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Upgrade heavy oil more cost-efficiently

09.01.2012  |  Cabrera, C. A.,  Ivanhoe Energy, Calgary, Alberta, CanadaSilverman, M. A.,  Ivanhoe Energy, Calgary, Alberta, Canada

A new technology can economically upgrade and significantly improve the properties of heavy oil by reducing viscosity, increasing gravity and removing contaminants.

Keywords: [oil] [oil sands] [heavy oil upgrading] [bitumen] [syncrude]

Heavy petroleum resources are becoming significantly more important as the availability of light, sweet crude oil continues to decline (Fig. 1). Heavy-oil resources are difficult to extract, transport and refine. Producers are focused on heavy-oil regions around the world, such as Venezuela, the Amazon basin and Canada’s oil sands. A new technology can be used in the field to economically upgrade and significantly improve the properties of heavy oil by reducing viscosity, increasing gravity and removing contaminants (Fig. 2). The authors discuss the economic drivers and benefits now available with this new method.

  Fig. 1. Global Oil recoverable resources.

  Fig. 2.  Commercial demonstration facility
  in Bakersfield, California.


Demand for refined crude oil products continues to be strained by the large and continually growing demand from developing economies, particularly from economic growth in Asia Pacific nations. Although forecasts vary widely, there is a new optimism over recent hydrocarbon resource discoveries in North America (mainly in the US) and South America (Brazil). However, the price of crude oil will continue to be most influenced by the world’s largest producers that have spare capacity. To alleviate high prices due to ever increasing demand, new sources of petroleum supplies will be required.

A largely untapped source of heavy crudes can be used to significantly augment supply. As shown in Fig. 1, there are substantial reserves of heavy oil, up to 2 trillion barrels, which constitutes nearly half of the remaining recoverable crude oil supply.1

Advanced technologies deployed across all phases of the supply chain will be needed to improve the economics and feasibility of producing and refining heavier crude oils. A novel technology has been proven to economically uplift the value of heavier crudes in the field. The uplift, or incremental margin captured per barrel of crude processed, is dependent on the quality of the heavy crude upgraded and ranges from $19/bbl to $32/bbl.


Historically, the petroleum industry supply chain has been divided into three discrete sectors: production, transportation and refining. Typically, crude is produced and made ready for transportation by production operations, and it is transported via pipeline or ship, train or truck to more sophisticated and complex refineries. Once at the refiner, the crude oil is refined into transportation fuels and other high-value finished products. The downstream sector of the hydrocarbon industry continues to optimize processing schemes to take advantage of the lowest-cost crude oil, of which a significant portion of the “opportunity crudes” are heavy oils.

Production of heavier crudes strains the present supply chain. These crudes include those found in the Canadian oil sands, the Orinoco Belt in Venezuela, Mexico, the Middle East, Africa, and other locations. The API of such crudes ranges from 6° API to 16° API, and the resources can be located onshore or offshore.


Supply-chain constraints include the need to heat the heavy oils in situ (underground) to reduce the viscosity so that the oil will flow to the surface. After produced crude oil is dewatered, it must be diluted with a lighter hydrocarbon so that the crude oil can flow in a pipeline and be transported to the refinery gate. These diluents are typically naphtha or light oils, and diluents can make up 40% of the blended heavy-oil stream, thus adding significant cost to production operations.


Transporting diluent to the production facilities requires dedicated pipelines. Operators incur the costs to build and operate the diluent delivery facilities, as well as suffer the decrement in lost pipeline capacity that could be otherwise used to transport additional valuable crude.


Once at the refining center, the heavy oil is typically processed through a delayed coking unit where approximately 30% to 35% of the residual oil is converted to coke.

In summary, several factors are important in considering heavy oils as a feedstock for producing transportation fuels:

  1. Heavy oils require significant energy for extraction from the reservoir
  2. A diluent source is required to allow their transportation
  3. Large refinery investments are necessary for processing heavy oils and a significant fraction of the feed is converted to a low-value byproduct—coke.

Novel process

A new process has been proven to overcome many of the production, transportation and refining challenges of heavy oils. It is energy efficient. This process produces the energy in situ that is required to heat the heavy crudes to bring the oil to the surface. This process selectively removes the least valuable of the components (resid) of the heavy oil. This process significantly reduces the heavy crude’s viscosity and eliminates the cost and use of diluent. By eliminating most of the residual oil, the synthetic crude oil (SCO) is much easier to transport and more amenable for processing in refineries.

Excess energy can be generated and made available for export or for extracting the heavy oils from the reservoir. The process consumes only 8 vol% of the heavy oil in the process, thus leaving up to 92 vol% of the heavy crude oil produced for sale and/or refining. The resultant SCO can be effectively processed in most modern refineries. The heavy-oil upgrading (HOU) units can be designed at scales, as low as 10,000 bpd to 30,000 bpd. The process is ideal for modularization and access to remote locations.


By installing an HOU unit at the production site or midstream in the supply chain, significant economic returns can be realized. Fig. 3 illustrates the relative values of SCO at the refinery gate for the Canadian Athabasca Bitumen case as compared to other crude oils.2 In this example, the value of SCO crude, as determined by its convertibility into refined products, is $108/bbl vs. $82/bbl for the native unprocessed Canadian bitumen. This represents a $26/bbl uplift in value through the use of the HOU process.

  Fig. 3.  Example of crude oil price seriatim—Canadian crude oils.

In addition to uplifting the value of crude oil, the HOU process also produces energy for field operations and eliminates the reliance on diluent for transportation. This significantly lowers operators’ production costs thus improving the economics of heavy-oil projects.

Shift in operations

The new paradigm is that the energy industry has the flexibility to add a new technology that can optimize the supply chain. By selectively rejecting carbon economically and efficiently at the production site, vs. at the refinery, substantial economic returns are possible, thus breaking the old paradigm.

The existing constraints that impose a significant economic penalty to the commercialization of heavy oils can be removed. The new process is highly scalable and cost-effective. For the first time, a new field-integrated approach allows carbon to be selectively and economically rejected closer to the production site.


A variety of business models have been used to determine the best applications of this novel and unique technology. Attractive returns on investment (> 20%) and a net present value (NPV) of $200 to $500 million are achievable depending on the installation, geography and type of heavy crude oil to be upgraded and converted into SCO.


The HOU process uses a circulating transport bed of hot sand to quickly heat the heavy feedstock and convert it to a lighter, more valuable product. Fig. 4 shows an overview of the HOU process flow.3 The underlying breakthrough of this method is that the asphaltenes present in heavy oil residue are dispersed and deposited on the sand in a thin film. This is facilitated by the high sand-to-oil ratio and efficient feed injection zone mixing. The process requires less than 2 seconds total time from feed in to product out. The very short residence time is at the heart of the process. It allows conversion of the heaviest residue into high yields of lighter, more valuable products with a minimum production of unwanted byproduct coke and gas.

  Fig. 4.  Process flow diagram of the HOU process.

The heaviest fractions of the liquid feed are converted to coke, which is directly deposited on the circulating sand particles. In addition, a small portion of the residue feed converts to noncondensable product gas. The coke-covered sand is regenerated in the reheater where the thin coke layer is burned off, thus providing the energy necessary to support the upgrading reactions and to also supply substantial excess energy that can be captured via high-pressure (HP) steam generation.

Product gas is collected and consumed as fuel gas in fired heaters and steam boilers that support the HOU unit’s internal energy demand while coproducing HP steam. This process generates enough excess energy to supply virtually the entire steam requirement for a typical steam-assisted gravity drainage (SAGD) project in Canada. Alternatively, in regions where steam is not needed for oil recovery, the excess energy can be converted into electricity. A typical 20,000-bpd HOU plant generates an energy equivalent of a 40-MW power plant.

Proven processing principles

The HOU process is mechanically very similar to a fluidized catalytic cracking (FCC) unit, a common conversion process found at the center of every modern refinery.4 At present, there are over 400 FCC units in operation today, and FCC has been commercialized globally since the 1940s. Although configured similarly to an FCC unit, the HOU process requires fewer pieces of equipment and is noncatalytic. Result: It is less complicated and easier to operate than an FCC unit.

Products and yields

The properties of the HOU product SCO, such as API, viscosity, metals, sulfur and nitrogen, are significantly better than the original heavy oil feedstock. This processing method nearly eliminates the residual oil (material boiling above 1,000°F) originally present in the feed and yields a SCO product that can be processed in refineries without producing large quantities of undesirable heavy fuel oil and requiring additional residue conversion capacity.

Unlike coking, this process does not accumulate large volumes of coke byproduct, which must be stored or transported offsite. The produced coke is consumed by the process itself and converted into onsite energy. Also, unlike other upgrading technologies, which require hydrocracking and/or hydrotreating, the HOU process does not require hydrogen addition to achieve the desired improvements in product quality. This represents a significant capital cost advantage in comparison with traditional technologies due to the reduced scale of the processing site and the fewer pieces of equipment required.

Table 1 summarizes the product yields using Athabasca bitumen as a feedstock in the HOU process. Note: Low residual oil in the SCO (5.8 voll%) as well as the very high yield of vacuum gasoil (VGO) plus distillates (78.9 voll%) Table 2 is an example of product properties that list the significant improvement in API, metals, viscosity, etc.



In many locations, producers are faced with declining rates of local light crude oil supplies that have traditionally been used as blendstock to facilitate delivery of heavy oil to markets. At the same time, these producers are also relying on increased volumes of heavier oil production to satisfy future export demand. These diverging production trends lead to crude oil quality that cannot meet pipeline and customer-contract specifications, or result in the market value of the heavy blends being so severely depressed due to residual oil conversion limits at the refineries that the heavy oil can no longer be economically produced. Countries and companies are facing declining rates of benchmark crudes, and are seeking ways to replenish supplies of export volumes with crude oil that can meet historical quality specifications. As illustrated in Fig. 5, HOU processing methods can offer unique opportunities to these producers via midstream solutions.

  Fig. 5.  Midstream configuration to upgrade
  heavy oil into lighter, transportable SCO
  and to produce electrical power.

This process can be strategically located at a site where heavy-oil production streams are gathered, such that the producer can eliminate or reduce the need for blending with large volumes of higher-value crude oil. The heavy oil is received from the producer, and upgraded in a location convenient to both the producer and the transportation terminal operator. Excess energy from byproduct gas and coke is converted onsite into electrical power that can be used to supply local electricity demands. Upgraded SCO is forwarded downstream to the transportation terminal, where it can be directly transferred to sales or utilized as a lighter diluent for blending with heavy production. The small footprint of the processing unit, coupled with the lower installation cost, is an attractive midstream solution.


Following development, scale-up and testing operations, the designing and engineering of full-scale HOU facilities for commercial heavy oil projects is underway. The basic engineering and design (BED) package has been completed for Ivanhoe Energy’s Tamarack Athabasca Oil Sands Project. This phase established a complete deployment strategy, including the technical design basis, capital cost estimate and project execution strategy for the first commercial unit. Key technical design deliverables were finalized, such as process and instrumentation diagrams (P&IDs); equipment, instrument, and materials purchase and installation specifications; and three-dimensional (3D)CAD modeling of plant equipment locations, piping networks, civil and structural supports (Fig. 6).

  Fig. 6.  Footprint of a commercial HOU facility.


A key component of the project execution strategy is modularization, and it has been fully incorporated into the cost estimate and the design plan based on extensive project experience in Canada. The capital cost estimate for Tamarack has been developed to Class 3 (AACE) accuracy. This estimate was completed at the end of the front-end engineering and design (FEED) phase with competitively priced equipment and installation costs based on physical material-takeoffs generated by the 3D CAD model.

The BED, FEED and value-engineering efforts undertaken for the Tamarack project will serve as a basis for future conceptual and feasibility studies. A conceptual engineering study and accompanying cost estimate were recently completed for a Latin American midstream project. This commercial engineering work has demonstrated that the HOU process is economic at feed capacities as low as 10,000 bpd to 30,000 bpd, and the typical Class 4 cost estimate for a plant ranges from $12,000/bbl to $20,000/bbl of capacity, depending on scale, feedstock properties and configuration.


This novel process is a powerful way to monetize heavy oil resources either at the source deployed to a production field, or in the midstream application. The key value to this novel process’ is that the SCO produced is of great value to refiners. Such value is principally the result of:

  • Low residual oil content (6 wt%–10 wt%)
  • Higher API (16°–20°).

A recent study by a world-class independent consulting firm determined the market value of HOU SCO in several different refining centers. This study was done using proprietary refinery modeling and optimization tools (linear programs or LPs) that are representative of regional refining centers and can be used to determine the value of a new crude oil when brought into the overall feedslate of that refining center.

The premise of the evaluation was to simulate penetration of HOU-produced SCO into the refining center’s overall crude diet, and allow the regional LP modeling tool to optimize the refinery operations with the new crude slate. Product volumes and prices were held constant, such that the optimization program could adjust unit operations and the suggested market price for the new crude. The program iterates through the model calculations until the refining center model is able to achieve the same gross product volumes and net margins (profits) with the new crude slate, as was realized from the original crude slate. The result of this analysis is the determination of the SCO value, benchmarked against a crude oil with a known market price.

Modeling of HOU SCO was evaluated at market penetration levels of 1% to 5% to ensure that the refining models were adequately reflective of the expected market price of the HOU SCO. This procedure provided certainty that, on aggregate, the refineries in a regional center will be able to realistically introduce the SCO in significant volumes and that the market value determined by the study is realistic and achievable. Two strategic HOU SCO products for modeling were selected:

  • Expected commercial SCO product from the future Tamarack Athabasca Oil Sands Project in Alberta, Canada. Penetration of the Tamarack SCO was modeled into two key refining centers. The first center evaluated was the Midwest refining region of PADD 2 due to the geographical proximity to Canada. The second center was Singapore, which serves as a proxy for the Asia Pacific region.
  • The other SCO modeled was the product of HOU processing of Boscan crude oil from Venezuela. The Boscan SCO was modeled into the PADD 3 center, as well as into the Singapore refining center.

The results of this study determined that the HOU SCO will be valued on a par with Brent price, with the differences dependent on a combination of the refining center selected and the feed quality. HOU SCO has a very low content of residual oil and a very high VGO content, such that it makes an excellent feedstock for refineries with sufficient hydrotreating capability to manage the SCO’s high sulfur and low hydrogen-to-carbon ratio. The penetration studies show that refining capacity available for processing SCO exists in significant amounts for all regions, thus supporting these price levels since the calculated SCO values were independent of market penetration within this range.

The pricing forecasts for heavy oil and SCO generated in this study, together with the CAPEX and OPEX estimates, were used to generate the expected economic returns for sample HOU projects. For example, projects with capacities of 20,000 bpd to 30,000 bpd are expected to provide IRR’s between 15% and 30% depending on location specifics, feedstock quality and various design considerations. HP

  Fig. 7.  Feedstock test facility at the
  SouthwestResearch Institute in San Antonio,


The authors thank Michael Hillerman for his assistance in preparing this manuscript and also Hilary McMeekin and Jerry Schiefelbein for reviewing the manuscript.


1 International Energy Agency, World Energy Outlook 2011, (excludes Kerogen oil).
2 Independent study with world class consulting firm.
3 Complete HTL process video available at www.ivanhoeenergy.net.
4 Cabrera, C. A. and M. Silverman, “Bringing heavy crudes to market,” International Refining and Petrochemical Conference 2012, 12-14, June 2012, Milan, Italy.


The article is a revised and updated version from an earlier presentation at the International Refining and Petrochemical Conference 2012, 12–14 June 2012, at Milan, Italy.

Ivanhoe Energy uses technologically innovative methods to significantly improve the development of heavy oil and other oil and gas assets. Primary among these is Ivanhoe’s proprietary, patented heavy-oil upgrading process called HTL, or Heavy-to-Light.

The authors 

  Carlos A. Cabrera is the executive chairman of Ivanhoe Energy, a publicly traded oil and gas company. Prior to his appointment, he served as the founding president and CEO of the National Institute of Low Carbon and Clean Energy (NICE) based in Beijing, China. Mr. Cabrera was also a 35-year employee with UOP, holding posts as the president/CEO and then chairman. He is a distinguished associate to the world energy consulting firm FACTS and serves on the board of directors of GEVO, a publicly traded biotechnology company, and the Gas Technology Institute, a US-based leading research, development and training organization. Mr. Cabrera has been given many awards, including being inducted into the University of Kentucky Engineering Hall of Distinction and the Honeywell Corp. 2008 Senior Leadership Award. He earned a BS degree in chemical engineering from the University of Kentucky and an MBA from the University of Chicago. 

  Dr. Michael Silverman is executive vice president and chief technology officer of Ivanhoe Energy. Dr. Silverman joined Ivanhoe in 2007 from Kellogg, Brown and Root (KBR) and is responsible for all technical aspects of Ivanhoe Energy’s proprietary heavy oil upgrading process—HTL (heavy-to-light). This includes interfacing with leading engineering firms in the design of commercial HTL installations, technology development and intellectual property management. Dr. Silverman has almost 30 years of experience in technology development and management, including the commercialization and marketing of new technologies, and is a leading expert in the fluid catalytic cracking (FCC) processes. Prior to joining KBR, Dr. Silverman was the manager of technology development for Stone & Webster, Inc. His earlier experience included the management of fluid catalytic cracking for Tenneco Oil Co., and an assistant professorship in chemistry at Rutgers University. 

Technology Development History

In 2005, Ivanhoe Energy acquired the petroleum rights of a patented pyrolysis process that is based on a hot “transported” bed (typically, sand) to produce renewable liquid fuels and chemicals from wood residues and other solid biomass. Being forward-thinking, Ensyn investigated the applicability of applying a hot “transported” bed as a possible way to upgrade heavy oil in situ. The process, HOU, was studied extensively during early pilot-plant work, and then validated by successful operation of a 1,000-bpd commercial demonstration facility (CDF) in Bakersfield, California (Fig. 2). Testing of heavy crude oils in the CDF proved the scalability of the HOU process, and it also provided key design information for the first commercial BED package and FEED of Ivanhoe Energy’s Tamarack project in Alberta, Canada.

In 2008, Ivanhoe Energy commissioned the feedstock test facility (FTF) at the Southwest Research Institute in San Antonio, Texas (Fig. 7) to further improve the process for a wide range of heavy oil feedstocks. The FTF was designed to model the commercial HOU process, but at a reduced capacity, making it feasible to test smaller batches of heavy crude oils rapidly. Equipped with a state-of-the-art process control and measurement system, the FTF maximizes the quality of data collected, validating technology advancements being made to this novel process and supplying critical data for commercial design. Ivanhoe Energy has completed technology development and commercial engineering. The process will not be available for licensing. HP

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Cephala is back

I have been shorting this stock for 8 years, and I am getting worried about my short since Tamarack will likely get some good news this month, IVAN is meeting with AER, and so to with Ecuador's government to finalize their megafield (put 20) partner--bad time to short, I'm going to switch to long.


Not sure who tried to copy me but I have a good idea who it is.
The post below was made by an imposter and not me. Another scam to try hide the truth regarding the "unproven" technology called Heavy-to-light or HTL.

I have never owned or shorted IVAN shares and never will due to 8 years of HTL will not one plant in operation anywhere on the planet.

After further review, I have discovered the value of the HTL process, and have bought shares of IVAN. I believe this is a very viable process for certain oil fields.

William DeMarco

What is the latest with HTL? I see a comment from Roger Lott that says the thermally cracked oil is useless? How much truth is there to his statement?

Esteban Benitez

Dear Sirs,

I would like to know if a comercial unit is alreday in operation. On the other hand, where we can see the pilot plant operation.

Kindly Regards,

Esteban Benítez
Cel: 57-312-5093326

Roger Lott

HTL produces an unstable, thermally cracked oil that has no market unless with heavy discount. Moreover, the cracked oil will form gum in storage or during transportation. What a waste of investor money.


CCC upgrading technology to convert heavy oil / oilsand into light oil

The process using a proprietary catalyst will convert raw oilsands /heavy oil into diesel fuel light oil, synthetic gas and clean sand/coke. The process can be operated at normal pressure through low temperature heating. Laboratory tests on Athabasca oil sands and oil sands from other countries have been conducted and received excellent oil and gas yield.

Jesús T Espinoza Sandoval

I agree, is a great achievement. And I wonder if this technology have had commercial applications

omothoja olumari

this is a great achievement, I will really love to see a video clip of this process, or a more detailed picture of the process.

Great job,
Omothoja Olumari


After further review, I have discovered the value of the HTL process, and have bought shares of IVAN. I believe this is a very viable process for certain oil fields.


What is projected date for full scale operation of an HTL unit at the Tamarack project? Seems such an announcement would be huge boost for stock


Looks like IVAN forgot to mention their HTL projects never came tto pass. Look up IVAN to build HTL facility in Iraq. This is the last ditch effort of IVAN to "spread the word" before their stock is delisted by NASDAQ. Sad but the truth is HTL is not in use anywhere on the planet.

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