1. Presented by : Supervised by:
Chibani Amira M.Samia BENALI
SAKHRAOUI Safwan Mr.Med BOUGACHA
Republic of Tunisia
Ministry of higher education and scientific research
National Engineering School of Gabes
Prefeseability study of petroleum field

2. Plan
Case of study
Flow assurance
Crude oil unit design
Conclusion
Introduction
Economic review

3. To produce
the
hydrocarbon
To predict
existence
of the
reservoir
1
Geological Development
Oil & gas
process
Metering
& storage
Seismecs
activities
•Appraisal
wells
•Design
•Building the
installations
•Vessel
•loading
•Differents
units of
treatment
1.Introduction
Oil & gas life cycle

4. wastes
Gas traitement
Oil traitement
Water traitement
Three phase
separator
2
Introduction Oil & gas process

5. The purpose of this project is to :
3
Solve the gas shortage problem
Design of pipeline using PIPESIM software
Design of crude oil production unit
1.Introduction

6. 4
Problematic
Scenario
Local cost estimation
2.Case of study

7. ASHTART GAS RESERVOIR
5 MW/DAY
80
100
120
140
160
180
2014 2016 2018 2020 2022 2024 2026
m3/DAY
YEARS
64.24 MM $
33.22 MM $
Problematic
5

8. How to compensate Diesel
consumption to generate power
energy ?
6

9. 7
Problematic
Scenario
Cost estimation
2.Case of study

10. 35km
Importing sufficient gas from close sites
 main drawback of this scenario is the dependency of our site on
others.
This scenario is rejected 8
• we need to install new pipelines network
for 35 km
Scenario 1

11. 67km
Onshore
Offhore
Such instalation of submersible cable is very costly
and technically hard to realize
Setting new cable installation with 67km of length to
dilever electricity to ASHTART offshore platform.
This scenario is rejected
Scenario 2
9

12. Treated gas
CO2 used for
tertiary recovery
FSO
Installing new membrane unit to treat gas coming from bireno reservoir storage and
sale of treated gas
• Drilling 8 wells wehre CO2 will be injected as tertiary recovery fluid
• Extracted oil will be sent to treatment or process platform by FSO Floating storage
and offloading.
An economic study will be carried in order to justify the choice of this scenario
.
Scenario 3
10

13. 11
How to treat the upcoming
gas from bireno ?

14. BIRENO Well
65% CO2
Membrane unit Amine unit
• Weight and size
• No regular maintenance required
• Low cost installation
• Proven performance for high level CO2
12

15. 13
Problematic
Scenario
Local cost estimation
2.Case of study

16. Number Cost [MM$]
Wells 6 60
Membrane unit 1 20
Injection well 2 < 40
Platform 1 150
FSO (floating storage
offloading )
1 50
Cable cost x 150 + 10
Production Wells 8 160
WHP (well head
production)
1 50
14
CAPEX 710 MM$
Local cost estimation

17. PIEPSIM
Building the physical model and entering the
input data
Pipeline sizing simulation
Analyzing the output data according to
pressure drop
Local cost estimation
15
3.Flow assurance

18. 16
Treated gas Pipeline
Oil pumping pipeline
CO2 injection pipeline
3.Flow assurance

19. Inside diameter [inch] Inlet pressure [Psia]
6 324.7063
8 268.62
10 255.191
12 250.1592
14 249.1203
17
Treated gas pipeline

20. Inside diameter [inch] Inlet pressure [Psia]
6 309.9354
8 307.7446
10 307.1164
12 306.8911
18
Oil pumping pipeline

21. Inside diametrer
[inch]
Inlet pressure [Psia]
8 308,1
10 307,17
12 306,89
14 306.8
16 306.76
18 306.74
19
CO2 injection pipeline

22. Separation
Expansion
Heating
Separation
Pumping
Mixing
Desalting
Stabilisation
Cooling
4.Crude oil unit design
21
• The mixture enter the slug catcher to
separate liquid phase from gas
• Liquid phase passes by valve where it will be
expanded
• Cold liquid enter the HE in order to be heated• The mixture goes to the three phase
separator to eliminate the remaining gas
• Separated oil will be pumped and mixed
with water
• The new mixture goes to the desalter to
eliminate the remaining salts
• Desalted oil will be stabilized in the
absorber reboiler
• The stabilized oil will be cooled in the air
cooler

23. Liquid phase capacity retention time3
4 Feed, exist pipe and mist extractor diameter
Separator height5
Gas capacity Souders-Brown KSB factor2
Slug catcher design estimation1
22
Slug catcher design steps

24. volume of liquid in separator (ft3) 1306.2
height of liquid level in separator (ft) 12
diameter of feed pipe (ft) 0.94
height of feed pipe (ft) 1.88
Inside diameter (ft) 3.59
Height (ft) 7.19
23
Slug catcher design results

25. Liquid phase capacity retention time3
4 Weir and bucket heights
Separator dimensions5
Gas capacity Souders-Brown KSB factor2
Approximate separator dimensions1
24
Three phase separator design steps

26. Volume of liquid in the separator (ft3) 232.2
Height of liquid in the separator (ft) 19.11
Separator diameter (ft) 6.38
Height of water-oil interface in separator (ft) 10.57
Height of water weir (ft) 15.97
Inside diameter of separator (ft) 3.96
Lenght of separator shell(ft) 25.48
25
Three phase separator design results

27. Heat transfer area and shell side diameters3
4 Number of tube
Shell side and tube side heat transfer5
Estimation of overall heat transfer2
Determination of Toutlet, Theol
1
6 Shell side and tube side pressure drop
26
Heat exchanger design steps

28. Overall heat transfer coefficient [Btu/ft2.hr.°F] 446.8
Heat transfer area [ft2] 2338.9
Shell side diameter [inch] 21.9
Number of tubes 208
Shell side heat transfer [Btu/ft2.hr.°F] 3609.5
Tube side heat transfer [Btu/ft2.hr.°F] 832.32
Shell side pressure drop (Pa) 240.77
Tube side pressure drop (Pa) 1705.25
Tube length (ft) 43
Number of baffles 15
27
Heat exchanger design results

29. Calculate number of tubes3
4 Determine Air face mass velocity
Calculate overall transfer coefficient5
Determine required surface2
Estimate overall heat transfer1
6 Determine fan diameter
28
Air cooler Design steps

30. Tube length (ft) 3.964
Tubes number 7
Tube length (ft) 30
Tube side film coefficient (Btu/hr.ft2.°F) 18.454
Air side film coefficient (Btu/hr.ft2.°F) 56
Overall heat transfer (Btu/hr.ft2.°F) 12.983
Number of fan 2
Fan area per fan (ft2) 9.087
Diameter of fan (ft) 2.624
29
Air cooler Design results

31. CAPEX & OPEX
Turnover
Key
words
Cash Flow& Net Present
Value
30
5.Economic review

32. Year Index CF (MM$) NPV (MM$)
2015 -2 -50
2016 -1 -50
2017 0 366,1 366,1
2018 1 366,1 699,92
2019 2 366,1 1 002,48
2020 3 366,1 1 277,54
2021 4 366,1 1 527,59
2022 5 158,05 1 625,72
2023 6 158,05 1 714,93
2024 7 158,05 1 796,03
2025 8 158,05 1 869,76
2026 9 158,05 1 936,79
2027 10 158,05 1 997,72
2028 11 158,05 2 053,11
2029 12 158,05 2 103,47
2030 13 158,05 2 149,26
2031 14 158,05 2 190,88
2032 15 54,025 2 203,80
2033 16 54,025 2 215,56
2034 17 54,025 2 226,25
2035 18 54,025 2 235,96
2036 19 54,025 2 244,80
31

33. NPV increase 10 years coming
Cost effective project
-5E+10
0
5E+10
1E+11
1.5E+11
2E+11
2.5E+11
3E+11
2012 2014 2016 2018 2020 2022 2024 2026
NPV
Year
32
6.Economic study

34. Project confirmation
33
We used bireno gas in order to compensate the energy shortage.
In this project we had chosen the third scenario :
Pipeline sizing and crude oil design was necessary for the prefeasibity
An economic review
7.Conclusion

35. THANK YOU FOR YOUR
ATTENTION