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).

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Case Study

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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 Year 2000 Year 2010 Year 2015 World Overall 32.5 32.4 32.3 Western Hemisphere 28.1 27.6 27.3 Eastern Hemisphere 34.0 34.0 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

Case Study progressively increasing and will need to rely on better technologies that can effectively remove and recover sulphur from oil field and refinery production.

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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.).

Case Study

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

Historical Technology Selection

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Coking Visbreaking Hydrotreating Catalytic cracking Deasphalting

Case Study 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.

Case Study

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

Case Study 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%) Product (vol%)

Gravity, API 8.5 24.8 Sulphur, wt% 5.14 0.24 Nitrogen, wt% 0.27 0.14 C5 Asphaltenes 17.3 1.6 C7 Asphaltenes 12.6 1.2

CCR, wt% 12.8 2.6 Table 2.2 GHU® Upgrading Process Results

API Increase 16.3 % HDS 95 % HDN 48

CCR Conversion, % 80 C7 Asphaltenes Conversion, % 90

975°F+ (524°C+) Conversion, % 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 GHU Product Temperature, °F --- 780 Pressure, psig --- 1700 LHSV, h-1 --- 0.25 Hydrogen to Oil Ratio, SCFD/bbl

--- 5500

API gravity (degrees) 12.40 21.56 Specific gravity 0.983 0.924

Case Study Sulphur, wt% 0.51 0.04 CCR, wt% 7.73 3.09 Nitrogen, wt% 0.457 0.27 Vanadium (V), ppm 8.205 1.14 Nickel (Ni), ppm 19.14 3.94 Table 3.2 Crude Product Yields Feed (Vol%) Product (Vol%) Full Range Naphtha, IBP to 200°C 0.8 5.3 Kerosene, 200 to 300°C 5.1 13.2 Heavy Diesel, 300 to 350°C 18.7 12.5 Vacuum Gasoil, 350 to 535°C 39.7 52.5 Vacuum Residue, 535+ °C 35.7 16.5 * IBP = initial boiling point

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

Case Study 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.

Case Study 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

Process Delayed Coking

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

or Air Cooled Requires large volumes of

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

Case Study 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  

Case Study 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-to-refine 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.