MSc group project presentation

05/02/2023 IPE FDP 2014 - Team A 1

Field Development Plan Team (A) – AQUA

Contents:

• EXECUTIVE SUMMARY • FIELD DESCRIPTION• DEVELOPMENT AND MANGEMENT PLAN• CONCLUSION

2IPE FDP 2014 - Team A05/02/2023

EXECUTIVE SUMMARY

3IPE FDP 2014 - Team A05/02/2023

STOIP: 806 MM bbl Stock

Water Injection

Technique

FPSO + Tie to existing Pipelines

10 New Production Wells + 6 New Injection

Wells (16 Wells)

20 Slots SubSea

Template

Oil Pipeline

Gas Pipeline

Recovery Factor 47.8 %

First Oil Q3 2017

NPV (0.10) $2014 7,727 MM USD

HSE Standard

FIELD DESCRIPTION

Seismic Interpretation

4IPE FDP 2014 - Team A05/02/2023

Seismic plot used for basic interpretation of the reservoir, structure.• An anticline, with possible syn-depositional faults• Pinching out of the main sands and the Ribble sands towards NNW

FIELD DESCRIPTION

3-D Model of X-Field, with Faulting Visible in Blue

5IPE FDP 2014 - Team A05/02/2023

FIELD DESCRIPTION

Severity of the edges

6IPE FDP 2014 - Team A05/02/2023

Severity of the edges, in the top structure of the X-Field, which can be used for detection of possible faulting from the Top Structure.

FIELD DESCRIPTION

2D Contour of X-Field

7IPE FDP 2014 - Team A05/02/2023

2-D Contour of X-Field with Possible Faulting directions highlighted in blue and pink, the extent of the faulting is approximated by the distance to the nearest fault from well test interpretations, visible as red circles.

FIELD DESCRIPTION

OWC (Oil Water Contact)

8IPE FDP 2014 - Team A05/02/2023

The wells X1, X2, X3 and X4 lie in the region with the lower OWC at 10850 ft. TVD SS, and the Well X5 and X6 lie in the region with the shallower OWC, at 10560 ft. TVDSS, with 2 Wells seeing opposite trends, X2 being almost all water, and X6 being all oil.

Well-X1 Well-X2 Well-X3 Well-X4 Well-X5 Well-X6

FIELD DESCRIPTION

Conceptual Explanation for Different Oil-Water Contacts observed in the X-Field

9IPE FDP 2014 - Team A05/02/2023

FIELD DESCRIPTION

Field Stratigraphic Correlation

10IPE FDP 2014 - Team A05/02/2023

Full Field Stratigraphic Correlation for the X-Field, with all the wells in the section, and in order X1,X2,X3,X4,X5,X6, with no preferred direction.

FIELD DESCRIPTION

Stratigraphic Correlation Panel (1) for Wells X2, X1, X6 and X5

11IPE FDP 2014 - Team A05/02/2023

Stratigraphic Correlation for Wells X2, X1, X6 and X5, in the direction SE-NW, with faults shown in red.

FIELD DESCRIPTION

Conceptual Geological Model from Stratigraphic Correlation Panel (1)

12IPE FDP 2014 - Team A05/02/2023

FIELD DESCRIPTION

Stratigraphic Correlation Panel (2) for X4, X6, X1 and X3

13IPE FDP 2014 - Team A05/02/2023

Stratigraphic Correlation for Wells X4, X6, X1 AND X3, in the direction NE-SW, with the fault across well X-6 shown in Red.

FIELD DESCRIPTION

Conceptual Geological Model from Stratigraphic Correlation Panel (2)

14IPE FDP 2014 - Team A05/02/2023

FIELD DESCRIPTION

Core Image Analysis

15IPE FDP 2014 - Team A05/02/2023

Oil-Stained Cores

Interbedding

with

Mudstones

Sand-Filled Mud

Lined Burrows

FIELD DESCRIPTION

Palaeocurrent Direction of Interpreted Sediment Supply

16IPE FDP 2014 - Team A05/02/2023

FIELD DESCRIPTION

Interpreted Geological Sequences of Evolution of the field

17IPE FDP 2014 - Team A05/02/2023

FIELD DESCRIPTION

Indicators for Shallow Marine Environment

18IPE FDP 2014 - Team A05/02/2023

The Main Jurassic Sand Units thins out towards the east because of sedimentary input

from the SW-NE direction.

Core image samples that shows the bioturbated mudstone lamina and trace fossils

present.

A general coarsening up texture of rock.

FIELD DESCRIPTION

GEOLOGY AND RESERVOIR DESCRIPTION

19IPE FDP 2014 - Team A05/02/2023

The Formations in the X-Field can be classified into five diff types of sub-units.

• Ribble Sand which is highly permeable (1000mD) and porous representing very

good to excellent reservoir characteristics.

• Clyde is very low permeability (10-50 mD) with poor reservoir characteristics.

• Lydell, Mersey and Usk Sands show permeabilities that are varying from very-

high to moderate values (average 670 mD) resulting in a reservoir unit that is

good to moderate in quality.

FIELD DESCRIPTION

20IPE FDP 2014 - Team A05/02/2023

Multi-Well Histogram for Core Derived Porosities for X1, X4 and X5

Porosity X1 X4 X5

Minimum 3.6 % 10.2 % 3.7 %

Maximum 33.3 % 32.4 % 28.8 %

Std. Deviation 5.92 % 3.23 % 5.21%

Mean 22.32 % 24.65 % 20.8 %

FIELD DESCRIPTION

21IPE FDP 2014 - Team A05/02/2023

Multi-Well Histogram for Core Derived Permeability for X1, X4 and X5

K X1 X4 X5

Minimum 0.01 mD 0.05 mD 0.01 mD

Maximum 4500 mD 2900 mD 3600 mD

Std. Deviation

801.91 mD 734 mD 789.54 mD

Mean 733.12 mD 767.2 mD 564.53 mD

Cutoff 1 mD 1 mD 1 mD

FIELD DESCRIPTION

Cross Plot Multi Wells (Core Permeability – Core Porosity) for X1, X4 and X5

22IPE FDP 2014 - Team A05/02/2023

Porosity and Permeability, plotted on a semi-log graph, showing two different trends for Well X1, and Wells X4 and X5, thereby hinting that the main reservoir units, in Well X1 is different from Wells X4 and X5.

FIELD DESCRIPTION

The Permeability and Porosity profiles for the Well X5

23IPE FDP 2014 - Team A05/02/2023

The Permeability and Porosity profiles for the

Well X5, hint at the existence of possible layering within the

reservoir section, with layers of very high and

very low permeabilities, which is also being confirmed in the Lorentz Plot (in the

next slide)

FIELD DESCRIPTION

Lorenz Plot and Semivariogram for Core of well X5

24IPE FDP 2014 - Team A05/02/2023

Well X5, was chosen for core analysis, as it has all three sets of data, with sufficient sample sizes for each of the four distinct zones , along with core photographs, and RFT data.

FIELD DESCRIPTION

Core Derived Porosity and Permeability Cross plot for Core-Data in Well X5

25IPE FDP 2014 - Team A05/02/2023

FIELD DESCRIPTION

Cross Plot Multi-Wells (Porosity – Formation Resistivity) for X3, X4 and X5

26IPE FDP 2014 - Team A05/02/2023

For the estimation of Rw, both “Pickett Plot” and “Rwa” method have been used, and the value of Rw, in the field was approximated at 0.03 OHMM. Values of Rm and Rmf are from the log headers.

Porosity

FIELD DESCRIPTION

Facies identification

27IPE FDP 2014 - Team A05/02/2023

• For our facies identification , we decided to go for a sand/shale system, and used the ROCK_NET flag generated from the summaries section in Techlog.

• For estimation of Water Saturation (Sw), we used was the Indonesia Equation, as the Archies Equation is only for clean sands.

• For Vshale, cutoffs from Histogram, and Clavier Equation.

• KMOD for Permeabilities.

Well-X1 Well-X2 Well-X3 Well-X4 Well-X5 Well-X6

FIELD DESCRIPTION

Cross Plot (Neutron-Porosity – Bulk Density) for wells X1-X6

28IPE FDP 2014 - Team A05/02/2023

Density-Neutron Cross plots for all Wells, the main outlying points, belong to the bottom most Non-Reservoir Unit, Sand-5 (Very-Shaly Sand), and excluding those outlying points, the entire lithology falls along similar trends, agreeing with our interpretation of a sand & shale system.

FIELD DESCRIPTION

Multi-Well Gamma-Ray Histogram for Wells X1-X6

29IPE FDP 2014 - Team A05/02/2023

Higher than normal Gamma Ray Values for the Reservoir Sands especially in Wells that lie within the area under the Clay Seals (Wells- X1, X2)

FIELD DESCRIPTION

HYDROCARBONS IN PLACE; Deterministic Reserve Estimation

30IPE FDP 2014 - Team A05/02/2023

WORST MOST PROBABLE BEST

Area (acres) 2425.5 2425.5 2825.5

Thickness (feet) 100 340 580

Porosity (%) 0.18 0.23 0.33

Water Saturation (%) 0.4 0.2 0.1

Form. Volume Factor (bbl/stb) 1.49 1.43 1.33

NTG 0.89 0.98 0.99

STOOIP (MMSTB) 121.386 806.7262111 2810.62

Deterministic Reserve Estimation, using parameters from the Petrophysical Analysis

FIELD DESCRIPTION

HYDROCARBONS IN PLACE; Probabilistic Reserve Estimation (Latin Hypercube Method)

31IPE FDP 2014 - Team A05/02/2023

Probabilistic Reserve Estimation, using parameters from the Petrophysical Analysis, and Latin Hypercube Sampling.

STOOIP (MMSTB)P10 1,274.80P50 859.69

P90 517.70

FIELD DESCRIPTION

Sensitivity Analysis for STOIP; Tornado Chart

32IPE FDP 2014 - Team A05/02/2023

Thickness (FT.)

Porosity (%)

Water Saturation (%)

Area (Acres)

Form. Volume Factor (bbl/stb)

NTG

0.00 500.00 1,000.00 1,500.00

472.67

0.29

0.32

2,785.50

1.46

0.98

207.33

0.21

0.15

2,465.50

1.37

0.92

Sensitivity Analysis for Field-X STOOIP (MMSTB)

Downside Upside

The range of values used for the Input Parameters are taken from the generated summary of the six wells, varying from the best to worst values, with the median values assumed for the base case, for sensitivity analysis.

FIELD DESCRIPTION

Sensitivity Analysis for STOIP; Spider Diagram

33IPE FDP 2014 - Team A05/02/2023

10.00% 13.86% 17.71% 21.57% 25.42% 29.28% 33.13% 36.99% 40.84% 44.70% 48.55% 52.41% 56.27% 60.12% 63.98% 67.83% 71.69% 75.54% 79.40% 83.25% 87.11%400.00

600.00

800.00

1,000.00

1,200.00

1,400.00

Sensitivity Analysis for Field-X STOOIP (MMSTB)

Thickness (FT.) Porosity (%) Water Saturation (%)Area (Acres) Form. Volume Factor (bbl/stb) NTG

The range of values used for the Input Parameters are taken from the generated summary of the six wells, varying from the best to worst values, with the median values assumed for the base case, for sensitivity analysis.

06/19/14 34

PVT ANALYSISPROPERTY MEASURED

API 40

Initial Reservoir Pressure (psi) 5745

Temperature (°F) 250

Bubble Point (psi) 1785

GOR (scf/stb) 351

Density (lb/ft3) 41.51

Viscosity (cP) 0.34

Oil Compressibility , 1/psi X10^-5 1.3

Oil Formation Volume Factor 1.41

IPE FDP 2014 - Team A

06/19/14 35

CAPILLARY PRESSURE


01020304050607080901000

20

40

60

80

100

120

140

160

Pressure(oil water) vs pore space %

Pressure(oil water)

Pressure, Psia

porosity % 22.9 permeabil-ity MD 49 Depth (Ft) 10330.4 100101

100

10

1

0.1

0.01

Sw %

J(sw

)

S 0.336483R-Sq 80.8%R-Sq(adj) 80.7%

Log Fitted Leverett-J Function for Field-X Capillay Pressure Core Datalog10(J(sw)) = 2.525 - 1.723 log10(Sw %)

06/19/14 36

RELATIVE PERMEABILITY


0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 10

0.10.20.30.40.50.60.70.80.9

KR1T 0Water Saturation, Sw

Rel

ativ

e Pe

rmea

bil-

ity

Mersey and Lydell Sands

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 10

0.1

0.2

0.3

0.4

0.5

0.6

0.7

KRHTKRIT

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 10

0.10.20.30.40.50.60.70.8

KR1TKRHT

Clyde Sands

Usk Sands

06/19/14 37

RELATIVE PERMEABILITY


0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 10

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

KR1T

KRHT

0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 10

0.1

0.2

0.3

0.4

0.5

0.6

KR1T

KRHT

Ribble sands Forth Sand & Ush Sand

Well-Test Analysis

Log-Log Diagnostic(X2) Results (Oil Zone)

38IPE FDP 2014 - Team A05/02/2023

Reservoir Parameter Results

Permeability (mD) 250

Skin 1.25

Wellbore Storage Coefficient

(bbl/psi)

0.0349

Well Thickness (ft) 130

Extrapolated Pressure (psia) 5680

Reservoir Interval (ft TVDSS) 10637 - 10672 & 10688 –

10700

Productivity Index(bbl/d/psi) 35

Distance from Fault (ft) NA

Well-Test Analysis


39IPE FDP 2014 - Team A05/02/2023



Skin -3.5


(bbl/psi)

0.0349



Reservoir Interval (ft TVDSS) NA

Productivity Index(bbl/d/psi) 70

Distance from fault (ft) 220

Well-Test Analysis

• Log-Log Diagnostic(X5) Results (Oil Zone)

40IPE FDP 2014 - Team A05/02/2023



Skin 22

Wellbore Storage

Coefficient (bbl/psi)

0.2



Reservoir Interval (ft TVDSS) 10264-10332

Productivity

Index(bbl/d/psi)

64.2

Distance from fault(ft) 467 and 600 ft. (Interesting

Fault) - BU

Well-Test Analysis


41IPE FDP 2014 - Team A05/02/2023



Skin 43.6


(bbl/psi)

0.241



Reservoir Interval (ft TVDSS) 10264 – 10309

Distance from fault (ft) 325 and 325 ft. (Interesting

Fault) - BU

06/19/14 42

Well-Test Analysis

Well Test Summary Table Well Name Well X2 Well X3 Well X5 Well X6

K(mD) 249.7 - 270.30 214.7 692.80 - 820 338.8 - 500

Kh(mD Ft) 32460 - 35143 21470 204400 - 223000 158200 - 211500

P* (psia) @ 10500 ft TVDSS 5680 - 5700 5246 4304 - 4350 4826 - 4837

S (Total Skin) 0.9989 - 1.5 -3.5 20.83 - 22 43.6 - 60

Fault Detection Distances N/A 220 ft. 467 and 600 ft.

(Interesting Fault) - BU325 and 325 ft.

(Interesting Fault) - BU


• Permeability values from all the well test shows high heterogeneity in the reservoir.• Formation damage(Skin) in the range -3.5 – 45.

06/19/14 43

Well-Test Analysis

Well Test Interpretations• Fault Signatures are identified in Wells X2, X5,

X6.


06/19/14 44

Well-Test Interpretations

• Semi steady state regimes are not found in any log-log plots, therefore:– Drainage area & Shape factor were not calculated

using pan system.– Pmbh & Pavg could not be calculated.


Well-Test Analysis

06/19/14 45

Well-Test Analysis


RFT Analysis for X1, X2, X3 and X5

Two OWC’s identified @ 10560 and 10840 ft. TVD SS

06/19/14 46

Case no.

Number of wells

Plateau Production

(years)

Recovery Factor

(fraction)

Base Case

4 Producers and 2 Injectors

12.6 0.26

Case 1 9 Producers and 5 Injectors

5 0.46

Case 2 10 Producers (1 Horizontal) and

5 Injectors

4.8 0.47

Case 3 14 Producers and 8 Injectors

3 0.478

Number of wellsThe selection of the number of wells was determined on the basis of the combination of:

(1)Economic factor(2)Recovery Factor(3)Plateau production period


FIELD DESCRIPTIONWELL PERFORMANCE

Producer Injectors

Existing 4 2

New 10 6

Optimum Case (Case-3)

06/19/14 47

Layer Pressure

Water Cut Oil rate OD ID

(psia) (fraction) (bopd) (in) (in)

1900 0.9 389.2 4.5 3.958

1900 0.9 403.1 5.5 4.8

Optimum tubing diameter“4.5 in OD “

The selection criteria:Oil rate (bopd) @Water cut = 0.9 (fraction)Layer Pressure = 1900 psia


Worst Case Scenario

The difference between the oil rates is very low, thus, we go for the smaller tubing size


06/19/14 48

Plateau Period

Recovery Factor

Water Cut Layer Pressure

(years) (fraction) (fraction) (psia)Case 3 3 0.478 0.35 5720

Natural Flow of well:-• The well flows naturally at

the Optimum Oil rate for “3 years”

• The corresponding Layer pressure, Water cut and Recovery Factor are shown in the table, also their relationship



06/19/14 49

Artificial Lift Selection is Dual “ESP”.

Gas Lift was not used because:• The reservoir does not produce gas• Quantity of gas available after

separation is not sufficient• Uneconomical to import gas from the

closet facility available



06/19/14 50

Selection of the Pump• Available options:


Specifications HN 21000 (HS) – Reda KC 20000 – Centrilift

Motor 562 Series – Reda KMH-J 562 – Reda

Min Liquid rate 20416 20416

Max Liquid rate 28000 28000

Stages 14 – 88 2 – 98

(The pump selection is based on the performance at the worst case scenarioThe pumps that were available for these conditions are shown in the table)


06/19/14 51

Selection of the Pump• Comparison of the performances of the pumps are shown in

the table


Pump Name Layer Pressure Water Cut Oil Rate

(psia) (fraction) (bopd)

HN 21000 (HS) – Reda1900 0.9 363.8

KC 20000 – Centrilift1900 0.9 464.6

Based on the performance @ worst case scenario:“KC 20000 – Centrelift” is selected as the ESP


06/19/14 52

Performance of the pump• The table shows the point, i.e. water and Layer pressure, till

where the ESP can provide the Optimum Oil Rate



From the above table we can see that the pump will be able to produce at Optimum rate till “5000 psia and water cut ranging from 0.41 to 0.47”

Layer Pressure (psia)

Water Cut (fraction)

Oil Rate(bopd)

5720 0.35 15297.9

5000 0.41 10173.6

5000 0.47 8501.9

4600 0.35 10021.2

1900 0.2 9597.3

06/19/14 53

Formation DamageThe Formation Damage caused by:a) Drillingb) Cementingc) Perforationd) Production– Fine movement– Scales(organic and inorganic)– Pressure Reduction– Stimulation



06/19/14 54

Production Zone maintenance

• Re-perforation for water Shut-offs.

• The technical well treatment solutions to remove the

Formation Damage are as follows:

– Matrix.

– Hydraulic Fracturing.



06/19/14 55

• Selection Criteria for Well Treatment method:


Treatment Type Skin Permeability

Propped Hydraulic Fracture Low Low

Propped Hydraulic Fracture High Low

Frac and Pack High Medium

Matrix High Medium/High

Treatment not required Low Medium/High


06/19/14 56

Selection of Well Treatment Method“Matrix v/s Hydraulic Fracturing”


Parameters Matrix Hydraulic Fracturing

Hydrocarbon Saturation ˃ 40% ˃ 40%

Water cut ˂ 30% ˂ 30%

Permeability ˃ 20 mD 1-50mD

Reservoir Pressure ˂ 70% depleted ˂ 70% depleted

Based on the above table, Matrix method is chosen.


06/19/14 57

Sand ControlTypical Allowable Sand Production Levels are mentioned in the table below:


Produced Fluid Production Rate Allowable Sand Level

Light Crude Oil <5000bopd 30lb/1000bbls

5000-15000 10 lb/1000bbls

>15000 5 lb/1000bbls

• Initially, the sand production is “ at the production rate of• But, in the future with the increase in the water cut, it will be expected to get an

increase in sand production.• At that period “Internal Gravel Pack” will be used.


FIELD DESCRIPTION

– STRUCTURAL CONFIGURATION.– GEOLOGY AND RESERVOIR DESCRIPTION.– PETROPHYSICS AND RESERVOIR FLUIDS.– HYDROCARBON IN PLACE.– WELL PERFORMANCE. – RESERVOIR MODELLING APPROACH. – DYNAMIC MODEL.

58IPE FDP 2014 - Team A05/02/2023

MODELLING APPROACH

Static reservoir model :

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

59IPE FDP 2014 - Team A05/02/2023

06/19/14 60

MODELLING APPROACHPermeability Distribution


06/19/14 61

MODELLING APPROACH

Cross section of model with pore distribution


06/19/14 62

MODELLING APPROACHPorosity distribution


FIELD DESCRIPTION

– STRUCTURAL CONFIGURATION.– GEOLOGY AND RESERVOIR DESCRIPTION.– PETROPHYSICS AND RESERVOIR FLUIDS.– HYDROCARBON IN PLACE.– WELL PERFORMANCE. – RESERVOIR MODELLING APPROACH. – DYNAMIC MODEL.

63IPE FDP 2014 - Team A05/02/2023

DYNAMIC MODEL

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

64IPE FDP 2014 - Team A05/02/2023

06/19/14 65

DYNAMIC MODEL

• Fluid properties for oil and water were entered (i.e. oil formation volume factor, relative permeability, water-oil capillary pressure data and Rock compressibility).

• Oil-water contacts were defined.

• Model was quality checked by comparing GRV.

• Model generated with 208,050 cells.


Optimum Case (Case-3)

o DEVELOPMENT PLANS, RESERVES AND PRODUCTION PROFILES.

o DRILLING FACILITES.o PRODUCTION AND PROCESS FACLITLES.o RESERVOIR MANGEMENT & MONTIORING (I.e. Production

Plan).o ENVIROMENT IMPACT AND ABATEMENT.o ABONDAMENT.o COST.

66IPE FDP 2014 - Team A05/02/2023

DEVELOPMENT AND MANGEMENT PLAN




67IPE FDP 2014 - Team A05/02/2023


Reservoir development strategies:• Several development plan cases were considered with

various sensitivities on liquid flow rates and water injection rates.

• Four scenarios were chosen for detailed investigation as

follows:– Base case– Case 1: 9 producers & 5 injectors– Case 2: 10 producers(1 horizontal) & 5 injectors– Case 3: 14 producers & 8 injectors

68IPE FDP 2014 - Team A05/02/2023


06/19/14 69

BASE CASE• Natural depletion case.

• 4 of appraisal wells will be producer wells, while two of the wells will be converted to water injection wells.

• Wells are completed in (Layers (DZ): 1-5).

• Control mode - BHP limit of 1900 Psi is set.

• Reservoir evaluation period : 30 years.

• Recovery factor – 26 %.

• Water cut – 43 %.


06/19/14 70

CASE 1


• 9 producers and 5 injectors.• Injectors completed in low

permeable zones.• Control mode – Reservoir Oil rate of 90,000 STB/day.• Recovery factor of 46% is achieved.• Reservoir is energized with water injectors.• Oil recovery is increased due to high sweep efficiency.• Sensitivities were run on the locations of wells and timing of water injectors.• Water cut is around 88.9%.

06/19/14 71

CASE 2• 10 Producers(1 horizontal) and 5

injectors.• 1 Horizontal wells of 2000 ft. laterals are placed.• Reservoir Oil rate of 100,000

STB/day.• 5 injectors will be drilled and completed in low permeable zones.• Various sensitivities were run to optimize the location and length of the horizontal wells.• Recovery of 47.1 %.• Water cut is 88%.


06/19/14 72

CASE 3

• 14 producers and 8 injectors.• Reservoir Oil rate of 132,000

STB/day.• 8 Injectors will be drilled in

low permeable zones.• Various sensitivities were run to optimize the location and length of the wells.• Recovery of 47.8 %. • Water cut is 88%.


OPTIMUM DEVELOPMENT PLAN CASE

06/19/14 73

SIMULATION RESULTS


CASES OIL RECOVERY EFFICIENCY (%)

TOTAL OIL PRODUCTION

(MILLION BBLS)MAX WATERCUT PLATEAU

PERIOD (YRS)

BASE CASE (4 P + 2 I) 26 280 0.43 12

CASE 146 499 0.89 5

(9 P + 5 I)CASE 2

47.1 509 0.88 4.8(10 P + 5 I)

CASE 347.8 510 0.88 3

(14 P + 8 I)

* P - Producer Wells; I – Injector Wells

FOE vs TIME

06/19/14 74

SIMULATION RESULTSFOPR (Field Oil Production Rate)


06/19/14 75

SIMULATION RESULTS• FOIP (Field Oil In Place)


06/19/14 76

SIMULATION RESULTSFWCT (Field Water Cut)


06/19/14 77

UNCERTAINTIES

Uncertainties and limitation of reservoir model:• All the faults have not been incorporated in this

model given the uncertainty of the location and transmissibility’s.

• For simplicity, only one oil-water contact has been considered.

• Property variation across the fault is uncertain as the layers pinch out.





78IPE FDP 2014 - Team A05/02/2023





79IPE FDP 2014 - Team A05/02/2023


INTRODUCTION

80

The drilling program is designed to drill 16 new development wells in “X” field penetrating the upper Jurassic Sandstone formation located in offshore Northern North Sea of water depth 150 meters.

The wells are intended to penetrate the “X” field structure at the designated locations from reservoir simulation.

IPE FDP 2014 - Team A05/02/2023

Offset Well Analysis• The offset wells

analysis have been conducted for the available data for wells X2 and X3.

• The offset well analysis is used for casing point selection and the mud design.

81

Main Offset Well X-3

IPE FDP 2014 - Team A05/02/2023

06/19/14 82

Well Design Summary


Subsea Template Location

The program includes the selection of the center of the subsea platform to achieve all the proposed wells from single subsea template.

83

Subsea Template

IPE FDP 2014 - Team A05/02/2023

Directional Well Program for the longest well (J-Type)

84

• Nudge Plan @ 26” Hole.• KOP @ 1482 ft.• BUR = 1.5 deg / 30 ft.• J-Well Profile .• Max Inclination= 51.88.• Well TD @ 15556 ft MD/

11039 ft TVD.

Nudge plans will be provided once the subsea template final coordinates and orientation will be given.

DLS is low as possible as the KOP @ 17 ½” Hole Size (large Hole Size) to reduce T&D along the well.

IPE FDP 2014 - Team A05/02/2023

Geological Prognosis

85

The geological prognosis used is a typical North Sea geology up to the depth of the top of the reservoir.

The used pore pressure is the normal pore pressure up to the top of the reservoir.

The used reservoir pressure from the RFT data.

IPE FDP 2014 - Team A05/02/2023

Pore Pressure, Fracture

Pressure and Overburden

86

0 2000 4000 6000 8000 10000 120000

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

PORE PRESSURE

MUD ACTUAL DATA (WELL X3)

OVERBURDEN PRESSURE (1 Psi/FT)

FRACTURE PRESSURE (EATON METHOD)_Various Poisson Ratio

FRACTURE PRESSURE (EATON METHOD)_Max Poisson Ratio (0.50)

FRACTURE PRESSURE (0.85 psi/ft)

Pressure, psi

TVD

ft, R

KB

Fracture Pressures estimated from EATON method with Different Poisson Ratio and as constant as 0.85 psi/ft.

LOT / FIT is planned for drilling wells to update the fracture gradient and casing design.

IPE FDP 2014 - Team A05/02/2023

Casing Setting Depths,

Bottom-Up Design

87

Obtained LOT / FIT will be used to review the is planned for drilling wells to update the casing design.

To isolate the reservoir section

IPE FDP 2014 - Team A05/02/2023

Casing summary Table

88

Hole Size

In

CasingODIn

Casing Setting Depth

ft., MD

Casing Setting Depth (*)

ft., TVD-RKB

Casing Setting Depth

ft., TVD-SS

Casing Seating Depth Criteria

36 30 693 693 615

Set 123 ft. below the seabed (As per offset well X3). Seal off unconsolidated formation at shallow depths

which, with continuous mud circulation, would be washed away.

26 20 1383 1382 1304

Seal off any fresh water sands. Case and cement off unconsolidated shallow sediments. Provide Structural support for the subsea Wellhead and

BOPs.

17.50

13.375

8282 6549 6471

To isolate troublesome formations between production and surface casing (unstable shale and lost circulation (i.e. Chalk).

Cased off Tertiary formations and usually set in top upper Cretaceous

12.25 9.625 14054 10112 10034

Set above the pay zone to isolate the production interval from other formations and/or act a conduit for the production tubing.

Cased off top Cretaceous chalk and Lower Cretaceous siltstones.

8.50 7 15555 11039 10961

Set across the reservoir to allow selective access for production / injection/ control the flow of the fluids from or into the reservoir.

(*) RKB-MSL = 78 ft.IPE FDP 2014 - Team A05/02/2023

Rig Selection Criteria

89

Criteria Selected Design Criteria Source of Design Criteria

Water Depth 150 m Given for Group A

Mud Pumps 1600 HPThree Mud Pumps (2 + 1 Back Up’s)

HP = Q x P / 1714

For 8 ½”, 1600 HP

Hoisting SystemDerrick, Draw works, fast line, dead line, travelling

block, crown block, Reserve Drum, Drilling Hook and Elevators

The total vertical load on the rig when pulling the string = 382,036 Ib Buoyant Weight = 15,000 ft * 22.50 Ib/ft * 0.85 = 300,000 Ib Tension in the fast line = 300,000 / 8 * 0.842 = 44,536 Ib Tension in the dead line = 300,000 / 8 = 37,500 Ib

BOP’s 10,000 Psi

The maximum expected Burst surface pressure from gas kick off is 4700 psi The Maximum Pressure to surface (In case of Gas Migration to Surface) is 5800 psi The Abnormal high pressure BOP rated as 10,000 psi.

IPE FDP 2014 - Team A05/02/2023

Rig Selection

90

Rig Name Providers Water Depth Mud Pumps Hoisting System BOP’s

West Alpha Seadrill 60 – 600 m 3, 1600 HP N/A 15 K

Ocean Ambassador DIAMOND OFFSHORE 335 m

3 x National 12-P-

160, 1,600hp, 5,000 psi

1000 KIb

Cameron 18 ¾”

10,000 psi four-ram preventer

2 x Shaffer 18 ¾” 5,000 psi annular

preventers

Ocean Yorktown DIAMOND OFFSHORE 868 m

3 x Oilwell A1700-PT, 1,000hp, 5,000 psi

1000 KIb

Cameron 18 ¾”

10,000 psi four-ram preventer

2 x Shaffer 21 ¼” 5,000 psi annular

preventers

IPE FDP 2014 - Team A05/02/2023

BHA Design

91

Hole Size Vertical / Deviated

Anticipated Drilling Problems

Primary BHA Design Secondary BHA Design

36” Hole Vertical BHA Wash out, Losses 36” Pendulum BHA Or 26” Hole Opener Rotary BHA

N/A

26” Hole Nudge Directional BHA

Losses 26” Nudge Motor BHA N/A

17 ½” Hole Directional BHA Slow ROP 17 ½” Motor BHA (For First Well) 17 ½” RSS BHA (Rotary Steering BHA) will be evaluated after

drilling the first well

12 ¼” Hole Directional BHA Losses in Chalk formation and shale instability problems

12 ¼” Motor BHA (For First Well) 12 ¼” RSS BHA will be evaluated after drilling the first well

(In case of no losses in Chalk

formation), this BHA can be used to drill the shale section in lower

cretaceous.8 ½” Hole Directional BHA

Kicks, stuck 8 ½” Motor BHA (For First Well) 8 ½” RSS BHA will be evaluated

after drilling the first well

Motor BHA

RSS BHA

IPE FDP 2014 - Team A05/02/2023

Drilling Parameters

92

Hole Size Vertical / Deviated WOB, Ibs Flow Rate, GPM (*) Surface rpm Drilling Problems

36” Hole Vertical BHA 35,000 – 45,000 1000 60 Wash out

26” Hole Nudge Directional BHA 35,000 – 45,000 1300 – 1820

60 Losses

17 ½” Hole Directional BHA 35,000 – 45,000 875 – 1225

(1100 – 1200) from Offset Well X-3

60 Slow ROP

12 ¼” Hole Directional BHA 25,000 – 35,000 612 – 857

(+/- 750 GPM) from the Offset Well X-3

60 Losses in Chalk formation.

Shale instability

problems

8 ½” Hole Directional BHA

15,000 – 25,000 425 – 600

(Min 500 PM) for the offset well X-3

60 Kicks, stuck

(*) The designed flow Rate is between 50 – 70 x Hole Size (Rule of Thumb)

IPE FDP 2014 - Team A05/02/2023

Bit Design

93

Hole Size FormationDepth In, ft. MD

Depth out, ft.

MDBit Type Bit Picture

Rationale

36” Hole Sandstone 571 693 Mill Tooth Bit

Mill tooth can be used to drill soft formation in top hole in Tertiary.

Mill tooth bit cost relatively cheaper than the Insert/ PDC bits.

26” Hole Mud and Siltstone 693 1383 Mill Tooth Bit

Mill Tooth can be used to drill soft formation in top Tertiary, Mill tooth bit cost relatively cheaper than the Insert/ PDC bits.

17 ½” HoleSiltstone,

Sandstone, Anhydrite

1383 8282

Insert Bit(In case of

presence of Chert)

PDC Bit(In Case of no

chert)

Insert bit can drill all the formation include the Chert. The insert bit will help to kick off using motor BHA (creates

steady tool face for orienting the motor). The insert bit disadvantage is the limited life by bearing wear,

increase the bit trips to drill the section, and increase the rig time and cost.

If geologists confirm the non-presence of the chert, PDC bit

will be used (with directional drilling features).

12 ¼” Hole Chalk and Siltstone 8282 14054 PDC Bit

PDC bit can drill moderately hard formations (not chert); ROP varies depending on the formation.

The PDC bit should provide higher ROP than the tricone bit.

8 ½” Hole Sandstone 14054 15555 PDC Bit

PDC bit can drill moderately hard formations (not chert); ROP varies depending on the formation.

The PDC bit should provide higher ROP than the tricone bit.

IPE FDP 2014 - Team A05/02/2023

Casing Design Table

94

Hole Size

In

Section Depth

Ft, MD

Setting Depth

Ft, TVD-RKB

Setting Depth

Ft, TVD-SS

CasingODIn

Weight, Ib-ft Grade

26 1383 1382 1304 20 106 J-55 and/or K-55

17.50 8282 6549 6471

13.375

No standard (Non API Casing)

Due to high collapse Load in this design

(The Collapse resistance required

is > 3044 Psi

12.25 14054 10112 10034 9.62547 and 53.50 (Special

Drift ID for 53.5 Ib/ft)

L80 / N-80

8.50 15555 11039 10961 7 29 L-80 / N-80

IPE FDP 2014 - Team A05/02/2023

Example for Casing Design9 5/8” Production Casing Design

95

Assumptions:

5800 psi4750 psi

Pi @ Top of Liner= 10990 psi

0 psi6240 psi

Depth Pi Pe Pb Pb x D.F.Surface 0.00 4750.00 0.00 4750.00 5225.00Top of Liner 9600.00 10990.00 6240.00 4750.00 5225.00

Pc = Pe-PiAssumptions:

0 psi0 psi

0 psi6240 psi

Depth Pi Pe Pc Pc x D.F.Surface 0 0 0 0 0Top of Liner 9600 0 6240 6240 6240

Pe= Normal Pore Pressure

9.625 PRODUCTION CASING DESIGN

Burst Load:-Pb = Pi - Pe

(ii) External Loads:Pe @ surface =

SUMMARY

Collapse Load:-

Pe @ surface =Pe @ packer top =

SUMMARY

Pi= Gas well, well closed at surface, leak in tubing under tubing hanger at surface, annulus above packer is full of packer fluid

Pi= Casing empty, due to gas being switched off after gas lifting, assume well in producing well

Pe= Normal pore pressure

(i) Internal Loads:Pi @ surface = Pi @ packer top =

(ii) External Loads:-

Pe @Top of Liner =

(i) Internal Loads:Pi @ perforations top =Pi @ surface =

BURST PLOTS

COLLAPSE PLOTS

0.00

1000.00

2000.00

3000.00

4000.00

5000.00

6000.00

7000.00

8000.00

9000.00

10000.00

11000.00

12000.00

0.00 2000.00 4000.00 6000.00 8000.00 10000.00

TVD

ft,

RKB

Pressure, psi

Pb x D.F. Pb 47, L-80/N-80 53.5, L-80/N-80

0.00

1000.00

2000.00

3000.00

4000.00

5000.00

6000.00

7000.00

8000.00

9000.00

10000.00

11000.00

12000.00

0.00 2000.00 4000.00 6000.00 8000.00 10000.00 12000.00

TVD

ft,

RKB

Pressure, psi

Pe Pi Pb Pb x D.F.

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

11000

12000

0 1000 2000 3000 4000 5000 6000 7000

TVD

ft,

RKB

Pressure, psi

Pe Pi Pc Pc x D.F.

0.00

1000.00

2000.00

3000.00

4000.00

5000.00

6000.00

7000.00

8000.00

9000.00

10000.00

11000.00

12000.00

0 1000 2000 3000 4000 5000 6000 7000

TVD

ft, R

KB

Pressure, psi

53.5, L-80/N-80 Pc 47, L-80/N-80

IPE FDP 2014 - Team A05/02/2023

Cementing Program

96

Casing Design Considerations Technique TOC

30

Design for theHydrostatic Pressure < Fracture Pressure (During the

CMT Job) CMT is up to Surface to support the Subsea WH and

BOP.

Inner String Cementing

(A Stinger Cement Job)

Is to cement the casing through DP

To Surface

20


CMT Job)

CMT is up to Surface to support the Subsea WH and BOP.

Inner String Cementing (A Stinger Cement Job)

Is to cement the casing through DP

To Surface

13.375

Design for theHydrostatic Pressure < Fracture Pressure

Single Stage Cement

TOC @ 200 ft. above the previous casing

9.625


CMT Job)

DV tool between the chalk and Shale to reduce the hydrostatic head in the chalk while cementation

Two Stage Cement TOC @ 200 ft. above the previous casing

7


CMT Job)

Design for the reservoir pressure and Temperature

Liner CementationLinear will be cemented over their entire length, all the way from the

liner shoe to the liner hanger.

20" CSG

13 3/8" CSG

9 5/8" CSG

7" LNR

IPE FDP 2014 - Team A05/02/2023

Mud Program

97

Hole Size Formation Mud Type Mud Weight (*), ppg Technical Functions of the fluids Issues (Cost, Environments)

36” SandstoneWBM

(Sea Water)

8.94

Drill the Top hole and the return to the sea bed. Having drilled to the required depth, the hole is displaced to mud to prevent debris from settling onto the bottom of the

hole when running the 30” Conductor.

Environmentally friendly.

26” Mud and Siltstone

WBM

(Sea Water) with viscous pills

8.94- 9.23 Drill the top hole w/ sea water.Spot 9.23 ppg mud prior to running 20” casing


17 ½” HoleSiltstone (Shale),

Sandstone, Anhydrite

WBM – SUPER SHALE TROL / KCL

Polymer10.19 – 11.92 Help to reduce the shale swelling. Environmentally friendly.

12 ¼” Hole Chalk and Siltstone (Shale)

WBM –SUPER SHALE TROL / KCL

Polymer12.31 – 12.50 Help to reduce the shale swelling. Environmentally friendly.

8 ½” Hole Sandstone Super Shale TROL (Semi-Disperse) 12.50

Help to reduce the shale swelling.The skin obtained from the offset well X3 is between 0.9 – 2.5.


IPE FDP 2014 - Team A05/02/2023

Sub Sea Drilling Challenges

• The rig may disconnect from the well or even move off location due to bad weather.

• More complex equipment such as guide frame, marine riser, telescopic joints, riser tensioners, and flex joints.

• Well intervention is a major technical and economical challenge in deep water, and lack of well maintenance can easily risk flow assurance.

98IPE FDP 2014 - Team A05/02/2023

Production and Production Facilities

Challenges in the field:• Pipework in subsea, place-surface and down-hole• Corrosion/Erosion– Not an issue initially as CO2 content is initially less– Internal external corrosion of production facility– Coatings/materials to avoid corrosion

• Scaling• Asphaltenes• Production platform• Bottom-hole completion

99IPE FDP 2014 - Team A05/02/2023

Well completion design

100IPE FDP 2014 - Team A05/02/2023

4.5in VAM Tubing

4.5in ‘X’ Nipple

Crossover 6.5in x 4.5in

4.5in Hydril EU Tubing Tailpipe

4.5in ‘X’ Nipple

4.5in ‘X’ Landing Nipple

Wire-line Entry Guide

PRODUCTION AND PROCESS FACILITIES

Floating Production Storage and Offloading Unit (FPSO) Main Functional Requirements:

– Production of crude oil;– Processing of produced crude for oil, water, gas and sand separation;– Treatment of produced water prior to disposal or re-injection;– Provision of utility systems for LPF topsides and subsea operations;– Provision of space, weight and basicutilities for potential retro-fitting

of water injection facilities;– Space and weight provision for potential future additional produced

water treatment facilities.

IPE FDP 2014 - Team A 06/19/14 101

Surface Processing Topsides Facilities• Schematic facility design

102IPE FDP 2014 - Team A05/02/2023

Surface Processing Topsides Facilities• Facilities: Floating Production Storage and Offloading (FPSO) will be use for

the production of crude oil and associated gas product. The well fluid will be process in a single three stage gas-oil

separation train. The gas is compressed to the export pipe line and treated to remove

water vapour and heavier hydrocarbons.

IPE FDP 2014 - Team A 06/19/14 103

Surface Processing Topsides Facilities• Produced water disposal

104IPE FDP 2014 - Team A05/02/2023

Corrugated Plate Interceptor

Induced Gas floatation Unit

Surface Processing• Topsides Facilities Main Utility Systems: The main utility systems associated with the

topsides operations consist of:– Chemical injection– Emergency power generation– Electrical power generation– Cooling and Heating medium– Relief and Flare facilities– Diesel and Potable water

105IPE FDP 2014 - Team A05/02/2023

IPE FDP 2014 - Team A 10605/02/2023

SUBSEA PRODUCTION AND ASSOCIATED FACILITIE

Well Completions– The wellhead will be a conventional manufacturer’s standard

product rated according to Closed In Tubing Head Pressures (CITHP).

– Allowing the use of any mobile drilling rig (MODU).– Completions will be single string. – Sub-assemblies and material selection specified to minimise

planned work-over operation. – Down-hole monitoring equipment will be used for all producers

and injectors.

107IPE FDP 2014 - Team A05/02/2023


Subsea Trees and Controls• The wellheads will be design to resist 65 tonnes snag loads and a

safety margin will be imposed. Subsea Manifolds• Provision for manifold will be provided for the future use of

water injection for the two required functions of water injection and control.

108IPE FDP 2014 - Team A05/02/2023


Subsea Flow-lines

• The design will allow for hydraulic and thermodynamic regimes to

be adjusted during start up and shut down.

• The flow line will be run to the FPSO via flexible risers.

• The system design will allow circulation and pigging operation.

PRODUCTION EXPORT SYSTEM

Oil Export

• The crude oil produced will be exported from floating production storage

and offloading unit (FPSO) via tie back to the existing pipeline facility.

• The presence and proximity of existing pipeline which is about 70km

which currently serve Clair field is our selection (Assuming the existing

pipeline are capable to handle the production from our field).

IPE FDP 2014 - Team A 06/19/14 109

PRODUCTION EXPORT SYSTEM

Gas Export

The gas export will be carried out via existing gas pipe-line facility.

The nominal pipe-line diameter will be 12in from the FPSO to the deep gas diverter.

The discrete segment of the gas export pipe-line comprises:

• A rigid carbon steel pipe-line to the Deep Gas Diverter;

• An expansion spool-piece and tie-in facilities at the Deep Gas Diverter;

• Flexible riser from the FPSO to a Pipe-line End Manifold (PLEM) (which will also

house a Subsea Isolation Valve (SSIV));

• An expansion spool-piece connecting the pipe-line to the PLEM/SSIV.

IPE FDP 2014 - Team A 06/19/14 110




111IPE FDP 2014 - Team A05/02/2023


06/19/14 112

RESERVOIR MANGEMENT & MONTIORING

• Typical Well test.• Production profile

management.• Downhole permanent

Sensors:– Optical Sensing System.

• Flow Meters.• 4D seismic • Surveillance program.


Reservoir Management Process




113IPE FDP 2014 - Team A05/02/2023





114IPE FDP 2014 - Team A05/02/2023


ABANDONMENT

• Cessation of the production of 1,027 BPD is determined using economic screening criteria.

• All reasonable provisions will be made during the design construction and operational phases of the development to facilitate abandonment.

• Technique for all aspects of abandonment and removal will be reviewed from time to time during the project life.

115IPE FDP 2014 - Team A05/02/2023




116IPE FDP 2014 - Team A05/02/2023


ECONOMICS

Key Assumptions

• Oil price (2014): $103.25/bbl• Gas price (2014): $10.95/bbl• Discount Factor: 10% (Constant) (industry standards)• Field considered as standalone, for taxation purposes• Tax: 62% (corporate tax 30% + supplementary tax 32%)• Opex and Capex: Simulated using IHS-Questor economics

software

(Woodmackenzie UK Country Report)

117IPE FDP 2014 - Team A05/02/2023

05/02/2023 IPE FDP 2014 - Team A 118

Uncertainties

06/19/14 119

Concept Scenarios1. FPSO + Subsea2. Production Platform + Subsea Tieback3. Semi-submersible + Subsea Tieback

For 10 producer wells and 6 injector wells the three cases were simulated.Parameters to be satisfied for a project to be viable:

NPV[i] > =0 NPVI[i] > = 0

IRR > = i


06/19/14 120

Development Options


Parameters FPSO + Subsea via existing pipeline

Platform + Subsea Tieback via existing

pipeline

Semi-submersible + Subsea via

existing pipelineMCO (MM$) -535 -522 -552

Payback (years) 3 3 3

NPV[0.10] 7727 7696 7709

NPVI[0.10] 14.42 14.74 13.97

IRR (%) 150 129 145

OPTIMUM CASE

06/19/14 121

Optimum Case NPV vs. Discount Factor


0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 10

2000

4000

6000

8000

10000

12000

14000

16000

18000

20000

NPV Profile

NPV Profile

Discount Factor

NPV

, MM

USD

06/19/14 122

Optimum Case Cumulative Discounted

Cash Flow


0 5 10 15 20 25 30-1000

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

Year

CUM

DCF

Payback period = 3 Years MCO = $535 MMTCS = $7,727 MM

Used to determine the size and profitability of the project.

Optimum Case Sensitivity Analysis

123IPE FDP 2014 - Team A05/02/2023

0.4 0.6 0.8 1 1.2 1.4 1.6 1.8 22500

3500

4500

5500

6500

7500

8500

9500

10500

11500

12500Field Spider Diagram

CapexopexTaxOil Price

Proportional Change

NPV

Spider Diagram is showing variation in capex, opex, tax and oil price.

Varying one parameter at a time.

Taxation has the highest effect in

NPV value

Engineering

MSc group project presentation