Annulus: Pha=3670 ftx0.49 psi/ft=1798 psi


Page | 122

Hydrostatic Pressure in Casing: Phc=0.645 psi/ftx2417ft+0.49 psi/ftx762 ft= 1932 psi

Total ∆Pf:

127.96x3.895=498 psi

9.78x1.478=14.45 psi

17.76x3.895=69.17 psi

17.12x2.417=41.37 psi

Pw=623+1798-1932= 489 psi

6.3.6 APPENDIX C6-Directional Drilling Well Location and Trajectory

Deviated Well

Well Location:

-6000

-4000

-2000

0

2000

4000

6000

-5000 -3000 -1000 1000 3000 5000

Northing (ft)

Ea

stin

g (ft)

Semi-Submersible Drilling Rig


Page | 123

Well Trajectory Planning:

Calculation:

Parameters: TVD=11000 ft BUR=3°/ft Horizontal Displacement=6561.65 ft

KOD=2000 ft

Maximum angle of hole inclination at end of build:

Total measured depth:

0

2000

4000

6000

8000

10000

12000

-100 900 1900 2900 3900 4900 5900 6900

Horizontal Departure (ft)

TV

D (

ft)


Page | 124

6.3.7 APPENDIX C8 – Casing Design Calculation Example (Adams, 1985)

Surface Casing Design

Depth = 3670 ft Casing seat Fracture gradient 12.62 lb/gal

Pipe size=13 3/8 in Cement density from 0-3370 ft =12.4 lb/gal

Cement density from 3370-3670 ft = 15.6 lb/gal

1. Create the burst load line

Injection pressure =(12.62+1)lb/galx0.052x3670ft=2599.24 psi

Surface pressure =injection pressure-gas hydrostatic pressre

=2599.24-3670ft(0.115psi/ft)=1855.95 psi

2. Create the backup line by using 9 lb/gal formation fluid as the worst case of density

degradation

Top= 0 psi

Bottom=3670 ftx0.052x9l b/gal =1717.56 psi

3. The resultant is:

Resultant = load-backup

Top= 1855.95-0=1855.95 psi

Bottom=2599.24-1717.56=841.68 psi

4. Apply a design factor of 1.1 to creat the design line:

Top=1855.95x1.1=2041.545 psi

Bottom=841.68x1.1=925.85 psi


Page | 125

The maximum pressure require for the design is 2041 psi. A suitable weight and grade is

54.5-lb/ft, J-55 grade pipe.

5. The collapse load line is created with cement in the annulus:

3370 ftx0.052x12.4 lbgal =2172.976 psi

300 ftx0.052x15.6 lb/gal=243.36

Total collapse load = 2172.976+243.36=2416.36 psi

Since the pipe is designed with no collapse backup, the load line is the resultant. The design

line is constructed with a 1.1 design factor.

6. The tentative pipe selection based on burst is evaluated for collapse. The 54.5-lb/ft, J-55

has a collapse value of 1130 psi. Thus it will be underrated below 1600 ft, a heavier-weight

and grade pipe must be used. In this case, 68-lb/ft, s95 pipe is chosen.

-330

170

670

1170

1670

2170

2670

3170

3670

0 500 1000 1500 2000 2500 3000

Burst load line

Resultant

Design line

Backup (9 lb/gal)

Pipe resistant line J-55

Pressure (psi) D

ep

th (

ft)


Page | 126

7. The tension evaluation for the tentative pipe selection is described by following calcula-

tion:

Determine the actual stress load at bottom and top of the section

Section 1: 1600 ftx54.5 lb/ft =87200 lb

Section 2: 2070 ftx68 lb/ft=140760 lb

The buoyant forces result from mud hydrostatic pressure acting on exposed horizontal areas

of the pipe. The determination of buoyant forces are shown below:

BF1=-PxA=-0.052x9.2x3670x22.5 in2 =-39504 lb

BF2=PxA=0.052x9.2x1600x18.58 n2 =14221.8752 lb

-330

170

670

1170

1670

2170

2670

3170

3670

0 1000 2000 3000 4000

Collapse Load

Desing line

J-55 Collapse Resistance

S-95 Collapse Resistance

Pressure (psi) D

ep

th (

ft)

1410 ft


Page | 127

An overpull factor of 100,000 lb is applied for pipe-sticking considerations since the most rig

personal assume any tubular can be safety pull 100,000 lb. Moreover, a design factor of 1.6

is used to minimize pipe failure under full tension loads when running the casing.

-330

170

670

1170

1670

2170

2670

3170

3670

-100 0 100 200 300 400

Thousands

Tension load-S95

Tension load-S95+100000 lb

166666 lb limit

Tensionx1.6

Tension load-J55

Tension load-J55+100000 lb

Tension (lb)

Dep

th (

ft)

937.32 ft

324285 lb

166666 lb

60496 lb


Page | 128

Summary Table: Casing Selection

Casing

depth Size (in)

Grade

Burst (psi) Collapse (psi) Tension (psi) Result

ft Weight (lb/ft) Design Resistant Design Resistant Design Resistant

Surface 0-1750 13.375/ 54.5 J-55

Top

2041 2730 0 1130 324284.6 853000 SAFE

Bottom

925 2730 2416 2910 60496 85300 SAFE

1600-3670 13.375/68 S-95

5970

2910

1812000

Intermediate 0 -1567 9.625 /43.5 S-95

Top

7195 7510 200 5600 602970 1193000 SAFE

Bottom 1567-8400

4233 7510 955 5600 178840 1193000 SAFE

9.625 /40 S-95

6820

4230

1088000

Production Top 8400 7/26 S-95 5700 8600 4805 7800 154600 717000 SAFE

Bottom 11000

5700 8600 7619 7800 63046 717000 SAFE


Page | 129

6.3.8 APPENDIX C9 – Drillstring Design Calculation

Target depth =11000 ft

Collar length =600 ft

Drill pipe = 4.5 in (3.826 in ID)

Drill collars = 7 in (2.25 in ID, 117 lb/ft)

Maximum surface pressure on the drillpipe =5000 psi

Design factor:

Tension=1.3 ; Collapse=1.3; Burst=1.3; Overpull=100000 lb

Mud weight=10.6 lb/gal; Production zone=10300 ft

Length of drillpipe slips=16 in

1. Create the collapse load line. The maximum collapse is at the bottom of the drillpipe:

0.052x10.6 lb/galx11000 ft = 6063.2 psi

Safety factor of 1.3: 6063.2x1.3=7882.2 psi

Pipe is selected from the catalog. 16.6-lb/ft Grade E-75.


Page | 130

2. Burst load = 5000 psi

Safety factor 1.3: 5000x1.3=6500 psi

3. The Tension load line is calculated as follow:

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

0 2000 4000 6000 8000 10000 12000

Load line

Design line

Collapse 16.6 lb/ft Grade E

Pressure (psi)

De

pth

(ft

)

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

0 2000 4000 6000 8000 10000 12000

Maximum surface pressure

Design line

Burst 16.6-lb/ft Grade E

Pressure (psi)

De

pth

(ft

)


Page | 131

BF1= -(PxA)=-0.052x11000 ftx 10.6 lb/galx[π/4x(72-2.252)] =-209231.524 lb

BF2=PxA=0.052x11000 ft 10.6 lb/galx[π/4x[(72-2.252)+(3.2862-2.252)]=182508.35 lb

Collar weight =600 ftx117 lb/ft =70200 lb

Drillpipe=16.8 lb/ftx11000 ft=184800 lb

Total tension =228276.8 lb

The slip Crushing design line is achieved by following equation:

TS=TL(SH/ST)=228726.4x1.4736=336388.8 lb

The maximum allowable appiled tension is 90% of the tensile strength:

The tensile design factor is:


Page | 132

Summary Table: Drillpipe Selection

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

-300 -200 -100 0 100 200 300 400 500

Thousands

Load line

Load line

Load line

1.3 tension factor

Slip Crushing

100,000 lb Overall design line Max. Allow Tensile load

Yield Tensile Rating

Tension (lb) D

ep

th (

ft)

Hole Size Grade

Size/Weight Burst Collapse Tension

in/(lb/ft) Design Resistant Design Resistant Design Resistant

16 E 75 4.5/16.6 6500 9830 2330 10400 124466 333100

12 1/4 E 75 4.5/16.6 6500 9830 4644 10400 156020 333100

8 1/2 X 95 4.5/16.6 6500 12500 7882 12800 336400 419000


Page | 133

6.4 APPENDIX D – PRODUCTION TECHNOLOGY PART

6.4.1 APPENDIX D1 – Tubing Design Calculation Example

Burst Pressure = 1.1x reservoir pressure=1.1x5700=6270 psi

Completion Fluid:

P=ρgH

5700+100=ρx0.052x11000

Ρ=10 lb/gal

Collapse pressure = 1.25xdepthxcompletion fluid densityx0.052=7150 psi

Tension load 4 1/2 in drillpipe:

Tension load = 1.3xpipe weight x pipe length=12.6 lb/galx11000ft=180180 lb

Summary Table: Tubing Selection

Size Grade

Weight Burst (psi) Collapse (psi) Tension (lbs)

lb/gal Design Resistant Design Resistant Design Resistant

2 7/8 N 80 6.4 6270 10570 7150 11170 91520 105600

3 1/2 N 80 10.2 6270 11560 7150 12120 145860 185100

4 L 80 11 6270 7910 7150 8800 135850 246100

4 1/2 N 80 12.6 6270 8430 7150 7500 180180 288000


Page | 134

6.4.2 APPENDIX D2 –Pipesim Simulation Diagram

Summary Table: Wellhead Pressure at 5700 psi and 2500 psi Reservoir Pressure

Well Distance to manifold (ft)

Pw (psi) Flow rate (STB/d)

Pr=5700 psi Pr=2500 psi Pr=5700 psi Pr=2500 psi

XP1-1 957 310 102 20232 4305

XP1-5 3576 362 100 17738 4454

XP1-7 1025 313 67 20224 5645

XP1-8 2123 342 68 20110 5617

XP1-9 1962 338 57 20126 5844

XP2-1 3280 415 67 19821 4000

XP2-2 3935 430 55 19757 5868

Manifold 200 279 41 138009 35736

FPSO 0 200 15 138009 35736

Wellhead

FPSO

Production Well

Manifold


Page | 135

6.4.3 APPENDIX D3 – Wellflo Sensitivity Analyses

Pr psi

Flow rate

(STB/d) Permeability

mD

Flow rate

(STB/d) GOR

Scf/STB

Flow rate

(STB/d) Water cut

%

Flow rate

(STB/d) skin Flow rate (STB/d)

Tubing size (in)

ID/OD

Flow rate

(STB/d)

Wellhead (psi)

Flow rate

(STB/d)

Base Case

5700 31692

500 31692

500 31692

0 31692 1 31692. 3.958/4.5 31692

350 31692

Pa-rameter

5000 27189 10 4018 1000 29266 10 21425 0 32105 1.995/2 3/8 5894 100 32281

4000 19644

50 15252

2000 24056

20 17088

10 28267

2.441/2 7/8 9892

200 32151

3000 9855

100 21978

3000 20172

30 13739

20 25085

2.992/3 1/2 15528

500 30924

2500 1715

300 21978

4000 17529

40 10956

30 22413

3.476/4 1/2 23597

100 27278

2000 0 800 29677

5000 15462

50 8543

5.044/5 1/2 51281

1500 23198

1000 0 1000 32903 6000 13841 60 6429 6.52/7 0 2000 18406

2000 34113 7000 12534 70 4549

3000 34404 8000 11456 80 2880

4500 34599 9000 10554 95 709


Page | 136

Sensitivity-Tubing Size

Sensitivity-Permeability


Page | 137

6.4.4 APPENDIX D4 –Gas Lift Design

IPR and VLP for Gas Lift System


Page | 138

Sensitivity-Gas/Liquid Ratio SCF/STB

Bottomhole Flowing Pressure at different gas/liquid ratio

Summary Table: Gas Lift Design

Valve

Depth TVD

Tubing Pressure

Tubing Pres-sure Design

Casing Pressure

ft psia psia psia

1 3704 1115 1218.73 2169

2 5519 1611 1706.7 2241

3 6521 1915 1976.3 2271

4 7057 2087 2087 2277


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6.5 APPENDIX E – ECONOMIC PART

Field Development Plan

Documents

Transcript of Field Development Plan