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No. 1998.222

Upgrading and Refining of Heavy Oil in Iraq

Amira M. Juwad and Suham A. Kamal, Ministry of Oil, Baghdad, Iraq


Iraq is considered among the leading countries with large reserves of heavy crude oils. Qaiyarah's heavy crude oils with API gravities (11­17) and high sulfur content (6­7.5) wt.% are contained in five oil fields in northern Iraq. These reserves constitute about 3% of the total oil reserves of Iraq. Production from Qaiyarah oil fields is planned to increase to 100,000 B/D in the future. This paper reports on a feasibility study that includes four schemes for the upgrading of Qaiyarah heavy crude at a capacity of 100,000 B/D. Selection of the optimum scheme for utilization of these crudes is made on theoretical basis, and pilot plant tests for the selected scheme should be undertaken later to confirm the theoretical results reported. These schemes include either carbon rejection or hydrogen addition for primary upgrading with required secondary refining/upgrading, and are defined as follows: Scheme 1 and Scheme 2 are for the upgrading of the crude for production of petroleum products for local consumption. Scheme 3 and Scheme 4 involve upgrading for production of synthetic crudes for export. 2. Production of Petroleum Products and Synthetic Crudes. The quantities of the petroleum products produced from scheme 1 and scheme 2, and synthetic crudes produced from scheme 3 and scheme 4 are as listed below: (1000 Tons / Year) Products Scheme 1 Scheme 2 LPG 200.0 130.0 Gasoline 940.0 760.0 Kerosene 500.0 L.G.O. 2320.0 2050.0 Fuel oil 700.0 Pet. coke 1330.0 Synthetic crudes Scheme 3 Scheme 4 production 4806 4396 Yield on crude, vol % 102.6 96.5 API gravity 27.5 35 Sulfur, wt % 1.0 0.8 3. Capital Cost. The total capital cost for each of the four schemes, including the capital cost of the process units, utilities and off-site facilities are estimated and as listed bellow Scheme Capital Cost (Million Dollars) Scheme 1200 Scheme 2 1600 Scheme 3 900 Scheme 4 1150 4. Economic Analysis Results. The results of the economic analysis for the four schemes as shown bellow:

Capital cost, $ / B Production cost, MM$/Y Operating cost,$ / B Revenue, MM $/Y Net cash flow, MM $ Net present value, MM $ Pay back period, year Break even point,% IRR, % Scheme 1 Scheme 2 Scheme 3 Scheme 4 14815 16755 8770 11920 553.7 674.5 555.0 600.3 5.0 9.2 5.1 6.3 647.1 20.8 630.5 630.4 1734.4 1242.1 1421.9 841 109.8 305. 73.8 238.1 6 8 6 8 60 80.9 59.6 82.6 13.2 7.6 12.8 7.3

Technical and Economical Evaluation 1. Capacities of the Process Units. The process units and their capacities utilized in the above mentioned schemes, for primary and secondary upgrading are as listed: (BPSD)

Unit Scheme 1 Atm. Distillation 100 000 Vac.Dist. Naph. HDS 35 000 Isomerization (TIP) 7 500 Reforming (CCR) 20 500 L.G.O. HDS 52 000 Delayed coking 60 600 Atm.Res.Desulfur. V.G.O Hydrocrack. H.Oil Hydrocrack. LPG Production (T/D) 600 Amine +Sulfur Recovery 370 (T / D) Hydrogen Production 10 000 (M3 / hr) Scheme 2 100 000 50 000 22 000 6 500 16 000 35 000 230 300 26 500 387 800 140 000 Scheme 3 Scheme 4 100 000 100 000 230 300 230300 760 760 120 000 150 000

Conclusions and Recommendations The above economic analysis results indicate that scheme 1 and scheme 3 have economic advantages over schemes 2 and 4. In order to determine the most optimum scheme pilot plant tests should be carried out employing the Atm. Res. Desul. process to confirm the yields and product specifications. This is especially necessary because of the high sulfur content of Qaiyarah heavy crude (7.3 wt.%), since the operating units of this kind have not been designed for or tested with this kind of heavy crude oils having such a high sulfur content.


It is a standard practice in the U.S. to define heavy crudes as those with gravities of less than 20°API in conventional oil reservoirs. Unitar / UNDP define heavy oil as that having a viscosity of 10,000 CP or less at reservoir temperature and bitumen with a viscosity of 10,000 CP or more. Heavy oil has therefore 10­20°API gravity while extra heavy less than 10°API gravity. The heavy crudes can be compared to average crudes as having: * Higher viscosity. * Higher sulfur, metal and asphaltene content. * Higher average boiling point. * Low H/C processes. Development of heavy oil and bitumen reserves is accelerating around the world, and the Opec countries have the intention of increasing the fraction of heavy crudes in their oil exports. Light crudes represent 49% of their known reserves, but these crudes represent approximately 62% of the oil produced by these countries. When these additional heavy crudes are added to the increasing production of very heavy crudes in north and south America, the result is an over-supply of residual oil. The difficulties to process these kinds of crudes, are related to the facts that the existing refineries are not well equipped to process heavy crudes with high sulfur content, and to the environmental restrictions for the sulfur emissions in most areas.

heavy crude oil processing philosophy is to upgrade this crude to a synthetic crude oil that can supplement or replace conventional crude oil in a refinery. This provides a large potential market penetration for upgraded heavy crude oil products. A number of alternate technology have been considered and employed for primary upgrading of heavy oil and bitumen. They can be grouped into two well known categories of Carbon Rejection and Hydrogen Addition processes. Both of these processing routes are employed at syn crude. Delayed Coking uses Carbon Rejection and H. Oil Hydrocracking and Atmospheric Reside Desulfurization is an example of Hydroprocessing. In recent years, economic and social pressures have made the advantages of the hydroconversion process more significant. As society increases the priority given to environmental protection, atmospheric emissions and sulfur dioxide and particulates from coker operation become less torelable. These emission can be reduced, but additional high cost equipment is required to treat the flue gases. The molecular structure of coker products present significant product quality drawbacks to down stream refiners. In particular, the aromatic content of light and heavy gas oil limits refiners ability to process synthetic crude. Final refined product specifications are becoming more stringent due to environmental pressures. To meet final specifications coker products must be subjected to more intensive hydrotreating employed as secondary upgrading. However for the Hydroprocessing upgrading there is no need for the secondary upgrading.

Criteria for Selection of Upgrading Processes · Upgrading processes must be commercially proven. · Product slate, quantity and quality must be equivalent to that produced from sweet crudes. · There must be no adverse environmental impact.

Processing Objective and Technology

It seems that in the long run, every major refiner will have to be capable of refining heavy crudes. With as much as 80% of the world's oil reserves considered heavy, lighter oil must ultimately become both scarcer and costlier. Heavy crudes will not become a major component of the national energy supply picture unless they are upgraded, so that they can be utilized as transportation fuels. The current

Hydroprocessing Upgrading The most favorable processes used for upgrading heavy crude and bitumen by using Hydroprocessing technology are Atmospheric Residue Desulfurization and H. Oil hydrocracking, both of them are commercially proven with atrack record of successful operation and flexibility.

Atmospheric Residue Desulfurization Process, ARDS The ARDS unit is the primary residue upgrading process for the Atmospheric Residue. It employs fixed bed of catalyst and operates at moderately high pressure It is used to desulfurize and denitrify, demetallize and reduce the coke- producing components in the atmospheric residue in order to produce

good quality feed stocks for converting units like FCC or hydrocracker. Some liquid conversion of the residual component to middle distillates and gasoline is also achieved in the ARDS process. The excellent treatment capabilities of the process are being recognized for upgrading heavy oil to produce synthetic crude.

Scheme 1: Delayed coking for atmospheric residue with a separate hydrotreating and utilize the coke produced in a power station equipped with flue gas desulfurization. Scheme 2: Desulfurization of atmospheric residue with conventional V. G. O hydrocracking.

H-Oil Process This process used for all types of difficult feedstocks to distillable light products and synthetic crudes, desulfurization and demetallization of the residual either for LOW sulfur feed to FCC or coking or for sale as low fuel oil It is an ebullated bed catalytic hydrogen addition and cracking process, it can work at two type of residue conversion at 60% and 90%

Case Two Upgrading of 100,000 B / D of Qaiyarah heavy crudes for production of synthetic crudes for export. includes two schemes also: Scheme 3: Production of synthetic crude by Atmospheric residue desulfurization. Scheme 4: Production of synthetic crude by high conversion H- oil hydrocracking (90%) with gasification of the residual for producing hydrogen. The above-mentioned schemes are illustrated schematically in Figures 1­4.

Iraqi Heavy Crude Oils Iraq is considered among the leading countries with large reserves of heavy crude oils Heavy oil reserves of (API bellow 20) are 13.3 billion barrels and oil in place are 66.9 billion barrels. These heavy crude oils reserves constitutes 12% of the total Iraqi oil reserves of the Iraqi country. About 25% of these heavy crudes are Qaiyarah site crudes located in the north of Iraq. They are the heaviest crudes in Iraq with an API gravities of (11­17), with high sulfur content (6­7.5) wt%. They include five fields namely, Qaiyarah, Qasab, Jawan, Najma and Maqmour fields. The reserves and oil in place with API and sulfur content of these fields as in Table 1. In present situation there is no production of heavy oil crudes except from the Qaiyarah field with a capacity of 20,000 B/D for production of asphalt. Production from Qaiyarah oil fields will be increased to 100,000 B/D in the envisage plan. There is a need to develop a process configuration to be used as optimum utilization of Qaiyarah heavy oils. This paper discuss the feasibility study executed by the relevant experts in the ministry of oil of Iraq, including many cases and schemes. The object is to select the most overall favorable scheme based on capital costs, operating cost, yield, net cash flow to utilize Qaiyarah heavy oils.

Qaiyarah Oil Upgrading Study Considerations

Characteristics of Qaiyarah Heavy Oils Qaiyarah heavy oils evaluated in this paper are characterized by high viscosity (659 centistockes at 20°C.), high sulfur content (7.3 wt%), high nitrogen content (0.23 wt%), high metals content (155 ppm Ni + V) and low API gravity of 16.4. The typical Qaiyarah crude assay used for this study is given in Table 2. The high viscosity necessitates some form of viscosity reduction for pipeline transmission. The high sulfur and nitrogen levels indicate that hydrotreating will be necessary at some point in the process along with hydrogen production and sulfur recovery plants. The high level of heavy metals will need to be substantially removed before catalytic processing to avoid uneconomic levels of catalyst make up.

Study Scope

The study includes two cases: Case One Upgrading of 100,000 B / D of Qaiyarah heavy crude for production of petroleum products for local consumption. This case includes two schemes:

Application of Conversion Technology The upgrading technologies taken into consideration in this study are delayed coking as Carbon Rejection processes, HOil Hydrocracking and Atmospheric reside desulfurization as Hydrogen Addition processes. The process noted above are referred to as primary upgrading. The liquid products from the selected primary upgrading processes and from the atmospheric distillation unit for scheme 1 and scheme 2 are hydrotreated in naphtha and distillate hydrotreaters to convert organic sulfur and nitrogen to hydrogen sulfide and ammonia and to saturate the reactive olefin and diolefin exposed by primary conversion. Associated with these hydrotreaters H2S and Sulfur recovery units to remove sulfur from the fuel gas produced and Hydrogen plant for feeding these units. Also light and heavy Naphtha are fed to isomerization and reform-

ing units for production of gasoline. For scheme 3 and scheme 4, the synthetic crudes produced by blending virgin naphtha and middle distillates with the products from the Atm. Rest. Deslfur. or H. oil hydroc.

Hydrogen Plants The hydrogen required for the processing schemes outlined in the mentioned study is assumed to be manufactured in on-site process units. The hydrogen plants required for scheme 1 and scheme 3 are based on steam reforming of imported natural gas. The hydrogen plants required for scheme 2 based on partial oxidation of the vacuum residue and for scheme 4 based on gasification by TEXAC-HYTEX process.

Maximizing Liquid Yields In scheme 1 the delayed coker based on minimizing coke production. In scheme 2 and scheme 3, the atmospheric desulfurization based on 70 vol % conversion, and in scheme 4, H-Oil hydrocracking based on 90 vol % conversion to maximize distillates ranging from 200­530°C+, and to minimize the residue at 530°C+.

Sulfur Plants All of the processing schemes have H2S removal systems and sulfur plants of gas treating in order to achieve 99% sulfur removal of feed stream. The sulfur is converted to solid type and deposited as storage piles with no dust creation. The case involving the burning of high sulfur coke in a power station (scheme 1) requires flue gas desulfurization in order to meet expected emissions standards. The capital cost of this type of treatment is included in the total capital cost of this scheme.

Quantities and Products Specifications The petroleum products produced from scheme 1 and scheme 2 for local consumption are to be according to with an international specifications. In scheme 3 and scheme 4, the synthetic crude produced have API gravity 27.5 and 35 respectively. In addition a low sulfur content of about 1 and 0.8 wt% with acceptable nitrogen content and minimal metals content. Tables 4­5 summarize the quantity and specifications of the petroleum products produced by scheme 1 and scheme 2. Table 6 summarize the quantity and specifications of the synthetic crudes with their components produced from scheme 3 and scheme 4.

Utilities Each scheme is considered to be self-sufficient in all utilities except for the electrical power requirement and the importation natural gas for producing hydrogen. Refinery fuel requirements were met by the burning of light gas streams and some of the LPG produced.

Evaluation of the Schemes

Capacity of the Process Units The capacity of the process units for each scheme are calculated including the atmospheric unit, primary upgrading, desulfurization of Naphtha and gas oil, Amine sweetening and Sulfur recovery plant, Hydrogen production unit, also for scheme 1 and scheme 2, Isomerization, Reforming, and LPG production units are also involved. Table 3 illustrates the capacities of the process units for the four schemes.

Capital Costs The total capital costs for each of the four schemes are estimated and expressed in 1996 prices including process units capital costs, costs of basic design and licensors, capital costs of utilities and off site facilities, no contingency of forward escalation has been included. These estimates are summarized in Table 7. The total capital costs for the four schemes are: $1200 million for scheme 1 $1600 million for scheme 2 $900 million for scheme 3 $1150 million for scheme 4 The capital costs for the above schemes as $ / BPSD produced as listed bellow: $/ BPSD Scheme 1 Scheme 2 Scheme 3 Scheme 4 14815 16755 8770 11920

Economic Analysis

The economic assumptions used in the calculation were as follows: · Discount rate of return 10%. · No inflation adjustments. · 4 years construction period. · 15 years operating life. · Rate of interest 6%. · Operating Capacity of the project as follows: · First year (after completion of construction) at 75%. · Second year at 90%. · Third year at 100%.

F.O. 95 Coke 20 The by-product sulfur from each of the four schemes is not considered as saleable product due to the high world wide surplus of this product.

Estimated Price of Qaiyarah Heavy Oil Estimated price of Qaiyarah heavy crude is 11.5 $/ B calculated by correlation equations based on average prices of year 1997 for Arabian heavy 17.17 $/B and prices of Arabian heavy and Bachaquete / Venezuela heavy crude at years 1990 and 1992, and as shown below: Price $ / B Heavy crude API 1990 1992 1997 Arabian heavy 28 18.8 15 17.17 Bachaquete 17 15.8 9.71 -

Synthetic Crude Oil Produced from Scheme 3 and Scheme 4 17 $ / B for synthetic crude with API 27.5 produced from scheme 3. depending on 1997 price of orient crude / Forcados with API 22.2 and sulfur content 1% · 18.24 $/B for synthetic crude with API 35 produced from scheme 4 depending on 1997 price of lranian light crude with API 33.6 and sulfur 1.35% The revenue estimates are summarized in Table 9. Scheme 2 yields the highest annual revenue $720.8 million, Scheme 1 has an annual revenue of $647.1 million. Scheme 3 has $630.5 million and scheme 4 has $630.4 million.

Operating Costs Estimates Operating costs are calculated for each of the four schemes. These estimates are summarized in Table 8. Taken into consideration that the natural gas imported in the variable costs for scheme 1 and scheme 3 has been utilized for hydrogen production only, and the fuel gas with the propane produced from each of the four schemes are utilized as internal fuel consumption. Delayed coking (scheme 1) has the lowest annual operating cost $175 million. The annual operating cost for scheme 2, 3, and 4 are $295.8, $176.3 and $221.3 million respectively.

Economic Analysis Results The results of the economic analysis have been summarized in Table 10. The results have indicated that scheme 1 delayed coking for local consumption with utilizing the coke produced in a power station as fuel which equipped with flue gas desulfurization facilities and scheme 3 producing synthetic crude by Atmosph. Residue Desulfur have economic advantage over the other two schemes the parameters of these schemes are as shown bellow: Scheme 1 Scheme 2 IRR 13.2% 12.8% Net cash flow $1734 million $1491 million Net present value $109.8 million $73.8 million Pay back period 6 years 6 years Breakeven point 60% 59.6%

Revenue Estimates Revenue estimates are calculated and expressed in 1997 Dollar for each of the four schemes. The following are the major revenue components priced at the battery limits: Petroleum products prices for scheme1 and scheme2 as listed below: Product Price(Dollar/Ton) LPG Gasoline ATK L.G.O 160 195 180 170

Conclusions and Recommendations

The most economic schemes are scheme 1 and scheme 3, and the lowest capital cost is scheme 3. Pilot plant tests should be carried out employing the Atm. Res. Desul. process to confirm the yield, and product specifications. This is especially necessary because of the high sulfur content of Qaiyarah heavy crude (7.3 wt%), and as operating units of this kind have not been designed for or tested with this kind of heavy crude oils having such a high sulfur content.


1. H. Oil Process Gives Product Flexibility, L.M. Rapp and R.P. Van Driesen, Hydrocarbon Processing, December, 1965. Design Techniques for Modern Delayed Coker Illustrated S.B. Heck, Oil and Journal, July 24, 1972. Delayed Coking -- What You Should Know, K.E. Rose, Hydrocarbon Processing, July 1971. Delayed Coking, Hydrocarbon Processing, September 1984. HC Unibon, Hydrocarbo Processing, September 1984. H. Oil, Hydrocarbo Processing, September 1984. International Symposium on Heavy Oil and Residue Upgrading and Utilization. Upgrading of Heavy Distillates and Residual Stocks, Institut Francais du Petrole. (IFP). Optimize Design for Heavy Crude, H.R. Stewert, A.H, Koenig and T.A. Ring Bechtel Petroleum, Inc. San Francisco, Calif. Hydrocarbon Processing, March 1985. 10. Industry Steps Up Development of Heavy Oil, Bitumen Reserves. Marcia A. Parker, New York Editor and Bob Williams, West Coast Editor. Oil and Gas Journal, Jan. 6, 1986 11. Canada's Heavy Oil, Bitumen Upgrading Activity is Growing, Richard A. Corbett, Refining / Petrochemical Editor, Oil and Gas Journal, June 26, 1989 12. How to Upgrade Heavy Feeds, B. Schuetze, Esso AG Refinery Karlsruhe, West Germany, and H. Hofmann. Hydrocarbon Processing, February 1984 13. Advanced Recycle Isomerization Gives Highest Value for C5/C6 Streams / IFP. 14. Catalytic Reforming, Three Decades of Development 1990s Ultra-Low Pressure Continuous Catalyst Regeneration. / IFP 15. Setting the pace with IFP for the 21th Century, IFP.

2. 3. 4. 5. 6. 7. 8. 9.


OIL RESERVES MM BARRELS 813 347 1007 858 189 3214 API 16 17 17 17 12.7

SULFUR Wt. % 7.3 6.7 6 7.6 6

Table 1: Iraqi Heavy Oil With an Api (11­17) -- Reserves And Oil In Place

CRUDE OIL TBP Range C. TBP Yield % Wt. TBP Yield % Vol. API Gravity Density KG /L Sulfur Wt.% Nitrogen Smoke Point MM C Insol Wt.% Freezing Point C. CetaneIndex CCR Wt.% Vanadium Nickel Visc. at 20 C. CST. Visc, at 40 C. CST. Visc, at 100 C. CST. Pour Point C. Acidity MG KOH/G

GAS C1-C4 0.9 1.5

NAPHTHA C5 - 80 3.2 4.5 0.68 0.22 80-180 8.4 10.2 0.74 0.33

KEROSENE 180-250 6.9 8.1 0.814 1.0 22

GAS OIL 250-350 13.8 15.1 0.874 3.0 0.017

VGO 350-530 21.8 21.6

RESIDUE 350+ 66.8 60.6 1.054 7.5 0.25 20.16 530+ 45 39 1.11 9.8 0.38 0.3

16.4 0.954 7.3 0.23 13.8

5.5 0.11

-62 48 14.4 115 40 659 193 20 -27 0.7 21.5 172 60 33.27 290 119

950 50


Table 2: Qaiyarah Heavy Crude Assay


Atomspheric Unit Vacuum Unit Naphtha L.G.O. Desulfurization Desulfurization

SCHEME 1 Delayed Coking

100 000 35 000 52 000 7 500 20 500 60 600

SCHEME 2 Atm. Resid.Desul. +VGO Hydrocr.

100 000 50 000 22 000 35 000 6 500 16 000

SCHEME 3 Atm. Resid. Desul.

100 000

SCHEME 4 H-Oil Hydroc. + Gasific.

100 000

Isomerization Unit (TIP) Reformer Unit (CCR) Delayed coking H-Oil Hydrocracking V.G.O. Hydrocracking Atm.Res. Desulfur. Hydrogen Production Unit (Cu.M/Hr) L.P.G. Production Unit (T/D) Gas sweetining & Sulfur Recovery Unit (T/D)

2 x 30 300 26 500 2 x 30 300 10 000 600 370 140 000 387 800 760 760 2 x 30 300 120 000 150 000

Table 3: Capacities of the Process Units -- BPSD



SCHEME 1 Delayed Coking 1000 T/ Y BPSD

200.0 940.0 2320.0 1330.0 7000 24000 50000 -

SCHEME 2 Atm. Res. Desul.+VGO Hydroc. 1000 T/ Y BPSD

130.0 760.0 500.0 2050.0 700.0 4000 19300 11000 47000 14200 -

Table 4: Finished Petroleum Products for Local Consumption





95 85 0.767 0.800 27 10 0.844 400 50 0.978 1.3 40 SPONGE 10



Table 5: Specification Of Finished Products Produced from Sch1 & Sch.2 for Local Consumption





1000 T/ Y


60 33 18 -3 27.5 58 33 25 35


0.1 1.5 0.5 1.6 1 0.1 1.3 1.5 0.8


2.0 17 33.4 25.8 21.8 100 1 31.5 41.5 26.0 100





2000 60.0 17500 690.0 34300 1556.0 26470 1300.0 22330 1200.0 102600 4806 102.6 vol % 95.8 wt% on crude on crude 1000 29 30400 1185 40000 1910 25100 1272 4396 96500 96.5 vol% 87.7 wt% of crude of crude

Hydrocracked Virgin + Hydrocracked Virgin + Hydrocracked Hydrocracked -

Table 6: Synthetic Crude Production for Export

1-Capital cost of process units

Atm. Dist. Vacuum Unit Naphtha Desulfurization L.G.O. Desulfurization Isomerization Unit (TIP) ReformerUnit(CCR) Delayed coking H-Oil Hydrocracking V.G.O. Hydrocracking Atm.Res. Desulfur. Hydrogen Production Unit L.P.G. Production Unit (T/D) (Cu.M/Hr) 20 35 Gas sweetining & Sulfur Recovery Unit (T/D) Sub-Total(1) 15 50 860 740 1600 1600 60 510 390 900 900 70 650 500 1150 1150 60 30 60 15 40 185 60 40 20 40 10 35 60 60

300 120 260 15 210 260 130 220

2-Capital cost of site & utility units


3-Capital cost of flue gas desulfur

Grand Total

460 340 800 400 1200

Table 7: Capital Cost (Million $)

SCHEME (1) 1- VARIABLE COST Natural gas Fuel gas Electric power Catalyst & chemicals Fuel oil SUB-TOTAL (1) 2- FIXED COST Labour Maintenance General administrat Insurance Miscellanous Interest Depreciation SUB-TOTAL (2) GRAND TOTAL 3.6 18.0 0.9 6.0 6.0 26.9 80.0 141.4 175.0 2.1 10.8 10.7 10.0 33.6

(MM $) SCHEME (2) 9.3 30.5 23.0 37.5 100.3 6.3 24.0 1.5 8.0 8.0 41.1 106.6 195.5 295.8

SCHEME (3) 23.7 9.6 13.8 18.0 65.1 4.5 13.5 1.1 4.5 4.5 23.1 60.0 111.2 176.3

SCHEME (4) 9.0 15.8 30.0 26.2 81.0 4.5 17.2 1.1 5.7 5.7 29.5 76.6 140.3 221.3

Table 8: Annual Revenue Estimate -- (Mm $)



LPG Gasoline Kerosene / ATK L.G.O. Fuel oil Coke Synthetic crude oil Refinery fuel gas Residue for production of hydrogen TOTAL

32.0 183.3 394.4 26.6 10.8 647.1

20.8 148.2 90.0 348.5 66.5 9.3 37.5 720.8

620.9 9.6 630.5

594.8 9.0 26.6 630.4

Table 9: Annual Operating Cost Estimate-- (Mm $)

ITEMS Total capital cost MM $ Total capital cost with interest 6% during construction MM $ Total production cost MM$ / Y Total operation cost MM $/Y Annual revenue MM $ Total revenue through the life of the project MM $ Net cash flow MM $ Discount cash flow with discount rate 10% (NPV) MM $ IRR % Return back period (Year) Break even point % Production cost $/T $/B Operation cost $/T $/B

SCHEME (1) SCHEME (2) SCHEME (3) SCHEME (4) 1200.0 1342.0 553.7 175.0 647.1 9480.0 1734.4 109.8 13.2 6 60.0 111.4 15.7 35.9 5.0 1600.0 1854.8 674.5 295.8 720.8 10559.7 1242.1 305.5 7.6 8 80.9 140.6 16.8 65.1 9.2 900.0 1043.3 555.0 176,3 630.5 9236.7 1421.9 73.8 12.8 6 59.6 111.7 15.7 36.2 5.1 1150.0 1333.1 600.3 221.3 630.4 9229.5 841.0 238.1 7.3 8 82.6 122.6 16.5 47.1 6.3

Table 10: Economic Analysis Results









350+ 60600 B/ D

H2 N . GAS H2



Figure 1: Delayed Coking Flow Diagram of Scheme 1

Figure 2: Atm. Res. Desul + V.G.O. Hydrocr. Flow Diagram of Scheme 2

Figure 3: Atm. Res. Desul. Flow Diagram of Scheme 3

Figure 4: H-Oil Hydrocracking Flow Diagram of Scheme 4


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