Date post: | 23-Jan-2018 |
Category: |
Documents |
Upload: | abdul-salam-abd |
View: | 139 times |
Download: | 2 times |
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%
Average Permeability: 454.14 md
Thickness: 37.5 ft
Porosity: 21%
Average Permeability: 160.83 md
Thickness: 46.5 ft
Porosity: 21%
Average Permeability: 78.33 md
Thickness: 37.5 ft
Porosity: 13%
Average Permeability: 132.14 md
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
• Evaluate Return on Investment
• 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
• Evaluate Return on Investment
• 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
Cement Weight: 11 ppg
Production Hole Section:
Drill with 8.75” PDC
Mud Weight: 10.5 ppg
Liner: 7” L-80 26
Cement Weight: 12 ppg
$ 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
5-Producers & 4-Injectors
2025 2026
6-Producers & 3-Injectors
2019 2020 2021 2022 2023 20242016 2017 2018
Operations Schedule
SAB Production Begins
ABD & BAS Production
Begins
42
43
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