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
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
IBP370°C) and naphtha (from IBP140°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.
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
These configurations were developed using technologies and
processes that are already commercially proven and well
established in refineries. Figs. 18 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
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.49 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
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
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
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 VRs 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
1CDU + DCU + FCC + Reformer + HDT.
Fig. 2. Configuration
2ADU + FCC* + SHDS + PRU + HDT + HGU.
Fig. 3. Configuration
3CDU + DCU + FCC* (50% LR) + SHDS + PRU + HDT +
Fig. 4. Configuration
4CDU + DCU + HDK + HDT + HGU.
Fig. 5. Configuration
5CDU + DCU + HDK (60%) + FCC + Reformer + HDT +
Fig. 6. Configuration
6CDU + SDA + FCC + Reformer + HDT.
Fig. 7. Configuration
7CDU + SDA + HDK + HDT + HGU.
Fig. 8. Configuration
8CDU + SDA + HDK (60%) + FCC + HDT + HGU.
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
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 crudes 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
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
2 The Economic Times, Sept. 15, 2010.
3 Society of Indian automobile manufacturing
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. 6080.
12 Economic indicators, Chemical
Engineering, September 2010.
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 Ambujas 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
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
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
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.