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• SAMREF Refinery
• My unit area A1 processes
• Case studies
• Experiences
2
• Started operating in 1984 by the joint venture of Petromin &
Mobil Oil Corporation (PEMREF)
• Saudi Aramco took Petromin shares in 1993 (SAMREF)
• Initial design processed 250,000 BPD of Arabian Light Crude Oil
• Nowadays, design reached around 400,000 BPD capacity
3
25%
30%15%
18%
10% 2%
Premium Gasoline
Diesel Oil
Jet Fuel
Marine Fuel Oil
Regular Gasoline
Sulfur
4
5
• Technical Department (Process, Project, Design, Training)
• Operation Department ( Control, Shelters)
• Maintenance Department ( Inspection, Maintenance)
• Finance and Accounting Department ( Management, Human-
-Resource, Security)
6
7
Area A1 units
8
9
10
11
12
13
Case Studies
14
• Objective:
– Learn PI tag system integration with Excel
– Calculate yield using actual live data (10 years range)
15
Crude Distillation Unit Stream flow (m3/day) Tag No. from PI system
Input CDU Feed 11FNQX001.
Output
Naphtha 11FN091.
Kero 11FN092. + 32FN658.
LGO 11FN093.
HGO 11FI094.
CDU Bottom (Resid) 12FN003.
𝒀𝒊𝒆𝒍𝒅 𝒘𝒕% =
𝑪𝒐𝒎𝒑𝒐𝒏𝒆𝒏𝒕 𝑭𝒍𝒐𝒘
𝑭𝒆𝒆𝒅 𝑭𝒍𝒐𝒘
∗ 𝟏𝟎𝟎
16
17
18
• Flowrates were balanced most of the ten years (input = output)
• Kerosene flow reading (32FN658.) had very low readings until 2013.
The reason according to Eng. Abdulaziz was CHD unit was too small
and was improved in Jan 2013
• Some turnarounds and shut down periods were noticed in the figures
(yield % = around zero)
• Shut down in April 2016 (last bottom peak) in VDU while I was a
trainee
19
• Objective:
– Find actual and theoretical heat transfer coefficients
– Calculate fouling rate to predict when the unit needs cleaning
20
21
Tube-
Light
Arabian
Crude
Density ρ 778.5 Kg/m3
Specific Heat(Cp) 2.395 KJ/(Kg.C°)
Surface Area 240.74 m2
Thermal Cond. (k) 0.1135 w/m.C°
Viscosity (µ) 1.4 mPa.s
Velocity U 3.5 m/s
outside diameter 254 mm
Thickness. 2.74 mm
inside diameter 251.26 mm
22
y = 2.688x - 80.21
R² = 0.9935
0.000
100.000
200.000
300.000
400.000
500.000
600.000
700.000
800.000
0 50 100 150 200 250 300 350
U(KW/m2.C°)
Feed Flowrate (kg/s)
Actual Heat Transfer Coefficient U (W/m2.C°) (23/Apr to 11/June) in
2010
Actual U
Linear (Actual U)
This equation is used
to find U theoretical
23
0.000
100.000
200.000
300.000
400.000
500.000
600.000
700.000
800.000
U(KW/m2.C°)
Actual & Theoretical Heat Transfer Coefficients U , During 2016
Actual U
Theoritical U
24
0.000
50.000
100.000
150.000
200.000
250.000
FoulingFactor(W/m2.C°)
Fouling Rate, During 2016
25
y = 0.0145x - 556.33
R² = 0.3983
0.000
10.000
20.000
30.000
40.000
50.000
60.000
70.000
80.000
90.000
100.000
28/May/05 10/Oct/06 22/Feb/08 6/Jul/09 18/Nov/10 1/Apr/12 14/Aug/13 27/Dec/14
Foulingrate
Fouling Rate for 11-E-01
This is the after cleaning
period used to get the
theoretical U
• Difference between Theoretical and actual U was noticeable, so
not very efficient is not optimum
• Fouling rate figure during 2016 shows non stability, there are
several reasons for this and they need to be checked
• Some optimization techniques were suggested to improve the
efficiency of these heat equipment. Also to decrease the load on
some suboptimal equipment.
26
• Objective:
– Understand how pumps cavitates and malfunction
– Evaluate efficiency, hydraulic power, total head, net positive
suction head required and absolute
– Suggest methods to improve the NPSHa
27
28
= Efficiency
First, we start by reconstructing the pump data sheet figures
29
Calculated
Capacity (M3/hr) Total head (Meter)
Hydraulic
power
BHP (Kw) Efficiency %
0 782.8 0.0 371.7
0.0
63.5 763.7 122.8 404.7
30.2
142 754.7 271.3 495.4
54.6
257.6 712.6 464.7 637.8
72.7
351 621.6 552.3 723.3
76.2
387.8 582.8 572.1 747.6
76.3
463.1 456.8 535.5 777.3
68.7
Capacity
(M3/hr)
NPSHr
65 3.1
145 3.3
260 4
350 5.5
380 6.4
30
456.8
777.3
68.7
y = -0.002x2 + 0.2547x + 769.21
R² = 0.991
y = -0.0006x2 + 1.2309x + 350.3
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
0
100
200
300
400
500
600
700
800
900
0 50 100 150 200 250 300 350 400 450 500
Efficiency%
TotalHead(Head),BHP(KW)
Capacity (m3/hr)
G-150-01C Pump Performance Curve
Total head (Meter)
BHP (Kw)
Efficiency %
31
Pump is in area B2
150 – Boilers
No access to P&ID’s was
granted to me.
PI Tag
Numbers
98fic021 98fic041 98fic061 98fi703 - -
Weekly data
Flowrate
Boiler 1
(tonne/h)
Flowrate
Boiler 2
(tonne/h)
Flowrate
Boiler 3
(tonne/h)
Flow
Users's
(tonne/h)
Total
flowrate
(tonne/h)
Actual
Capacity
(m3/h)
17-Jan-16 133.02 128.65 121.68 207.82 591.18 318.87
24-Jan-16 138.08 131.19 128.32 213.68 611.27 329.70
31-Jan-16 143.02 137.78 134.46 219.24 634.50 342.23
7-Feb-16 127.22 131.79 108.99 191.70 559.69 301.88
14-Feb-16 136.66 135.02 124.04 184.55 580.28 312.99
21-Feb-16 139.96 138.53 129.44 243.90 651.82 351.58
28-Feb-16 135.55 131.49 124.96 250.65 642.64 346.62
6-Mar-16 134.99 139.26 133.71 218.92 626.87 338.12
13-Mar-16 137.90 141.33 125.51 239.84 644.58 347.67
20-Mar-16 139.68 134.87 125.08 251.15 650.78 351.01
27-Mar-16 143.46 137.69 128.65 242.33 652.13 351.74
32
*Using
the same
total
head
equation
Shaft power
(kW) (obtained
from driver's
calculations)
716
98pi003. 98PI008.
Pressure in
(brag)
Pressure out
(brag)
Total
Head
hydraulic
Power at
current
capacity
Actual
Efficiency
%
NPSHA NPSHr
2.52 67.28 647.57 562.33 78.59 24.85 5.31
2.54 65.03 624.86 561.05 78.41 25.20 5.51
2.92 63.90 609.80 568.34 79.43 31.33 5.76
2.63 62.73 601.07 494.15 69.06 26.52 5.00
2.52 68.37 658.45 561.24 78.44 24.85 5.20
2.56 64.70 621.36 594.93 83.15 25.44 5.96
2.45 65.20 627.54 592.38 82.79 23.59 5.85
2.56 66.26 637.01 586.56 81.98 25.38 5.68
2.60 65.36 627.61 594.23 83.05 26.10 5.87
2.48 64.92 624.34 596.82 83.41 24.17 5.95
2.40 64.81 624.12 597.84 83.56 22.82 5.96
• NPSHa was noticed to be a critical aspect of a pump efficiency
• NPSHr is usually uncontrollable, because it is designed by
company that built it
• Allowing higher level in the supply tank will reduce chance of
pump cavitation
• Frictional loss could be decreased by reducing valves, strains, and
length of the piping
33
Experiences Acquired
34
• 2 Weeks of rich preparatory induction program (full day class)
– Chemical Engineering for 1 week
– Mechanical Engineering for 2 days
– Electrical Engineering for 2 days
– Control & Instrumentation for 1 day
35
36
• First meeting of
engineer and
managers
37
SL# Equipment Tag System
Line
Size
Type Equipment Details Area Unit
Flare
Header
P&ID Ref
Pipe VENT FM 31-K-03B 31-K-03 2" VENT MAKE UP GAS TO CHD LINE B1 HRU CFP C0EF-031B1-009
1 66-PSV-004 66-D-13 3" PSV Hydrogen make up from CCR B1 MDU CFP C0EF-066B1-011
2 66-PSV-177 66-D-13 8" PSV Hydrogen back up from HRU B1 MDU CFP C0EF-066B1-011
3 66-PSV-015 66-M-01A 6" PSV FCC Gasoline Feed from USGP B1 MDU CFP C0EF-066B1-012
4 66-PSV-016 66-M-01B 6" PSV FCC Gasoline Feed from USGP B1 MDU CFP C0EF-066B1-012
5 66-PSV-021B 66-D-01 6" PSV Hydrogen make-up from 66-D-13 B1 MDU CFP C0EF-066B1-013
6 66-PSV-020/030 66-D-01 16" PSV Relief from 66-D-01 B1 MDU CFP C0EF-066B1-013
7 66-PSV-034 66-E-01 12" PSV Relief from 66-E-01 B1 MDU CFP C0EF-066B1-014
8 66-PSV-044 66-E-03 10" PSV Relief from 66-E-03 B1 MDU CFP C0EF-066B1-015
9 DEPR. FM 66-E-03 66-E-03 2" Drain From 66-E03 Depressurization line B1 MDU CFP C0EF-066B1-015
10 FM 66-D-02B 66-D-02B 10" Drain Draning line B1 MDU CFP C0EF-066B1-016
38
• Objective:
– Replace two rusty heat exchanger bundles
– install new steam motive nozzles
– Test the new heat exchanger bundles (Hydro test)
39
40
Thank you for listening
41
Questions
42

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COOP training-Bokhari

  • 1.
  • 2. • SAMREF Refinery • My unit area A1 processes • Case studies • Experiences 2
  • 3. • Started operating in 1984 by the joint venture of Petromin & Mobil Oil Corporation (PEMREF) • Saudi Aramco took Petromin shares in 1993 (SAMREF) • Initial design processed 250,000 BPD of Arabian Light Crude Oil • Nowadays, design reached around 400,000 BPD capacity 3
  • 4. 25% 30%15% 18% 10% 2% Premium Gasoline Diesel Oil Jet Fuel Marine Fuel Oil Regular Gasoline Sulfur 4
  • 5. 5
  • 6. • Technical Department (Process, Project, Design, Training) • Operation Department ( Control, Shelters) • Maintenance Department ( Inspection, Maintenance) • Finance and Accounting Department ( Management, Human- -Resource, Security) 6
  • 7. 7
  • 9. 9
  • 10. 10
  • 11. 11
  • 12. 12
  • 13. 13
  • 15. • Objective: – Learn PI tag system integration with Excel – Calculate yield using actual live data (10 years range) 15 Crude Distillation Unit Stream flow (m3/day) Tag No. from PI system Input CDU Feed 11FNQX001. Output Naphtha 11FN091. Kero 11FN092. + 32FN658. LGO 11FN093. HGO 11FI094. CDU Bottom (Resid) 12FN003.
  • 16. 𝒀𝒊𝒆𝒍𝒅 𝒘𝒕% = 𝑪𝒐𝒎𝒑𝒐𝒏𝒆𝒏𝒕 𝑭𝒍𝒐𝒘 𝑭𝒆𝒆𝒅 𝑭𝒍𝒐𝒘 ∗ 𝟏𝟎𝟎 16
  • 17. 17
  • 18. 18
  • 19. • Flowrates were balanced most of the ten years (input = output) • Kerosene flow reading (32FN658.) had very low readings until 2013. The reason according to Eng. Abdulaziz was CHD unit was too small and was improved in Jan 2013 • Some turnarounds and shut down periods were noticed in the figures (yield % = around zero) • Shut down in April 2016 (last bottom peak) in VDU while I was a trainee 19
  • 20. • Objective: – Find actual and theoretical heat transfer coefficients – Calculate fouling rate to predict when the unit needs cleaning 20
  • 21. 21 Tube- Light Arabian Crude Density ρ 778.5 Kg/m3 Specific Heat(Cp) 2.395 KJ/(Kg.C°) Surface Area 240.74 m2 Thermal Cond. (k) 0.1135 w/m.C° Viscosity (µ) 1.4 mPa.s Velocity U 3.5 m/s outside diameter 254 mm Thickness. 2.74 mm inside diameter 251.26 mm
  • 22. 22 y = 2.688x - 80.21 R² = 0.9935 0.000 100.000 200.000 300.000 400.000 500.000 600.000 700.000 800.000 0 50 100 150 200 250 300 350 U(KW/m2.C°) Feed Flowrate (kg/s) Actual Heat Transfer Coefficient U (W/m2.C°) (23/Apr to 11/June) in 2010 Actual U Linear (Actual U) This equation is used to find U theoretical
  • 25. 25 y = 0.0145x - 556.33 R² = 0.3983 0.000 10.000 20.000 30.000 40.000 50.000 60.000 70.000 80.000 90.000 100.000 28/May/05 10/Oct/06 22/Feb/08 6/Jul/09 18/Nov/10 1/Apr/12 14/Aug/13 27/Dec/14 Foulingrate Fouling Rate for 11-E-01 This is the after cleaning period used to get the theoretical U
  • 26. • Difference between Theoretical and actual U was noticeable, so not very efficient is not optimum • Fouling rate figure during 2016 shows non stability, there are several reasons for this and they need to be checked • Some optimization techniques were suggested to improve the efficiency of these heat equipment. Also to decrease the load on some suboptimal equipment. 26
  • 27. • Objective: – Understand how pumps cavitates and malfunction – Evaluate efficiency, hydraulic power, total head, net positive suction head required and absolute – Suggest methods to improve the NPSHa 27
  • 29. First, we start by reconstructing the pump data sheet figures 29 Calculated Capacity (M3/hr) Total head (Meter) Hydraulic power BHP (Kw) Efficiency % 0 782.8 0.0 371.7 0.0 63.5 763.7 122.8 404.7 30.2 142 754.7 271.3 495.4 54.6 257.6 712.6 464.7 637.8 72.7 351 621.6 552.3 723.3 76.2 387.8 582.8 572.1 747.6 76.3 463.1 456.8 535.5 777.3 68.7 Capacity (M3/hr) NPSHr 65 3.1 145 3.3 260 4 350 5.5 380 6.4
  • 30. 30 456.8 777.3 68.7 y = -0.002x2 + 0.2547x + 769.21 R² = 0.991 y = -0.0006x2 + 1.2309x + 350.3 0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 90.0 0 100 200 300 400 500 600 700 800 900 0 50 100 150 200 250 300 350 400 450 500 Efficiency% TotalHead(Head),BHP(KW) Capacity (m3/hr) G-150-01C Pump Performance Curve Total head (Meter) BHP (Kw) Efficiency %
  • 31. 31 Pump is in area B2 150 – Boilers No access to P&ID’s was granted to me.
  • 32. PI Tag Numbers 98fic021 98fic041 98fic061 98fi703 - - Weekly data Flowrate Boiler 1 (tonne/h) Flowrate Boiler 2 (tonne/h) Flowrate Boiler 3 (tonne/h) Flow Users's (tonne/h) Total flowrate (tonne/h) Actual Capacity (m3/h) 17-Jan-16 133.02 128.65 121.68 207.82 591.18 318.87 24-Jan-16 138.08 131.19 128.32 213.68 611.27 329.70 31-Jan-16 143.02 137.78 134.46 219.24 634.50 342.23 7-Feb-16 127.22 131.79 108.99 191.70 559.69 301.88 14-Feb-16 136.66 135.02 124.04 184.55 580.28 312.99 21-Feb-16 139.96 138.53 129.44 243.90 651.82 351.58 28-Feb-16 135.55 131.49 124.96 250.65 642.64 346.62 6-Mar-16 134.99 139.26 133.71 218.92 626.87 338.12 13-Mar-16 137.90 141.33 125.51 239.84 644.58 347.67 20-Mar-16 139.68 134.87 125.08 251.15 650.78 351.01 27-Mar-16 143.46 137.69 128.65 242.33 652.13 351.74 32 *Using the same total head equation Shaft power (kW) (obtained from driver's calculations) 716 98pi003. 98PI008. Pressure in (brag) Pressure out (brag) Total Head hydraulic Power at current capacity Actual Efficiency % NPSHA NPSHr 2.52 67.28 647.57 562.33 78.59 24.85 5.31 2.54 65.03 624.86 561.05 78.41 25.20 5.51 2.92 63.90 609.80 568.34 79.43 31.33 5.76 2.63 62.73 601.07 494.15 69.06 26.52 5.00 2.52 68.37 658.45 561.24 78.44 24.85 5.20 2.56 64.70 621.36 594.93 83.15 25.44 5.96 2.45 65.20 627.54 592.38 82.79 23.59 5.85 2.56 66.26 637.01 586.56 81.98 25.38 5.68 2.60 65.36 627.61 594.23 83.05 26.10 5.87 2.48 64.92 624.34 596.82 83.41 24.17 5.95 2.40 64.81 624.12 597.84 83.56 22.82 5.96
  • 33. • NPSHa was noticed to be a critical aspect of a pump efficiency • NPSHr is usually uncontrollable, because it is designed by company that built it • Allowing higher level in the supply tank will reduce chance of pump cavitation • Frictional loss could be decreased by reducing valves, strains, and length of the piping 33
  • 35. • 2 Weeks of rich preparatory induction program (full day class) – Chemical Engineering for 1 week – Mechanical Engineering for 2 days – Electrical Engineering for 2 days – Control & Instrumentation for 1 day 35
  • 36. 36 • First meeting of engineer and managers
  • 37. 37 SL# Equipment Tag System Line Size Type Equipment Details Area Unit Flare Header P&ID Ref Pipe VENT FM 31-K-03B 31-K-03 2" VENT MAKE UP GAS TO CHD LINE B1 HRU CFP C0EF-031B1-009 1 66-PSV-004 66-D-13 3" PSV Hydrogen make up from CCR B1 MDU CFP C0EF-066B1-011 2 66-PSV-177 66-D-13 8" PSV Hydrogen back up from HRU B1 MDU CFP C0EF-066B1-011 3 66-PSV-015 66-M-01A 6" PSV FCC Gasoline Feed from USGP B1 MDU CFP C0EF-066B1-012 4 66-PSV-016 66-M-01B 6" PSV FCC Gasoline Feed from USGP B1 MDU CFP C0EF-066B1-012 5 66-PSV-021B 66-D-01 6" PSV Hydrogen make-up from 66-D-13 B1 MDU CFP C0EF-066B1-013 6 66-PSV-020/030 66-D-01 16" PSV Relief from 66-D-01 B1 MDU CFP C0EF-066B1-013 7 66-PSV-034 66-E-01 12" PSV Relief from 66-E-01 B1 MDU CFP C0EF-066B1-014 8 66-PSV-044 66-E-03 10" PSV Relief from 66-E-03 B1 MDU CFP C0EF-066B1-015 9 DEPR. FM 66-E-03 66-E-03 2" Drain From 66-E03 Depressurization line B1 MDU CFP C0EF-066B1-015 10 FM 66-D-02B 66-D-02B 10" Drain Draning line B1 MDU CFP C0EF-066B1-016
  • 38. 38
  • 39. • Objective: – Replace two rusty heat exchanger bundles – install new steam motive nozzles – Test the new heat exchanger bundles (Hydro test) 39
  • 40. 40
  • 41. Thank you for listening 41