pete 402 - hodhod final presentation

Hodhod Field Development ProjectPETE 402 – Capstone Project

Abdul Salam Abd Abdul Saboor Khan Bashar ELTahir Muna AL Nuaimi

1

Introduction

• Location: Southeast Asia Island

• Country: State of Pennaga

• Capital: Arcadia

• Governing Regime: Democratic

• Environment: Tropical Rainforests

• Geography:

– Below regional typhoon belt

– Coastline benign conditions within 100 Km

– Land preservation by World Wildlife Fund

• Population: 37 Million

• GDP per capita: $320

• Area: ~250,000 km2

• Trade: India and China

• Current Issue:

– Unfair spending in the south

– Recession

• Arcadia National Oil Company (ANOC)

• Agreement: Production Sharing

Contract

• Threat: Maritime Pirates

HodhodKanar

Neser

Sakir

2

Scope

• Quantify the volume of resources and quality of

crude oil in the offshore Hodhod field reservoir.

• Develop a FDP to produce the oil meeting the State

of Arcadia oil demand for local utilization and

international sales.

• Quantify the potential economic benefits to the State

of Arcadia and stakeholders including local

communities and shareholders.

• Ensure the safe execution and development of the

field, sustaining the social, health and economic

well-being for Arcadia.

• Give back to the Community. Develop programs to

integrate Arcadians into the workplace, utilizing their

expertise and providing them with the required skills.

3

Pre-Evaluation Evaluation Development

Execution

&

Manageme

nt

Methodology

Gate

1Gate

2

Final

Investment

Decision

Identify and Assess

Exploration Opportunity

Analyze Reservoir

Deliverability

Evaluate Alternative

Options and Optimize

Development Plan

Execute Development

Plan

Manage Production Life

Cycle

• Data Collection

• Environment Assessment

• Identify Major Risks and

Assess Hazards

• Develop Geological Model

• Develop Static Reservoir

Model

• Identify OOIP

• Select Alternative Methods and

Evaluate Each

• Select Technically Feasible and

Economically Viable Plan

• Evaluate Return on Investment

• Identify all Uncertainties (Risks

and Hazards)

• Develop Safety Programs and

Key Performance Indicators

• Analyze Geologic Model

• Select Well Locations

• Run Base Case

4

Pre-Evaluation

Methodology

Pre-Evaluation Evaluation DevelopmentExecution &

ManagementGate

1

Gate

2

Final

Investment

Decision

Identify and Assess

Exploration Opportunity

• Data Collection

• Environment Assessment

• Identify Major Risks and

Assess Hazards

• Develop Geological Model

• Develop Static Reservoir

Model

• Identify OOIP

Reservoir Characterization

Reservoir Properties

Pre-Evaluation

5

Lithology Petrophysical properties

The reservoir formation layers are :

Limestone and Dolomite

Major diagenetic processes active

in the Bandung reservoir include:

Dolomitization

Dissolution and formation of

Microporosity

Cementation

Compaction

Porosity: 15%

Average Permeability: 534.16 md

Thickness: 10.5 ft

Porosity: 20%


Thickness: 37.5 ft

Porosity: 21%


Thickness: 46.5 ft

Porosity: 21%


Thickness: 37.5 ft

Porosity: 13%


Thickness: 21.5 ft

Petrophysical Analysis

6

Reservoir Properties

Parameter Value

Reservoir Pressure 4180 psi

Bubble Point Pressure 3500 psi

Reservoir Temperature 217 F

Oil Gravity 42 API

Formation Volume Factor 1.48 BBL/STB

Solution Gas-Oil Ratio 211 SCF/STB

Oil Viscosity 2.1 cP

Oil Compressibility 3 x 10-5 psi-1

Rock Compressibility 3 x 10-6 psi-1

Reservoir properties for the developed area in Hodhod Reservoir

G

F

E

Bandung

C

B

A

Bandung-A

Bandung-B

Bandung-C

Bandung-D

Ban

du

ng

1

2A

2B

3A

3B

4

Jurassic petroleum system stratigraphy, Hodhod field

7

Rock Classification Curves

0.01

0.1

1

10

100

1000

10000

100000

0.1 0.15 0.2 0.25 0.3 0.35

Pe

rme

abili

ty (

md

)

Porosity

Grainstone Wackestone Packstone Marlstone Rock I Rock II Rock III Rock IV

8

Porosity-Permeability Relationship

0.1

1

10

100

1000

10000

0 5 10 15 20 25 30 35

PER

MEA

BIL

ITY

(M

D)

POROSITY

Sample cross plot of Layer 1 showing

porosity-permeability relationship

9

Determination of Sw

𝑃𝑐𝑒 = 𝐴. 𝑘−𝐵

𝑃𝑐𝑓 = 𝐶. ln 𝑘 − 𝐷

𝑆𝑤 = 𝐵ℎ(𝜌𝑤 − 𝜌𝑜)]

𝑃𝑐𝑒

100𝑃𝑐𝑓

1𝑃𝑐𝑓

8380

8400

8420

8440

8460

8480

8500

8520

8540

8560

0 0.2 0.4 0.6 0.8

Dep

th (

ft)

Sw

𝑃𝑐𝑒 is the Oil-water capillary threshold entry

pressure (psi)

𝑃𝑐𝑓 is pore size heterogeneity fractal dimension

• Calculation

• Quality Control

10

Quality Control

8380

8400

8420

8440

8460

8480

8500

8520

8540

8560

0 0.1 0.2 0.3 0.4

De

pth

(ft

)

Porosity (fraction)

H-3

H-4

H-5

H-6

Original

8380

8400

8420

8440

8460

8480

8500

8520

8540

8560

0 0 1 10 100 1,000

De

pth

(ft

)

Permeabilty (md)

Original

H-3

H-4

H-5

H-6

11

Relative Permeability Curves

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

Re

lati

ve P

erm

eab

iltiy

(Fr

acti

on

)

Water Saturation (fraction)

Kro

Krw

- Swc = 0.2

- Sgc= 0.06

- Sor = 0.33

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

Rel

ativ

e P

erm

eab

iltiy

(Fr

acti

on

)

Gas Saturation (fraction)

Krg

Kro

-15

-10

-5

0

5

10

15

20

25

0 0.2 0.4 0.6 0.8 1

Cap

pilary

Pre

ssu

re (

Psi)

Water Saturation

spontaneous oil imbibition saturation

12

Static Model

• 20 Km x 5 km

• 100 m x 100 m

• 416,000 cells

• Sealing Faults

• Anticline, 3 crests

• OWC = 8675 ft

• Weak Aquifer

• STOIP = 3.124 Bstb

13

Geostatistical Realizations

3D Permeability Realization 3D Porosity Realization 3D Water Saturation Realization

Sample Horizontal Variogram for Porosity – Major Direction

- Nugget: 0

- Sill: 1

- Major Range:4120 ft

14

Fluid Composition

C130%

C2-C48%

C5-C83%

C9-C1755%

C18-C263%

C27-C351%

C1

C2-C4

C5-C8

C9-C17

C18-C26

C27-C35

• Downhole fluid Sample

• Laboratory Test

• Components combined to simplify

simulation runs

• Solution Gas-oil Ratio : 211scf/stb

15

Evaluation

Methodology

Pre-Evaluation Evaluation Development

Execution

&

Manageme

nt

Gate

1

Gate

2

Final

Investment

Decision

Analyze Reservoir

Deliverability

• Analyze Geologic Model

• Select Well Locations

• Run Base Case

Analyze Geologic Model

Select Well Locations

Run Base Case

Evaluation

16

Development Strategy

• Optimum well positioning :a) Productivity

b) Sweep efficiency

c) Permeability

d) Faults

e) Saturations

f) Structure

• Economic Limit – 0.78 Watercut

• Reservoir targeted to be kept above bubble point

• Target Plateau production rate is set at 120,000 STB/D

17

Development Strategy

18

Case 1: Vertical Wells

• Producers on the crests

(45 total)

• Injectors on the periphery

(15 total)

• 12.9 % Recovery

19

Case 2: Horizontal Wells

• 17 Producers targeting

Layer 2 and 3

• 18.7 % Recovery

20

Development

Methodology

Pre-Evaluation Evaluation DevelopmentExecution &

Management

Gate

1Gate

2

Final

Investment

Decision

Evaluate Alternative

Options and Optimize

Development Plan

• Select Alternative Methods and

Evaluate Each

• Select Technically Feasible and

Economically Viable Plan


• Identify all Uncertainties (Risks

and Hazards)

• Develop Safety Programs and

Key Performance Indicators

• Select Alternative Methods and Evaluate Each

• Select Technically Feasible and Economically Viable Plan


• Identify all Uncertainties (Risks and Hazards)

• Develop Safety Programs and Key Performance Indicators

Development

21

Case 3: Horizontal Wells – Waterflood

• 10 Injectors drilled at a lower layer

below the producers

• 28.0 % Recovery

22

Case 3: Horizontal Wells – Waterflood

23

Case 4: SDS Surfactant

• Starts 11 years after Production

• Surfactant alters the wettability from

mixed wet to water wet

• Reduces residual oil saturation by

reducing the surface tension

• Cheaper facility alteration

Sodium dodecyl sulfate

Molecule

24

Case 4: Horizontal Wells – Surfactant Flood

0

0.2

0.4

0.6

0.8

1

1.2

0

20000

40000

60000

80000

100000

120000

140000

0 5 10 15 20 25 30

Cu

m o

il -B

stb

Rat

e –

stb

/D

Time (Years)Oil Rate Oil Cummulative

0

50000

100000

150000

200000

250000

0

500

1000

1500

2000

2500

3000

3500

4000

4500

0.00 5.00 10.00 15.00 20.00 25.00 30.00

Rat

e –

stb

/D

Pre

ssu

re -

psi

Time (Years)Pressure Water Injection Rate

0

0.05

0.1

0.15

0.2

0.25

0.3

0.35

0.4

0

10000

20000

30000

40000

50000

60000

70000

80000

0.00 5.00 10.00 15.00 20.00 25.00 30.00

Wat

er C

ut

Rat

e –

Mst

b/D

Time (Years)Water Production Rate Water Cut

0

50

100

150

200

250

0

20

40

60

80

100

120

140

160

180

0.00 5.00 10.00 15.00 20.00 25.00 30.00

GO

R –

Scf/

stb

Cu

m G

as -

MM

scf

Time (Years)Gas Production GOR

25

Case 4: WAG using Rich Gas

32%

17%26%

17%

6%

2%

C1

C2

C3

C4

C5

C6

• Starts 10 years after

Production

• 6 cycles; 4 months

each

Rich Gas Composition

26

Case 4: Horizontal Wells - WAG

0

50

100

150

200

250

210212214216218220222224226228230232

0 5 10 15 20 25 30

Cu

m G

as -

MM

scf

GO

R –

Scf/

STB

Time (Years)

GOR Gas Production

0

500

1000

1500

2000

2500

3000

3500

4000

0

50000

100000

150000

200000

250000

0 5 10 15 20 25 30

Pre

ssu

re -

Psi

Rat

e –

stb

/D

Time (Years)

Gas Injection Rate - 90000 Mscf Water Injection Rate Pressure

0

0.1

0.2

0.3

0.4

0.5

0

20000

40000

60000

80000

100000

120000

0 5 10 15 20 25 30

Wat

er C

ut

Rat

e –

stb

/D

Time (Years)Water Production Rate

0

0.2

0.4

0.6

0.8

1

1.2

1.4

0

20000

40000

60000

80000

100000

120000

140000

0 5 10 15 20 25 30

Cu

m O

il -

Bst

b

Rat

e –

stb

/D

Time(Years)Oil Rate Oil Cummulative

27

Production Profile

0

20000

40000

60000

80000

100000

120000

140000

0 5 10 15 20 25 30

Oil

Rate

(bbls

)

Years of Production

Waterflood

Surfactant

WAG

6 Years

8 Years

Production Optimization

29

Skin Factor Sensitivities Target Liquid Production : 14,000 STB/Day

2500

2700

2900

3100

3300

3500

3700

3900

4100

4300

4500

0 5,000 10,000 15,000 20,000 25,000 30,000 35,000 40,000 45,000 50,000

Bo

tto

m-H

ole

Flo

win

g P

ress

ure

(p

si)

Flow Rate (STB/D)

S=10

S=5

S=0

S=-3

OD=3.5 in

OD=5 in

OD=6.25 in

30

Controlled Acid Jetting (CAJ)

• Acid injected through drillpipe

• Covers zones up to 15000 ft

• Uniform matrix acid treatment along long

wellbores

Controlled Acid Jetting Technique (CAJ) Concept (Hansen and Nederveen 2002)

31

Production Tubing

2500

3000

3500

4000

4500

5000

0 10,000 20,000 30,000 40,000 50,000

Bo

tto

m-H

ole

Flo

win

g P

ress

ure

(p

si)

Flow Rate (STB/D)

Target Liquid Production : 14,000 STB/Day

32

Production Tubing (With ESP)

0

500

1000

1500

2000

2500

3000

3500

4000

4500

5000

5500

0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000

Bo

tto

m-H

ole

Flo

win

g P

ress

ure

(p

si)

Flow Rate (STB/D)

33

Completion Schematic

• Total Measured Depth : 26229 ft

• Dog leg severity : 3˚/100 ft

• Kick-Off point: 3000 ft

• Tubing size: 5” OD

34

Drilling Window

0

1000

2000

3000

4000

5000

6000

7000

8000

9000

10000

7.7 8 8.3 8.6 8.9 9.2 9.5 9.8 10.1 10.4 10.7 11 11.3 11.6

De

pth

[ft

]

Equivalent Mud Density [ppg]

Pore Density

Fracture Density

Trip Margin

Kick Margin

35

Conductor Hole Section:

Drill with 26” Milled Tooth

Mud Weight: 8.8 ppg

Casing: 20” J-55

Cement Weight: 16.6 ppg

Surface Hole Section:

Drill with 17.5” Milled Tooth

Mud Weight: 9 ppg

Casing: 13.5” J-55

Cement Weight: 10 ppg

Intermediate Hole Section:

Drill with 14.75” TCI

Mud Weight: 9.7 ppg

Casing: 9.625” Q-125


Production Hole Section:

Drill with 8.75” PDC

Mud Weight: 10.5 ppg

Liner: 7” L-80 26


$ 52,000

$ 119,000

$ 485,000

$ 495,000

$ 1.2 MM

High

Moderate

Low

Negligible

Ris

k r

ati

ng

2920 ft

3000 ft

11114 ft

MD

36

Surface Facility Design

37

Surface Facilities

SAB

BAS

ABD

38

Surface Facilities

Wellhead

Platforms

SAB

5 Producers

4 Injectors

WHP: 800psi

Wellhead

Platforms

ABD

6 Producers

4 Injectors

WHP: 800psi

Wellhead

Platforms

BAS

5 Producers

6 Injectors

WHP: 800psi

3 Phase Separator

Oil Production

Rate:

140,000 STB/D

Water Production

Rate:

70,000 STB/D

GOR: 211

SCF/STB

Gas Production

Rate:

30 MMSCF/D

Diameter: 120 in

Total Length: 48 ft

WHP: 200psi

Emulsion

TreatmentDe-Salting Sweetening

Sweetening Softening Re-Injection

Water

Oil

Dehydration Sweetening Compression

Gas

Storage

Re-InjectionNon-Thermal

Plasma

39

Non-Thermal Plasma Reforming

CH4 C2H6

• Generated e- collides with the molecules

• Ionization and electron excitation

• Ionized molecules recombine forming longer Chains

40

Scheduling & Economic Analysis

41

Mar Jun Sep Dec Mar Jun Sep Dec Mar Jun Sep Dec Mar Jun Sep Dec Mar Jun Sep Dec Mar Jun Sep Dec Mar Jun Sep Dec Mar Jun Sep Dec Mar Jun Sep Dec Mar Jun Sep Dec Mar Jun Sep Dec

Offshore Separation Facilities

EIA

Tangible Procurement

SAB Jacket Mobilization

Rig-1 Mobilization

SAB Wells (D&C)

Topside Installation & Hookup

Pipeline Construction

Tangible Procurement

ABD & BAS Jacket Mobilization

Rig-1 Mobilization

BAS Wells (D&C)

Rig-2 Mobilization

ABD Wells (D&C)

Topside Installation & Hookup

Pipeline Construction

Key: Surface Operations Subsurface Operations Contractual Operations

7-Producers & 3-Injectors


2025 2026


2019 2020 2021 2022 2023 20242016 2017 2018

Operations Schedule

SAB Production Begins

ABD & BAS Production

Begins

42

Economic Indicators

VerticalHorizontal Water

FloodSurfactant Flood WAG

NPV

(B$)4.5 19.3 20.8 26.3

IRR

(%)15 18 21 24

Payout period

(Years)6 11.5 12 11

Recovery Factor

(%)12.9 28.0 30.7 35.2

-5

0

5

10

15

20

25

30

2015 2020 2025 2030 2035 2040 2045 2050 2055

NP

V (

B$

)

Years

Surfactant

No Water

WAG

Water

Vertical

44

Economics for WAG

-5

0

5

10

15

20

25

30

-600

-400

-200

0

200

400

600

800

1000

1200

1400

1600

180020

17

2018

2019

2020

2021

2022

2023

2024

2025

2026

2027

2028

202

9

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040

2041

2042

2043

2044

2045

2046

204

7

2048

2049

2050

2051

2052

Bill

ion

$

Mill

ion

s $

capex Opex Tax Tax Shield Revenue NPV ($B)

45

Sensitivity

10

15

20

25

30

35

40

-50 -40 -30 -20 -10 0 10 20 30 40 50

NP

V (

bill

ion

$)

Variation %

Oil Price CAPEX OPEX

P10 P50 P90

NPV (B$) 48.0 26.3 4.78

IRR (%) 30 24 4

46

Safety

• Pressure consideration while drilling

• Streamlined operations

• Health & Safety

• Environment

• Risk Matrix

Marine geo-hazardsPore Pressure

Prediction

Maritime PiratesSubsurface

Compartmentalization

Survey and Positioning

Integrity

HSSE Incidents Operations

Plan

DoCheck

Learn

Probability

Co

ns

eq

ue

nc

es

47

Recommendations

• Water Injection is performed at early stages to maintain

the reservoir pressure above bubble point

• EOR significantly improves Economic value of Hodhod

field in later life

• 6 cycles of rich gas for WAG injection is the preferred

EOR technique with ultimate recovery

48

Thank You !!

49

pete 402 - hodhod final presentation

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