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Refinery configurations: Designs for heavy oil

10.01.2011  |  Garg, M. O.,  Indian Institute of Petroleum, Council of Scientific and Industrial Research, Dehradun, IndiaKumar, S.,  Indian Institute of Petroleum, Dehradun, IndiaNanoti, S. M.,  Indian Institute of Petroleum, Dehradun, IndiaSharma, Y. K.,  Indian Institute of Petroleum, Dehradun, India

Conceptualization and economic models looked at scenarios to process clean gasoline, diesel from domestic feedstock

Keywords: [refining] [gasoline] [diesel] [heavy crude oil] [propylene] [hydrocracker] [deasphalting] [hydrogen]

A challenge for existing refineries is how to process heavy crudes and handle the technical constraints associated with such feedstocks. A new heavy crude was discovered at the Mangala field in the Thar Desert of Rajasthan, India, in January 2004. The crude resources went into production in late August 2008. The Indian Institute of Petroleum (IIP) conducted a detailed analysis of this crude for product yields and characteristics. Lower distillate yield (23 wt%) and difficulties associated with its transportation through pipeline due to a higher pore point (39+ °C) clearly indicate that neat processing of the new crude by existing refineries may not be feasible.

One solution was to design a grassroots refinery designed specifically for this challenging heavy crude oil located near the Mangala field. Eight grassroots refinery configurations capable of processing the Mangala crude were conceptualized and evaluated economically with regard to finish products meeting Euro IV specifications. Results from the study indicated that individual product and combined distillate yield (gasoline + kerosine + diesel) are configuration dependent, and they are governed by the combination of secondary conversion processes as part of the processing scheme included in the configuration.

Need for more oil.

Reduced availability of lighter conventional crudes and growing global demand for energy drive efforts to find and produce new crude resources. India is actively seeking new offshore and onshore crude sources. Likewise, heavy crude oil reserves are increasing in availability. For example, the heavy crude reserves at the Mangala field in the Thar Desert of Rajasthan, India are estimated at 3.6 billion barrels (570 billion m3) oil of which 1 billion barrels (160 billion m3) are recoverable. Cairn India is the current operator of the field, a subsidiary of Cairn Energy. At present, 125,000 bpd (125 Mbpd) of crude oil is pumped out from wells in Rajasthan by Cairn India, and plans are in effect to to produce 150 Mbpd in the near term.1,2

Reliance Industries, Essar Oil and Indian Oil Corp. Ltd. (IOCL) and Mangalore Refinery have shown interest in processing a blending stock to conventional crude. With an increasing production rate, lower distillate yield (23 wt%) and difficulties associated pipeline transport issues associated with the Mangala crude, existing refineries are not designed to handle this very heavy crude oil. A grassroots refinery located near the Mangala field is the best option.

Mangala crude characterization.

Detailed analysis of Mangala crude was carried out at IIP. Table 1 lists the major characteristics of the crude oil. With a specific gravity value of 0.881 (API: 29.1), the Mangala crude is neither heavy nor light. However, its distillate (from IBP–370°C) and naphtha (from IBP–140°C) fraction yield values of approximately 23 and 1.1 wt % of crude are significantly lower in comparison to corresponding values of approximately 50 and 12 wt% for conventional crude. This crude oil can be considered part of the heavier crude category. Watson characterization factor value of 12.47 clearly indicates that it is paraffinic in nature. Also, the higher pore-point value of 39+°C poses the challenges in transpiration via pipelines.


Refinery configurations.

Present day data indicate that there is a continuous shift to middle and light distillates at the expense of heavy ends and to ever increasing higher quality standards.

In view of constraints associated with Mangala crude and its present exploration rate, eight refinery configurations for a 5 million metric tpy (5 metric MMtpy or 100,000 bpd (100 Mbpd)) crude processing capacity were conceptualized and analyzed. Table 2 summarizes possible processes and configurations. In each configuration, diesel and gasoline pool streams from different processes units are blended to produce Euro IV diesel and gasoline.


These configurations were developed using technologies and processes that are already commercially proven and well established in refineries. Figs. 1–8 are flow diagrams for the proposed processing configurations. Based on technical and economic ranking criteria, eight configurations are shown. In configurations 1 and 6, the hydrogen generation unit (HGU) is not included, as hydrogen (H2) demand can be met by recovering the H2 from the gasoline reformer unit.

Product yields and properties.

In all cases, product streams generated in each process unit were blended to obtain the final products with desired quality specifications such as Euro IV for gasoline and diesel.3 A commercially available software was used in the optimization and planning of plant operations in the refineries; in-house developed correlations and a knowledge data base available at IIP were used to calculate the yields and properties of different products obtained from each process unit.4–9 Product yields obtained for each refinery configuration are listed in Table 3, along with the distillate yield, which is the summation of kerosine, gasoline and diesel yields.


Study results indicate that the individual product and combined distillate yield (gasoline + kerosine + diesel) are configuration dependent and governed by the combination of secondary conversion processes included in the configuration. Accordingly, the configurations can be categorized in these classes based on configuration selectivity toward specific types of product manufacturing potential.

• Gasoline and diesel-oriented configurations (1, 5, 6 and 8). Euro IV gasoline and diesel can be manufactured.

• Diesel-oriented configurations (4 and 7). Only Euro IV diesel can be produced. However, these processing configurations do not have gasoline production potential.

• Propylene-oriented configurations (2 and 3). These processing configurations have propylene manufacturing potential that the other options do not have due to FCC*/propylene recovery unit inclusion in these configurations.

From Table 3, it is clear that in Configurations 1 and 6, there is surplus light naphtha whereas in Configuration 7, about 52,000 metric tpy of light naphtha procurement is needed to meet H2 demand in this configuration. Distillate yield value (gasoline + kerosine + diesel) follows configuration numbers in the order of 4>5>7>1>8>3>6>2. However, including LPG yield in the distillate yield changes the former trend to 4>5>1>7>3>8>2>6. These trends suggest that including a hydrocracker will yield more distillates. The configurations (6, 7 and 8) with the solvent deasphalting (SDA) unit give a lesser combined distillate yield value corresponding to the configurations (1, 4, and 5) with the delayed coking unit (DCU) in place of the SDA.

From the crude vacuum resid (VR) fraction physico-chemical characterization, it is clear that the VR has a low sulfur and vanadium content but has a high nickle (Ni) content. Thus, only fuel-grade coke can be produced from the DCU using VR as a feedstock due to Ni content. However, if the VR’s Ni metal content can be reduced by pretreatment, then premium-grade anode coke can be produced due to the very low sulfur and vanadium content in the VR. Lowering the sulfur content (<1%) of the fuel oil provides opportunities to sell it at a higher price than the refinery-fuel grade.


  Fig. 1. Configuration 1—CDU + DCU + FCC + Reformer + HDT.


  Fig. 2. Configuration 2—ADU + FCC* + SHDS + PRU + HDT + HGU.


  Fig. 3. Configuration 3—CDU + DCU + FCC* (50% LR) + SHDS + PRU + HDT + HGU.


  Fig. 4. Configuration 4—CDU + DCU + HDK + HDT + HGU.


  Fig. 5. Configuration 5—CDU + DCU + HDK (60%) + FCC + Reformer + HDT + HGU.


  Fig. 6. Configuration 6—CDU + SDA + FCC + Reformer + HDT.


  Fig. 7. Configuration 7—CDU + SDA + HDK + HDT + HGU.


  Fig. 8. Configuration 8—CDU + SDA + HDK (60%) + FCC + HDT + HGU.

Economic evaluation.

The economic analysis for these configurations was carried out for 5 metric MMtpy (100,000 bpd) crude processing capacity. The study was done during second quarter (2Q) of 2010. Crude and product prices were taken from the database available on Internet, in public sector oil refineries and IIP database.1, 9, 10 Capital costs of processing units were also taken from data available in technical journals, Internet and information provided from oil refineries; units capital cost were corrected for the base price corresponding to 2Q 2010, using the Marshall & Swift equipment cost index.10–12

To calculate payback for each configuration, a straight-line depreciation method was used assuming a plant life of 15 years. Corporate tax was considered at the rate of 30% of gross profit. Manpower charges of $22.2 million, and insurance, maintenance and miscellaneous costs at the rate of 0.5%, 4.5% and 0.15% of plant cost, respectively, were considered under the working capital head along with the crude’s cost. These configurations were compared with respect to product sales value realization, the investment required to set up the grassroots refinery, utility cost, gross profit and the payback period. Table 4 lists the details of the economic evaluation.

The results from Table 4 indicate that gross profit follows the configuration number trend: 2>4>7>3>1>6>5>8. Although, products sale values for Configuration 2 and 4 are comparable but payback period values are significantly different due to higher capital investment and utilities cost requirements for Configuration 4. Furthermore, Configuration 7 (CDU + SDA + HDK + HDT + HGU) has comparable gross profit and payback period value with Configuration 2, but a significant amount of pitch is generated that can pose a serious demand and disposal problems, and pushes this configuration as less attractive than 2 and 4.



These preliminary refinery configurations conceptualization and their economic evaluation analysis results indicate that Configuration- 2 (ADU + FCC* + SHDS + PRU + HDT + HGU) tops the gross profit and payout period ranking list. Maximum gasoline yield is obtained in Configuration-1 (CDU + DCU + FCC + Reformer + HDT), but it occupied 5th place in gross profit payback period ranking. However, Configuration 4 (CDU + DCU + HDK + HDT + HGU), which ranked just below Configuration-2 from profit and payback points of view, but provides the maximum distillate (4,305 metric tpy diesel) manufacturing potential against the distillate yield (2,856 metric tpy gasoline and diesel) for Configuration 2.Therefore, in view of current diesel driven economy, Configuration 4 may be proved the best over the long term. HP

* The INDMAX technology maximizes the conversion of heavy oils to highly olefinic LPG through a fluidized catalytic cracking (FCC) process.


ADU Atmospheric distillation unit
VDU Vacuum distillation unit
CDU Crude distillation unit (ADU + VDU)
DCU Delayed cocker unit
FCC Fluidized catalytic cracking unit
SHDS Selective hydrodesulfurization unit
PRU Propylene recovery unit
HDK Hydrocracker unit
SDA Solvent deasphalting unit
HDT Hydrotreating unit
DHDT Diesel hydrotreating unit
NHT Naphtha hydrotreating unit
NSPL Naphtha splitter
HGU Hydrogen generation unit
INDMAX FCC/propylene recovery unit
LN Light naphtha
HN Heavy naphtha
LCGO Light coker gasoil
HCGO Heavy coker gasoil
LCO Light cycle oil
VGO Vacuum gasoil


1 http://www.automatedtrader.net/real-time-dow-jones/7808/-cairn-india-1q-net- profit- surges-on-mangala-crude-output.
2 The Economic Times, Sept. 15, 2010.
3 Society of Indian automobile manufacturing website, www.siamindia.com/scripts/ fuelspecifications.aspx.
4 HPI Consultants Inc, Petroleum Refining Process correlations.
5 Prakash, S., Refining Process Handbook, Gulf Professional Publishing, 2003.
6 Mapple, R. E., Petroleum Refining Process Economics, 2nd Ed.
7 Garry, J. H. and E. Handwerk, Petroleum Refining: Technology & Economics, 3rd Ed.
8 Ingenious Inc, ProPlan, Version 3.6.
9 ICIS prices, 9th July 2010, www.icispricing.com.
10 Data from public sector oil refineries.
11 “Refining Processes 2000,” Hydrocarbon Processing, September 2008, pp. 60–80.
12 “Economic indicators,” Chemical Engineering, September 2010.

The authors 


Sunil Kumar received an MS degree in chemical engineering from the Indian Institute of Kanpur, India in 2009. He has been awarded with Certificate of Merit for Academic Excellence in the Master of Technology Programme in chemical engineering at IIT Kanpur and also honored with Ambuja’s Youngh Researchers Award. He started his career in modeling and simulation group, as a scientist, at Indian Institute of Petroleum (CSIR), Dehradun, India, in 2009. He has completed several projects in the area of petroleum refinery separation and conversion processes using the advanced state-of art tools.


Shrikant Nanoti is head of separation processes division at Indian Institute of Petroleum, Dehradun, India. He received a chemical engineering degree from Laxminaryan Institute of Technology, Nagpur and a PhD from the Indian Institute of Technology. Dr. Nanoti has over 26 years of experience in the development and scale-up of separation-based technologies, process design, process integration and pinch analysis for the petroleum refining and petrochemical industries. He has published more than 35 research papers in national and international journals and holds eight patents. 


Yogendra Kumar Sharma has 30 years of experience in analytical, research and development work and presently heads the crude oil evaluation laboratory at Indian Institute of Petroleum, Dehradun. Dr. Sharma was awarded the INSA/DFG fellowship to work on mechanism of degradation of middle distillate fuels at Engler Bunte Institut der universitat Karlsruhe, Germany and has submitted the D.Sc theses at B.R Ambedakar University of Agra. He is a NABL technical assessor and has significantly contributed to the evaluation of various indigenous and imported crude oils, natural gas liquids, condensate and petroleum products. Dr. Sharma has published 12 research papers in international journals and has filed seven patents. 


Dr. M. O. Garg is the director of Indian Institute of Petroleum, Dehradun, a constituent laboratory of Council of Scientific and Industrial Research. Dr. Garg has 33 years of experience in the refining industry. He started his career after graduating from IIT-Kanpur in the Research and Development Division of Engineers India Ltd. in 1976. He earned a PhD at University of Melbourne. In 1994, he joined the process system services division of KTI-Technip India Ltd. and joined Indian Institute of Petroleum in 1998. Dr. Garg has developed and commercialized several technologies and has received two CSIR Technology Award . Dr. Garg has published over 207 papers and holds 26 patents . He has been elected Fellow of Indian National Academy of Engineering. Dr. Garg specializes in the area of liquid-liquid extraction, simulation and modelling, process integration, advance control, and process conceptualization. He is acknowledged as an expert in petroleum refining and petrochemicals.

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Chayan Bhalla

Good work. It gives important info on Mangala crude as well as various concievable refinery configurations.


Excellent knoweldge sharing article

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