Jones D.S.J., Pujado P.R. Handbook of Petroleum Processing
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ECONOMICS 755
the study therefore is for the development engineer to provide basic engineering for
a“Semi Definitive”capital cost estimate to be prepared. (Very often the refining
company may solicit third party Engineering Contractors to undertake this step.)
Should the project proceed from study stage to installation, this estimate may be
used as the first project budget estimate for project control. Details of this type
of estimate is given later in this chapter. Briefly for this estimate development
engineers (and/or third party engineering contractors) will:
r
Prepare process flow sheets (complete with mass balances).
r
Prepare preliminary mechanical flow sheets (complete with line and instrument
Sizes and specifications).
r
Initiate all equipment data sheets sufficient for obtaining manufacturers firm
prices.
r
Review and select manufacturers offers for equipment.
r
Using selected manufacturer’s equipment data, prepare a preliminary utility bal-
ance and size by factoring new or expanded utilities facilities.
r
Factor additional offsite facilities as required.
Step 8. Calculate cash flow for selected configurations.
The selected manufacturers equipment offer will also include a delivery time for
the equipment item. Using these and other experience factors prepare a preliminary
schedule for the installation of the facilities. This is executed by the experienced
schedule engineers of the Company or by accepted consultants.
Using this schedule the development engineer participates with others (Usually
members of the company’s project management department or finance depart-
ments) to split the budget down to annual payments over the construction period
as scheduled. The exercise continues to allocate pay-out of the capital costs on an
annual basis over a prescribed period after plant start-up. This is also discussed
later in this chapter.
Step 9. Calculate the return on investment based on a discounted cash flow basis.
The development engineer proceeds to develop the return on investment using the
cash flow developed in step 8 for the selected configurations. A technique using
the discounted cash flow principle is used for this purpose. This provides a more
accurate and more credible result than a ROI arrived at by the simple method
where no account is taken of the construction time and cash flow. Details of ROI
calculations are given later in this chapter.
Step 10. Prepare the study report and presentation to management.
Much of the report should be written as the study project proceeds. In this way
facts which are still fresh in ones mind are recorded accurately. The final report
must be concise but complete with all salient points. Techniques in report writing
is not included as a subject here. Sufficient to say that communicating the study
and its results effectively is as important as any technique and good engineering
“know how”used in the work. The same applies to the final oral presentation to
management. The study, the methodology, and finally, the results must be presented
in a manner that maintains interest and stimulates the decision making mechanism.
756 CHAPTER 17
This completes a typical study approach. It needs to be pointed out that should the
screening study reveal an option which far surpasses any of the others studied in terms
of pay-out this could be the only option that then needs the further study as described
in steps 7–10. Such a situation saves a considerable time and effort.
Building process configurations and the screening study
(See also Chapter 2 of this Handbook).
From item 1 above it can be seen that the first major event, that involves in depth
examination in a process study, is the screening of options. Here a very simple and
preliminary economic comparison of the options is carried out. This comparison is
viable because the basis for the economic criteria is the same for each of the options. It
must be borne in mind that a prerequisite for carrying out any of these process studies
is a good working knowledge of the processes involved. This example has been chosen
because the ultimate product slate is achieved through the addition of new processes,
changing operating conditions of existing units, and of course blending base stocks.
The example then is a requirement by a petroleum refinery to upgrade its fuel oil
product to more financially lucrative lighter products. This is a fairly common pro-
gram in this particular industry because of the fluctuating needs of the fuel market.
The example calculation given here to illustrate the study is the base configuration
published in an earlier book “Elements of Petroleum Processing” by the author. This
may be found at the end of the first chapter of that book, and the block flow sheet is
given here as Figure 17.1.4. The objective of this refinery configuration is to maximize
gasoline and middle distillate but still retaining sufficient of the atmospheric residue
from the crude distillation as fuel oil.
In the example given here it is intended to reduce the amount of fuel oil and to produce
as much gasoline and diesel as possible to give the best return on investment. For this
purpose six well proven processing routes have been selected for preliminary study.
These are as follows:
r
Thermally crack all of the atmospheric residue. This will be a single stage unit.
r
Vacuum distill all of the atmospheric residue. The waxy distillate will be cracked
in a fluid catalytic cracker producing gas, gasoline, naphtha, and light cycle oil as a
diesel blend component. The vacuum residue from the vacuum unit will be thermally
cracked to give additional gas, LPG, naphtha (for gasoline production), and gas oil
for diesel blending.
r
The same as option 2. except there will be no thermal cracker for the vacuum
residue.
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Vacuum distill all the atmospheric residue and hydrocrack the waxy distillate.
DE – C
2
2176 BPSD
Gasoline
Blending
Gas Oil
Blending
DE – C
3
3830 BPSD
DE – C
4
6320 BPSD
NAP
Splitter
16500 BPSD
Cat Peform
11000 BPSD
Diesel
HDS
7000 BPSD
NAP
HDS
16500 BPSD
LT Naphtha
3701 BPCD
4160
Desulf HY Diesel
CH9 Lighter
1584 BPCD
1671
BPCD
5972 BPCD
14803
BPCD
HY NAP
9431 BPCD
1791 BPCD
L
T
Diesel 10744 BPCD
HY Diesel 4894 BPCD
59689
BPCD
27457
BPCD
KERO
Kuwait
Crude
Residuum
GAS 1186 BPCD
C
3
LPG 664 BPCD
C
4
LPG 1405 BPCD
Reg Gasoline
Prem Gasoline
Automotive
N°6 Fuel Oil
29248 BPCD
Diesel
4770 BPCD
14904 BPCD
6778 BPCD
REFY Fuel
734 BPCD
Crude
Unit
66000
BPSD
Figure 17.1.4. The existing refinery.
758 CHAPTER 17
r
Process the atmospheric residue through a delayed coking unit.
r
Finally, use a proprietary fluid coking unit for the atmospheric residue that eliminates
the coke by converting it into low Btu gas.
The last two options are eliminated after a preliminary study because the is no eco-
nomically attractive outlet for the coke and no effective use for the low Btu gas in this
refinery.
The example calculation that follows provides the detail calculation for Scheme 1 and
provides the results of the same calculations for Schemes 2, 3, and 4. The configuration
for Scheme 1 is given in the block flow sheet Figure 17.1.5. Similar block flow sheets
would be prepared for the other study schemes but these are not shown here but a
flow description is given for these three schemes.
Example calculation
It is required to develop a processing scheme in which the gasoline and diesel products
are increased at the expense of the fuel oil product. The capacity of the present units,
the flow configuration and flow rates are given in Figure 17.1.4. The refinery fence
pricing of the products are historical and do not reflect recent escalation
$/bbl
LPG (C3 & C4) 20.2
Premium gasoline 35.2
Regular gasoline 27.6
Automotive diesel 28.6
No 6 Fuel oil 17.2
The cost of Kuwait Crude Oil is posted at 17.0 $/bbl delivered to refinery tankage.
Cost of utilities and labor is as follows:
Power (purchased) $0.042/Kwh.
Water $ 0.5/1,000 US gals
Steam $ 0.83/1,000 lbs
Fuel $ 0.01/lb.
Labor $15/hr salary + 40 burdens.
Three 8 hr shift plus one shift off. There will be 8 staff on each
Shift. Total man hours per month is 185.
The calculation
Scheme 1. Thermal cracking
The first step is to determine the yields and the quality of the products that can be
obtained by the thermal cracking of the atmospheric residuum. These are obtained
DE–C
2
4352 BPSD
Gasoline
Blending
Gas Oil Blending
DE–C
3
7660 BPSD
DE–C
4
S
10921 BPSD
Naphtha
Splitter
31843 BPSD
GAS 2208 BPCD
C
3
LPG 1237 BPCD
C
4
LPG 2616 BPCD
12607 BPCD
8872 BPCD
23454 BPCD
Reg Gasoline
Premium Gasoline
Automotive Diesel
REFY F.O 3604 BPCD
N° 6 Fuel Oil 9465 BPCD
3122 BPCD
BPCD
10036
BPCD
2754
14804 BPCD
Diesel
HDS
7000 BPSD
New Diesel
HDS
9000 BPSD
New Thermal
Cracker
34320 BPSD
Cat
Reform
20000 BPSD
Naphtha
HDS
31843 BPSD
59689
BPCD
1791 BPCD
10744 BPCD
Gas to 350 °F
Naphtha
12732 BPCD
HY Diesel 4894 BPCD
13069 BPCD
6658 BPCD
4160 BPCD
1193 BPCD
12535 BPCD
Desulf Diesel
Desulf HY Diesel
REFY
Fuel
REFY Fuel
734 BPCD
L
T
Naphtha
6914 BPCD
Reformate
14565 BPCD
CuS
4
Lighter
2939 BPCD
KERO
L
T
Diesel
7851
BPCD
Residuum
27457 BPCD
Kuwait
Crude
Crude
Unit
66000
BPSD
HY Naphtha
17504
BPCD
Figure 17.1.5. Scheme 1. Thermal cracker.
760 CHAPTER 17
by methods given in the authors publication “Elements of Petroleum Processing”
Chapter 17 and also in Chapter 1 of this Handbook. These are:
Stream wt% lbs/hr lbs/gal Gph BPCD
Gas to C5 9.02 35,079 4.67 7,506 4,289
Naphtha to 20.29 78,899 5.34 14,775 8,443
390
◦
F
Gas oil 24.66 95,878 6.89 13,916 7,952
390
◦
Fto622
◦
F
Residue +622
◦
F 46.03 179,013 7.73 22,870 13,069
Total 100.00 388,869 6.58 59,067 33,753
Note: There is a volumetric increase in the total products over the feed.
This is due to the changes in gravity of the products of cracking. The total
weight and moles will still be the same between feed and products.
Handling the products
Figure 17.1.5 shows the routing of the product streams from unit to unit. The gas from
the thermal cracker (Gas to C5) and the naphtha are routed to the existing naphtha
hydrotreater which will be expanded in size to accommodate this. The hydrotreated
material will subsequently go to the splitter and debutanizer, respectively. The existing
reformer and light ends unit will also be expanded to cater for the thermal cracker
light products. The gas oil from the thermal cracker will be hydrotreated in a new or
expanded hydrotreater to meet diesel pool requirements. Thus, new unit sizes will be:
Naphtha hydrotreater: Total new flow = 14,809 BPCD + 12,732 BPCD
= 27,541 BPCD
New size @ 86% service factor =
27,541
0.86
= 32,024 BPSD
which is an increase of 72% above the existing unit. This is too large to consider a
revamp therefore build a new unit 13,500 BPSD in parallel. The same applies to the
splitter.
Catalytic reformer
New feed to the reformer is 16,191 BPCD. At a 86% service factor the new size will
be:
17,504
0.86
= 20,353 BPSD.
Revamp the catalytic reformer by 9,000 BPSD.
ECONOMICS 761
Light ends
New total feed to the debutanizer is 9,283 BPCD. With a service factor of 90% this
gives a new capacity of 10,000 BPSD, an increase of 58%. This unit will be revamped
at a cost of 10% of a new unit.
The depropanizer and deethanizer will be expanded with parallel units the same size
as the existing ones.
The diesel hydrotreater
A new hydrotreater of 9,000 BPSD will be designed to cater for the additional gas
oil from the thermal cracker. The new total amount of gas oil to be treated is 4,894
BPCD + 7,851 BPCD = 12,745 BPCD. There is 706 BPCD spare capacity in the
existing hydrotreater through improved catalyst and service factor. Taking this into
consideration with a service factor of 80% then the additional capacity required will
be 9,000 BPSD.
Operating costs
The following tables (Tables 17.1.5 and 17.1.6) give approximate factors for utilities
and labor for some refinery plants. Note the use of these is acceptable for the screening
analysis given here. For detailed economic analysis of the selected configuration a
more accurate operating costs using certified vendor and licensor data must be used.
Looking at the configuration under study here, the operating cost for the extension of
the refinery is as follows:
Total cost of utilities per stream year using 0.86 ave service factor
= 28,227 $/day × .86 × 365 = 8.840 mm $/year
Labor salaries at 15 $/hr = 15 × 8 × 4 × 185 hr/month × 1.4.
Table 17.1.5. Utilities requirement per bbl of feed.
Steam l Water Power Fuel Labor
lbs gals Kw hr mmBtu Pers/Shift
Light end dist 25 12 0.4 – 1
Splitter 0 9 0.4 0.1 ”
Cat reformer 50 15 12 0.35 3
Nap HDS – 4 6 0.12 1
Diesel HDS 30 8 1.5 0.12 1
Thermal cracker 70 20 3 0.5 2
FCCU 20 20 7 – 4
Wash plants 1 2.5 0.4 – 1
VDU 15 20 0.2 0.07 3
762 CHAPTER 17
Table 17.1.6. $/Calendar day for utilities (Exc Labor)
Unit Steam Water Power Fuel Labor Pers/shift
Nap HDS (13,500 BPSD) – 27 3,400 900 1
Nap splitter (1,350 BPSD) – 60 227 750 1
Lt Ends (3,000 BPSD) 60 18 50 –
Ther cracker (34,320 BPSD) 1,922 343 4,324 9,500 2
Diesel HDS (9,000 BPSD) 216 36 567 600 1
Cat reformer (9,000 BPSD) 360 68 4,536 263 3
Total 2,558 552 13,104 12,013 8
Notes on labor:
1. The salaries are increased by 40% to take up government benefits, paid days off,
vacation etc.
2. There are four shifts three on duty and one off every 24 hr.
3. Hours worked per person per month is 185 hr.
Then total labor cost per year = 124,320 $/month × 12
= 1.491 mm $/year.
Total operating cost per year = 10.331 mm $.
Investment costs for the new facilities
There are two costs which make up the overall investment outlay. These are:
r
Capital cost of the plant
r
Associated costs
The capital cost
For the screening study a capital cost of plant estimated on experience and factors
are used. This and other types of estimates are described later in this chapter. A set
of capacity cost data for plants of this size are listed below:- Note that these numbers
are pure fiction and bear no relationship to any company’s cost data.
Type of unit Capital cost factor
Light end units 412 $/BPD
Catalytic reformer 3,120 $/BPD
Hydrotreater (naphtha) 780 $/BPD
Hydrotreater (Diesel) 1,200 $/BPD
Wash plants 170 $/BPD
Naphtha splitters 360 $/BPD
ECONOMICS 763
Thermal crackers 2,000 $/BPD
Fluid catalytic crackers 3,960 $/BPD
Vacuum distillation units 700 $/BPD
Associated costs
To complete the full investment picture the following costs must be included as part
of the investment. These are:
r
Cost of first catalyst and chemical inventory.
r
Cost of licensing fees for proprietary processes.
r
Cost of additional utility and offsite facilities. This cost is included because addi-
tional processing plants will either require additions to utilities & offsite facilities
or take up available spare capacity. This will result at some future date an expansion
to these facilities which would not be necessary if this process expansion had not
occurred.
For the purpose of a screening study a figure of 15% of the capital cost is used for
these associated costs. In more definitive studies this item would be developed with
more detail.
The capital cost of the process expansion considered here is as follows:
New naphtha hydrotreater
Capacity 13,500 BPSD @ 780 $/bpsd = 10,530,000 $
New naphtha splitter
Capacity 13,500 BPSD @ 360 $/bpsd = 4,860,000 $
Revamp debut and new light ends
Debutanizer revamp = 10% of new plant =
2,963 × 412
10
= 122,000 $
New light ends unit = (3,830 bpsd × 412) +(2,176 × 412)
= 2,474,472 $
Total = 2,596,500 $
New thermal cracker
At a service factor of 80% the capacity of the unit is
27,457 BPCD
0.8
= 34,320 bpsd
Capital cost = 34,320 × 2,000 $
= 68,600,000 $.
764 CHAPTER 17
New diesel hydrotreater
9,000 bpsd × 1,200 $ = 10,800,000 $.
Revamped catalytic reformer
9,000 bpsd × 3,120 $ = 28,100,000 $.
Total capital cost = 125.490 mm $.
Associated costs
This is taken as 15% of capital cost = 18.823 mm $.
Total cost = 144.313 mm $.
The product slate
The new refinery product slate is summarized below (all in BPCD):
Product Existing Expanded Difference
C3 LPG 664 1,237 + 573
C4 LPG 1,405 2,616 + 1,211
Reg gasoline 6,778 12,607 + 5,829
Prem gasoline 4,770 8,872 + 4,102
Auto diesel 15,638 23,454 + 7,816
Fuel oil 26,323 9,465 − 16,858
Refy fuel gas 1,186 4,135 + 2,949
Refy fuel oil 2,925 3,604 + 679
**
TOTAL 59,689 65,990 + 6,301
*Note difference in BPCD between input and output is due to
changes in SG’s due to cracking. Mass (lbs/hr) In still equals
mass Out.
Gross income from increase in product slate
Product Increase BPCD $/bbl $/day
LPGs 1,784 20.2 36,037
Reg gasoline 5,829 27.6 160,880
Prem gasoline 4,102 35.2 144,390
Auto diesel 7,816 28.6 223,538
Fuel oil −16,858 17.2 −289,906
Refy fuel −3,628 17.1 −62,039
Gross income 212,900 $/CD