Case Study
Hydrocracking and Hydrotreating Refining Processes Needed
for Increasing Heavy Oil Demands
Utilizing hydroconversion refining for world oil demand and heavy oil processing
obstacle; Genoil Inc. GHU® Pilot Plant demonstrates capabilities on refinery
residuals
The increasing global demand of crude oil is turning towards heavier oils. The decline of
light oil reserves and an increase of heavy oil reserves are forcing the world to rely and
increase demand to heavier oil. According to a global estimation from Figure 1 & 2, light
oil reserves may be close to exhaustion in about 30 years (assuming that light oil
production will steadily decline by 0.9 billion barrel per year).
Crude Oil Reserves
1400
1200
Billion Barrels
1000
800
Heavy Oil
Light Oil 600
400
200
0
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
Year
Figure 1
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Crude Oil Demand
50
45
40
Billion Barrels
35
30
Heavy Oil
25
Light Oil 20
15
10
5
0
2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028
Year
Figure 2
REDUCING CRUDE OIL QUALITY
Throughout the years, global crude oil production has also revealed a decline in average
API. According to Table 1 predicted by the US “World Refinery”, the average API of
crude oil supplies in different regions is decreasing and they will be lower in the future
years to come.
Table 1
Crude Oil Average API
World Overall
Western Hemisphere
Eastern Hemisphere
Year 2000
32.5
28.1
34.0
Year 2010
32.4
27.6
34.0
Year 2015
32.3
27.3
33.8
In the US, Mexican, and South American regions, the heavy crude oil will be even
higher. North African traditional light sweet crude oil is declining rapidly and light oil
reserves in North Sea and China have only limited production. Although the Persian
Gulf is able to supply a large quantity and light crude oil, their oil supplies are becoming
heavier with higher sulphur content.
Along with lower API in crude oils, heavier crude oil contains higher boiling points,
acidity, metal, sulphur, & nitrogen contaminants, and carbon residue. Low API gravity
and high contaminant oil will result in lower market value and higher detrimental effects
to refinery equipment and face environmental repercussions. According to Figure 3, light
and heavy oil production with higher sulphur content, known as “sour oil”, are
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progressively increasing and will need to rely on better technologies that can effectively
remove and recover sulphur from oil field and refinery production.
Millions Barrels per day
100
90
80
70
60
High TAN
50
40
Heavy Sour
30
Light Sour
20
Light s weet
10
0
1990
1995
2000
2005
2010
2015
2020
Year
Figure 3
HEAVY OIL AND RESIDUE TECHNOLOGIES
Crude oil is regarded as a non-renewable resource, which is what heavy oil still is. It is
of great importance and strategic significance to increase the utilization of heavy crude
oil and residues by processing them into lighter, sweeter, less viscous products.
Conventional residue conversion technologies available in today’s age include coking,
visbreaking, catalytic cracking, deasphalting, and hydroprocessing. In Figure 4, at a
worldwide perspective, visbreaking, coking, and solvent deasphalting occupy the
technological majority of heavy oil and residue processing. Coking (also known as
carbon rejection), visbreaking, and deasphalting are simple technologies that do not
require a reactor-based chemical reaction to process residual oil, but their processes will
lose a significant amount of barrel profits and produce a lower quality liquid product
along with other low market value by-products (coke, tar, high sulphur fuel oils, etc.).
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Historical Technology Selection
4%
15%
Coking
Visbreaking
Hydrotreating
Catalytic cracking
Deasphalting
32%
19%
30%
Figure 4
HYDROCONVERSION PROCESS TECHNOLOGY
Hydroconversion upgrading technologies are better suited in processing bottoms
residuals and increasing refinery heavy oil feed yields.
As crude oil supplies are
increasingly becoming more acidic, sour, and heavier, more hydroconversion
technologies are demanded to be implemented in oil refineries. Refineries with reliance
to hydroconversion technologies will be able to upgrade residuals to high quality oil for
easier transportation and reduced coke production.
The hydroconversion process is a hydrogen addition method using once-through, single
pass operations. The original goal of the process was to upgrade heavy crude and
refinery residuals into higher quality, higher value products, such as naphtha and lighter
distillates. Another benefit of the technology is the capability of drastically reducing the
contaminant content of the heavy and sour oil products, where the targeted contaminants
are sulphur, metals, and nitrogen.
THE GHU® PROCESS
The Genoil Hydroconversion Unit (GHU®) provides a new route for heavy oil upgrading
and hydroprocessing methods. The main feature of the GHU comprises of a complex,
fixed bed reactor arrangement that can be utilized to upgrade high sulphur, acidic, heavy
crude, bitumen, and refinery residue streams, and for hydroprocessing naphtha, kerosene,
diesel and vacuum gas oil. The Genoil processing scheme is based on fixed bed reactor
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system with a reactor sequence and catalyst distribution to protect the more active
hydroprocessing catalyst. The first reactor is guard reactor containing HDM catalysts to
remove metals from the feed, followed by reactors using highly active HDS, or a
combination of HDS and HDN beds for sulphur and nitrogen removal, and final
conversion of heavier feed stock into sweet light crude or upgraded residue for utilization
in the existing refinery. If the feed is of a quality wherein the HDM guard bed is not
required, the entire hydroconversion process can be done through a single reactor. The
unconverted residue formed after hydroprocessing through the fixed beds of the GHU®
unit can be sent to a Syntheses Gas Unit, gasified, and the syntheses gas then used for
hydrogen recovery to supply the Genoil GHU®, and the remaining syntheses gas used as
fuel gas or to generate power and steam by adding an Integrated Gasification
Configuration Cycle (IGCC) unit into the overall plant configuration.
GHU® HYDROCONVERSION REACTOR SYSTEM
The hydrocracking and hydrotreating upgrading process involves various reactions to
upgrade and remove the heavy oil feed contaminants.
The reactions include
hydrodemetallization (HDM), hydrodesulphuration (HDS), hydrodenitrogenation (HDN),
and asphaltene and pitch conversions.
The GHU reactor sequence is arranged through four fixed-bed reactors. Each reactor
contains a proprietary catalyst arrangement for efficient contaminant removal and graded
catalyst protection during long processing runs.
The first reactor acts a guard reactor to trap the feed’s mechanical deposits from minute
amounts of coke and heavy metals. If the gradual deposits build up and cause excessive
pressure drop across the reactor, the reactor can be bypassed during the run for quick
catalyst replacement.
The second reactor serves as the HDM bed at upper column that captures metals such as
Nickel and Vanadium. The importance of this reactor protects the HDS and HDN
catalysts from premature deactivation from metal precipitates. It also includes HDS bed
downstream to remove sulphur.
The third and fourth reactors perform the main HDS, HDN, and additional hydrocracking
reactions. The HDS reaction will remove the sulphur compounds and form H2S, and the
HDN reaction will remove the nitrogen compounds and form NH3. Hydrocracking
reactions in the fourth reactor will break down large asphaltene and polycycloarmoatic
molecules.
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GHU® PROCESS FLOW SCHEME / PILOT PLANT TEST
Figure 5 Process Flow Diagram of Genoil 10 BPD Pilot Plant
Genoil owns and operates a 10 barrel per day GHU® pilot plant. The GHU® process
flow scheme is shown on Figure 5. The heavy feed oil is fed into the system, preheated
by a furnace, along with the hydrogen feed through an inline flow mixer. The mixing
device maximizes the mass transfer between oil and hydrogen fluids. Full dispersion of
one fluid into the other fluid is achieved (“micro-molecular mixing”) together with the
“super-saturation” of the gas into the liquid. The heated combined heavy oil and
hydrogen mixture flows into the reactors where hydrotreating and hydrocracking
catalysts take place. After reaction process, the overhead gas and treated oil go through a
series of cooling exchangers and a separation vessel where the upgraded oil and gases are
separated.
Using high activity hydrotreating / hydrocracking catalysts and proprietary design
technology, Genoil has conducted multiple pilot plant tests on various sour, heavy crude,
bitumen and residue oil feed stocks ranging from 6.5° to 17.5° API gravity. The operating
conditions (pressure, temperature, space velocity) were selected to achieve a minimum
one-year cycle while maintaining maximum conversion of the vacuum residue fraction of
the feed.
Table 2.1-2.2 shown below are the results of processing bitumen extracted from Western
Canada tar sands using the GHU® technology. With the addition of a distillation unit
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after the GHU® and using the residue to feed a syntheses gas unit, the API can be further
increased again from 24° to at least 34° API.
Table 2.1 Feed and Product Properties
Bitumen Upgrading by GHU®
Feed (vol%)
Gravity, API
8.5
Sulphur, wt%
5.14
Nitrogen, wt%
0.27
C5 Asphaltenes
17.3
C7 Asphaltenes
12.6
CCR, wt%
12.8
Table 2.2 GHU® Upgrading Process Results
API Increase
% HDS
% HDN
CCR Conversion, %
C7 Asphaltenes Conversion, %
975°F+ (524°C+) Conversion, %
Product (vol%)
24.8
0.24
0.14
1.6
1.2
2.6
16.3
95
48
80
90
81
In 2007, Genoil conducted a series of field tests on imported heavy oil and residual oil
from Chinese refineries. The field tests were performed as an investigation to upgrade
refinery and heavy oil blends feedstock (12.4°API) to reduce the sulfur, metals, nitrogen,
coke deposits, and increase product API under different operating parameters.
The pilot plant processed a 50/50 blended feed of heavy oil and atmospheric residues
under different severity conditions varying in pressure, feed ratio of hydrogen and oil,
temperature, and liquid hour space velocity (LHSV). One example of test result is listed
in Table 3.1-3.2. The test performed at condition of 780°F and 1700 psig, along with
superficial space velocity of 0.25h–1 , sulphur was reduced down by 92%, nitrogen
reduction and metals were reduced by 41% and 82%, carbon residue 59%, and API
increased by 9.2.
Table 3.1 Pilot Test Operating Conditions
Feed Blend
Temperature, °F
--Pressure, psig
---1
LHSV, h
--Hydrogen to Oil Ratio,
--SCFD/bbl
API gravity (degrees)
Specific gravity
12.40
0.983
GHU Product
780
1700
0.25
5500
21.56
0.924
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Sulphur, wt%
CCR, wt%
Nitrogen, wt%
Vanadium (V), ppm
Nickel (Ni), ppm
0.51
7.73
0.457
8.205
19.14
0.04
3.09
0.27
1.14
3.94
Table 3.2 Crude Product Yields
Full Range Naphtha, IBP to 200°C
Kerosene, 200 to 300°C
Heavy Diesel, 300 to 350°C
Vacuum Gasoil, 350 to 535°C
Vacuum Residue, 535+ °C
* IBP = initial boiling point
Feed (Vol%)
0.8
5.1
18.7
39.7
35.7
Product (Vol%)
5.3
13.2
12.5
52.5
16.5
Figure 6 TBP of GHU Feed and Product.
HIGH CAPACITY REFINERY APPLICATIONS
GHU technology can provide a unique means to yield more middle-distillate fuels with
low-S products. As mentioned before, the global crude supply becoming sour, heavier,
and acidic; refining these lower quality crudes will result in greater amounts of residues
with high metal and sulphur content. In addition, today’s stricter environmental laws and
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safer emission regulations demand cleaner burning fuels that limits markets in selling
high sulphur fuels.
Potential long-term solution for high capacity refining is addressed by installing a GHU
process to increase light-product yields from refinery heavy, low value, sour residuals.
Having a GHU will upgrade the residuals and change the refinery product quality,
generate higher margins, and reduce high sulphur residuals. Refiners will have an
opportunity to establish a “bottomless barrel” refinery system.
Figure 7 Process Flow Diagram of GHU Bottomless Barrel Project
GHU process can be integrated within existing refineries to establish a bottomless barrel
system (see Figure 7). Refinery residuals and new heavy crude oils are blended and
preheated from exchangers, then mixed with recycled hydrogen gas, passing through a
fire heater, and sent to the hydroconversion reactor system to yield gas and light
hydrocarbons. The reactor effluents are sent to high and low pressure separators to
separate the liquid products from the acidic gas overhead. The overhead gas is treated in
acid gas treatment units and reused as fuel gas and recycled hydrogen.
The new desulphurized, demetallized, denitrogenated liquid product is sent to
atmospheric distillation unit and vacuum distillation unit to be separated into saleable
products and sent back to the base plant as product blends. The increased output of
lower contaminated naphtha, kerosene, heavy diesel, and gasoil output will greatly
increase the existing refinery’s production.
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Any vacuum bottoms left behind are sent to a syngas unit (SGU) gasifier to be converted
into a syngas, which is later to be converted to recycled hydrogen and plant fuel gas (with
help of air separation, hydrogen, and sulphur recovery units).
A base refinery with any existing residue treatment units such as FCCU and coking units
can coexist and operate with the GHU. The advantage is that the newly low sulphur,
hydroconverted distillates can be sent back to FCCU to produce a higher yield of liquid
products or applying coking unit prior to GHU to treat dirtiest heavy oil.
Table 4 shows the comparison between GHU® process and Delayed coking process. In
terms of product yielding, the GHU® process yields all liquid product and no significant
amount of coke.
Table 4 Comparison between GHU Hydroconversion process and Delayed Coking
Process.
GHU ® Hydroconversion
Delayed Coking
Process
Residue Conversion
Up to 95%, once through
70-85%
Temperature
Low/Medium
High
Volume Output
100 ~ 104%
75 ~ 80%
Coke Production
0%
20~25%
Desulphurization (*)
>90%
37%
Hydrotreating
Includes Hydrotreating
Requires further Hydrotreating
Capital Cost
$ 7,000 ~12,000 per barrel
$ 8,000 ~14,000 per barrel
Equipment
Fewer Units in Facility
More Units in Facility
Water Usage
15 ~ 20% less than coking
Requires large volumes of
or Air Cooled
water for cooling and coker
Natural Gas Usage
Optional or None
Yes
(*) Source: Genoil test results / The American Oil & Gas Reporter, January 2006
MAIN ADVANTAGES OF THE GHU® UPGRADING PROCESS
 Flexible hydroconversion process: conversion and hydrogenation in one stage
 Output is 100 ~ 104% of liquid input volume versus approximately 80% of
coking processes when hydrogen is supplied by other means than syntheses gas
 Gives refiners flexibility to process sour, acidic, heavier crude feed stocks or
upgrade and recycle ATB / VTB residue back into the refinery overall process
scheme producing high value product from a low value feed
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 Proprietary devices to mix the hydrogen and the hydrocarbon stream achieving
super-saturation of the liquid hydrocarbons with hydrogen
 Stability of upgraded crude produced in hydroconversion process is superior to
coked products
 Removes the need for expensive blending diluents
 Flexibility of operation: “dial” the conversion level and the product properties by
changing the operating temperature, and capability to adjust product slate to meet
increasing demand for premium sweet synthetic crude product, including diesel
and gasoline
 Moderate operating conditions, temperatures and pressures allowing for simple
one stage reactor design with lower CAPEX and OPEX
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CONCLUSION
The GHU® is a fine example of hydroconversion technology that will be a viable option
for upgrading and decontaminating the growing heavy, sour crude oil supply. The
Genoil’s GHU® can provide existing plants the ability to convert residual and heavy oil
into low sulphur transportation fuels and middle distillates. With the world’s increasing
demand for transportation fuel and light distillates, and growing supply of harder-torefine sour, heavy oil and residuals, the GHU® can bring a better balance between the
supply and demand.
About Genoil:
Genoil Inc. is an engineering technology development company: focusing on upstream
and downstream refining, oil water separation, and other environmental matters in the
energy industry. Main technologies included the Genoil GHU® technology and Crystal
Sea Oil-Water Separation Units. Genoil is in list in the TSX as the symbol “V.GNO”
and in the OTCBB as symbol “GNOLF”. Website can be reached at www.genoil.ca.