From Bitumen to Synthetic Crude Oil: Upgrading Explained
- Upgrading is a process by which bitumen is transformed into light oil by fractionation and chemical treatment, removing virtually all traces of sulphur and heavy metals.
- Upgraders have 5 basic unit operations: (1) diluent recovery, (2) H:C ratio upgrading through hydrogen addition or carbon rejection, (3) fractionation or cracking of heavy oil into light oil, (4) removal of impurities and (5) product blending.
- About 40% of Alberta's bitumen, mostly sourced from mined oil sands, is upgraded into light/sweet synthetic crude oil (SCO) before being sold to downstream refineries.
- SCO is much better in quality than diluted bitumen and even slightly better than conventional light/sweet crude due to its lower sulphur and heavy metals content. SCO sells at a wide premium to diluted bitumen, typically close to par with West Texas Intermediate.
- The decision to upgrade depends on the required product quality, the needs of the final customer, and the price differential between heavy/sour versus light/sweet crude.
- Due to high capital costs and strong demand for heavy crude, Alberta's upgrading capacity is unlikely to keep up with growing production from the oil sands. The future of upgrading likely lies in partial upgrading, where heavy oil is transformed just enough to reduce diluent requirements, lowering transportation costs and improving netbacks.
Bitumen extracted from the oil sands is a heavy crude oil which contains a large fraction of complex long-chain hydrocarbon molecules. Depending on the extraction process used, bitumen product can sometimes contains as much as 2% water and solids, which does not meet pipeline specifications for transport over long distances. Pipeline specs can be met either by upgrading or dilution with a very light oil. Any crude that meets pipeline specs can be sold to downstream refineries, regardless of grade or quality.
Currently, about 60% of bitumen produced from the oil sands is diluted, typically with natural gas condensate, and sold directly to market as a heavy/sour blend. The remaining 40% is upgraded into a light/sweet synthetic crude before being sold to downstream refineries. All upgraded bitumen is currently sourced from oil sands mining operations, while most diluted bitumen is sourced from in-situ facilities.
TO UPGRADE OR NOT TO UPGRADE: THAT IS THE QUESTION
Upgraded synthetic crude and (non-upgraded) diluted bitumen have very different specifications, affecting both the selling price and marketability of the product. The decision to upgrade, or not, therefore depends on:
- Product Quality: A light sweet crude with few impurities (upgraded bitumen) versus a heavy sour blend containing sulphur and heavy metals (non-upgraded diluted bitumen).
- Marketability: The needs of the final customer (refinery) and its preference for feedstock (simple vs complex facility).
- Sale Price: Specifically, the differential between heavy/sour versus light/sweet synthetic crude, which needs to offset the added capital, operating and maintenance costs of an upgrader.
Bitumen produced from the oil sands is not only heavy, but also contains heavy metals, corrosive salts and a significant amount of sulphur. These impurities pose processing challenges to the downstream refinery, limiting the marketability of the product and sometimes even the selling price.
In contrast, upgraded bitumen (synthetic crude oil) is light, sweet and virtually impurity-free. This greatly increases the marketability of the crude, making is saleable to almost any type of refinery. Synthetic crude therefore sells at a premium to diluted bitumen.
|SYNTHETIC CRUDE OIL
Refineries typically blend different grades of crude feedstock with varying quality specifications, but not all refineries are built the same. Depending on the type, capacity and configuration of process equipment, each refinery has a limited ability to handle heavy grades of crude, with high concentrations of sulphur and other impurities.
Simple refineries can only process light crude feedstock with a low sulphur content. Bitumen produced from the oil sands would be too heavy and too sour for a simple refinery. In order for bitumen to be sold to a simple refinery, it must first be upgraded into a lighter crude oil.
More complex refineries, commonly referred to as high-conversion refineries, have the ability to process heavier feedstock, with higher concentrations of sulphur and nitrogen. These facilities have a larger capacity to process heavy crude, cracking the heavy components into lighter streams. High-conversion refineries actually prefer heavy/sour feedstock, producing better yields and higher profit margins. In order for bitumen to be sold to a high-conversion refinery, significant volumes of diluent must be added prior to transport in order to meet pipeline specs, normally about 30% by volume.
Traditionally, a majority of the bitumen produced in Alberta was upgraded into synthetic crude oil before being sold to downstream refineries. However, some bitumen is good enough to send directly to high-conversion refineries, which have a preference for heavy/sour feedstock.
As more and more refineries around the world convert to heavy oil feedstock, there is less of a demand for stand-alone bitumen upgrading. The economics of upgrading therefore lies in the price differential between heavy diluted bitumen and light crude oil.
According to IHS Markit, Alberta's upgraders have a typical operating cost of US$8-10 a barrel, excluding cost of capital. Factoring in the cost of capital, which can be north of $60,000 per flowing barrel, a new upgrader requires a light/heavy price spread of about US$25 per barrel in order to be economically viable.
UPGRADING 101: FROM DILUTED BITUMEN TO SYNTHETIC CRUDE
Although flowsheets can vary among the operators, upgrading heavy bitumen to a light synthetic crude involves 5 basic steps:
- Diluent Recovery: Diluent use to transport the bitumen is removed and returned back to the bitumen production facility. This diluent is typically a naphthenic solvent (commonly referred to as naphtha) but can also be a paraffinic solvent or condensate.
- H:C Ratio Upgrading: The hydrogen to carbon (H:C) ratio is improved either through carbon rejection (coking) or hydrogen addition (hydroconversion). A higher H:C ratio is indicative of a better quality crude.
- Heavy to Light Conversion: The lower-value heavy portion of the bitumen is converted into lighter hydrocarbons. This can be done through:
- fractionation (or distillation) where the different crude oils are separated by boiling point, and/or
- cracking, where the complex long-chain hydrocarbon molecules are broken down (cracked) into shorter-chain, simpler hydrocarbon molecules.
- Impurity Removal: Sulphur and nitrogen are removed, producing hydrogen sulphide and ammonia during a process known as catalytic hydrotreating. Removing these impurities enhances the quality and marketability of the final crude oil product.
- Product Blending: The different liquid fractions produced by the upgrader are then blended together to produce the desired crude oil product specification. Upgraded product is typically referred to as Synthetic Crude Oil (or SCO), which is then sold to downstream refineries for conversion into final consumer products.
Although exact equipment and configurations vary among the operators, a generic process flow diagram for a typical bitumen upgrader is as follows:
A typical upgrader is divided into 5 process circuits:
1. A&V Distillation
Bitumen feedstock is heated through a series of atmospheric and vacuum (A&V) columns, operated at moderate temperatures and low pressures. Diluent is removed in the atmospheric column, sometimes referred to as the Crude Distillation Unit (CDU). Naphtha and light gas-oil (LGO) are typically recovered and either sent to product blending tanks or processed in Secondary Upgrading for quality improvement.
The bottoms of the CDU are sent to the Vacuum Distillation Unit (VDU), where vacuum gas-oils (VGO) are flashed-off and send to Secondary Upgrading. Residue from the VDU is sent to Primary Upgrading for conversion/cracking into a lighter hydrocarbon.
2. Primary Upgrading (PUG)
PUG converts the bitumen residue into a lighter product through either carbon removal (coking) or hydrogen addition (hydroconversion).
Cokers operate at temperatures of about 500°C but relatively low pressures (about 350 kPa), thermally cracking the residue into light hydrocarbons such as naphtha, kerosene, and gas oils, leaving behind a coke residue. Cokers used in the oil sands are either Delayed Cokers, a batch process taking about 10 to 16 hours per cycle, or Fluid Cokers, which are more complex, continuous coking units. Both yield about 85%, since some of the bitumen is lost as coke product.
Carbon removal can also be achieved through solvent de-asphalting, where the very heavy-ends of the bitumen (asphaltenes) are removed through the addition of pentane. Removal of asphaltenes also reduces the yield, typically by about 15%.
As an alternative to coking or solvent de-asphalting, hydroconversion is where the heavy molecules are cracked through the addition of hydrogen in the presence of a catalyst (such as platinum). The most common hydroconversion process used in the oil sands is an LC-Finer, an ebullated catalyst-bed reactor operated at pressures ranging from 14,000 to 21,000 kPa. Distillate products from the LC-Finer are processed in an integrated hydrotreater. Since no carbon is rejected, hydroconversion results in virtually no loss of yield, but is considerably higher in capital and more complex to operate.
3. Secondary Upgrading (SUG)
SUG involves the complete or partial removal of sulphur, nitrogen, olefins and aromatics through the addition of hydrogen in the presence of a catalyst. Hydrotreated and/or hydrocracked distillate products are sent to the final product tanks or blended with other products.
4. Environmental Controls
Sulphur contained in the hydrogen sulphide stream produced in SUG is recovered in three unit operations:
- Amine regeneration unit: Hydrogen sulphide solution is stripped using steam-heated re-boilers. Recovered hydrogen sulphide is sent to the Sulphur Recovery Unit.
- Sour Water Stripper: Hydrogen sulphide and ammonia is stripped from sour water streams and also sent to the sulphur recovery unit.
- Sulphur Recovery Unit: Over 99% of the sulphur is recovered in liquid form. Residual sulphur is oxidized with sulphur dioxide, before being discharged to atmosphere. Sulphur products can be sold in liquid form or precipitated into sulphur blocks for sale as a solid sulphur.
5. Supporting Facilities
Every upgrader has a number of auxiliary facilities to support the production of hydrogen, steam and power, as well as heat recovery units, flare stacks, water treatment and a tank farm for product blending and feedstock storage.
Hydrogen is produced by steam methane reforming, then recovered and purified through pressure swing adsorption, producing 99.9% pure hydrogen. For those upgraders that produce an asphaltene product, gasifiers can be used to produce hydrogen through partial oxidation of the asphaltenes. Gasifiers reduce the upgrader's reliance on natural gas.
Power and steam can be produced by co-generation units, which burn natural gas, or coke-fire boilers, which burn pulverized coke (for those upgraders that produce a coke material). Coke-fired boilers are the cheaper alternative but produce higher CO₂ emissions.
SYNTHETIC VS CONVENTIONAL CRUDE OIL: COMPARING PRODUCT SPECS
Synthetic crude produced by a bitumen upgrader is slightly better in quality than conventional light/sweet crude, due to its lower sulphur and heavy metals content. Alberta's synthetic crude normally sells at par with West Texas Intermediate, and sometimes even trades at a small premium.
|WEST TEXAS INTERMEDIATE (WTI)||SYNTHETIC CRUDE OIL (SCO)||CANADIAN LIGHT|
5 ppm Ni
15 ppm V
5 ppm Ni
8 ppm V
|US benchmark for conventional light/sweet crude||Upgraded bitumen produced from the oil sands||Conventional light/sweet from Western Canada|
ALBERTA'S UPGRADERS: SIMILAR BUT DIFFERENT
About 40% of bitumen produced from the oil sands is upgraded into synthetic crude before being sold to market. There are currently 4 operational bitumen upgraders in Alberta:
- 3 located north of Fort McMurray (Suncor, Syncrude and CNRL Horizon Upgraders)
- 1 located NE of Edmonton, AB (Shell Scotford Upgrader).
With the exception of Shell's Scotford upgrader, all other upgraders are located adjacent to the mine and integrated with the Bitumen Production facility.
Nexen's Long Lake Upgrader is Alberta's only upgrader integrated into an in-situ facility. However, Long Lake was idled in the summer of 2016 after a fire crippled the facility. The adjacent SAGD (steam-assisted gravity drainage) facility remains operational and now produces a heavy diluted bitumen, just like most other SAGD operators in the area.
The Alberta Government has also partnered with Northwest Refining and Canadian Natural Resources to build a new 50,000 barrels per day bitumen upgrader in Sturgeon County, AB. The Sturgeon Refinery should be operational by the middle of 2018.
|BITUMEN FEEDSTOCK:||Mildred Lake & Aurora North||Base Plant, MacKay River & Firebag||Muskeg River & Jackpine||Horizon Mine||Long Lake SAGD||CNRL Cold Lake & BRIK 4|
|PUG:||carbon rejection + hydroconversion||carbon
|OrCrude + Solvent Deasphalting||LC-Fining|
|SUG:||hydrotreater||hydrotreater||hydrotreater||hydrotreater||hydrocracker||hydrotreater + hydrocracker|
|DETAILS ➜||DETAILS ➜||DETAILS ➜||DETAILS ➜||DETAILS ➜|
THE FUTURE OF UPGRADING: A PARTIAL SOLUTION
There's no question that upgraded synthetic crude is a much better product than heavy diluted bitumen. However, given the growing volumes of light and ultra-light oil being produced from US shale, demand for Canadian light/sweet crude south of the border is limited at best.
Although heavy diluted bitumen has no shortage of customers, the diluent used during transport is very expensive and takes up 30% of pipeline volumes, driving up transportation costs for the shipper and limiting pipeline capacity.
The solution to both problems may lie in partial upgrading, where the quality of the bitumen is improved just enough to reduce or even eliminate diluent needs. The product is still heavy and sour, but good enough to be transported via pipeline, freeing up much needed capacity.
As the viability of full upgrading has diminished, many operators are now asking themselves what is the minimum number of pots and pans required to slightly improve quality and reduce diluent needs, without driving up operating costs. This is likely the future of upgrading in the oil sands.
|WHY UPGRADE? BALANCING BIG BENEFITS VS HEAVY COSTS|