Relevant • Independent • Objecve CERI Commodity Report – Crude Oil Editorial Commiee: Paul Kralovic, Dinara Millington, Megan Murphy, Allan Fogwill About CERI The Canadian Energy Research Instute is an independent, not-for-profit research establishment created through a partnership of industry, academia, and government in 1975. Our mission is to provide relevant, independent, objecve economic research in energy and related environmental issues. For more informaon about CERI, please visit our website at www.ceri.ca or contact us at [email protected]. supply cost of and Alberta oil sands in situ project is higher than market price for bitumen. Another concern that arises from significant energy use is the accompanying emissions and their impact on the environment. The Federal Government of Canada as well as provincial governments are working to address the GHG issue. Recently, the province of Alberta implemented a new Climate Change Leadership plan that fixed total oil sands emissions at a cap of 100 megatonnes (Mt) of CO2eq per year and increased the carbon tax to $30/tonne of CO2 eq. to be applied to oil sands facilies. Those constraints add an incremental cost (carbon tax and investment to migate emissions) on the already costly oil sands projects. On their own accord, the oil industry has commied to reduce the use of freshwater by 50 percent by 2022 in the in situ extracon, and a reducon of 30 percent of the water take from Athabasca river by 2022 in the oil mining extracon. To address these challenges, industry is exploring other technological opons in conjuncon with improving the exisng SAGD process. For some years now, project proponents have been tesng adding solvent to the steam. This arcle provides an overview of what has been taking place in this technology development. The in situ solvent assisted extracon process consists of using a combinaon of solvent and steam or pure solvent as a replacement of steam to heat the oil deposit in the reservoir and reduce its viscosity causing heated oil to drain into the lower wellbore. Three different in situ solvent based extracon methods are discussed below: Steam solvent hybrid is characterized by co-injecon of steam and solvent; the proporon of a solvent is far less than the volume of steam injected around 10-20 percent. The injecon of a combinaon of hydrocarbon-based solvent (C4-C12) and steam will condense and evaporate at the same temperature as water and will reduce the viscosity of bitumen. Are Solvents the New Holy Grail for Alberta’s Oil Sands? Update on the Use of Solvents in SAGD Alpha Sow The majority of Alberta oil sands reserves (approximately 80 percent) is buried too deep to be recovered by open- pit mining, and are recoverable using in situ methods. The story of in situ bitumen development began in the 1960s, when Imperial Oil Ltd. built a test project to extract bitumen from Cold Lake deposits. This involved injecng steam under high pressure into the oil sand formaon. Once the bitumen was heated by steam and inclined to flow, it could be pumped to the surface. This technique became known as CSS or Cyclic Steam Smulaon. But technological development connued. One key collaboraon of the Alberta government, industry and academia was the Underground Test Facility near Fort McMurray, which demonstrated the value of horizontal wells for in situ bitumen producon. This research led to the development of a new technology known as SAGD or Steam Assisted Gravity Drainage, widely used by industry today. SAGD consists of a pair of horizontal wells, situated 4 to 6 meters above one another, drilled from a central well pad. In a plant nearby, water is transformed into steam by use of natural gas-fired boilers which then travels through above-ground pipelines to the wells and enters the ground via a steam injecon (top) well (Alberta Energy). The SAGD process has been constantly improving since 1987 (see Figure 1). The energy-intensity factor affects the future of Alberta oil sands growth because a highly energy-intensive extracon method can be costly and limits Alberta oil sands compeveness in the internaonal market, especially in today’s low oil price environment. The June 2016 CERI Commodity Report — Crude Oil
Transcript
Relevant • Independent • Objective
CERI Commodity Report – Crude Oil Editorial Committee: Paul Kralovic, Dinara Millington, Megan Murphy, Allan Fogwill About CERI The Canadian Energy Research Institute is an independent, not-for-profit research establishment created through a partnership of industry, academia, and government in 1975. Our mission is to provide relevant, independent, objective economic research in energy and related environmental issues. For more information about CERI, please visit our website at www.ceri.ca or contact us at [email protected].
supply cost of and Alberta oil sands in situ project is higher than market price for bitumen. Another concern that arises from significant energy use is the accompanying emissions and their impact on the environment. The Federal Government of Canada as well as provincial governments are working to address the GHG issue. Recently, the province of Alberta implemented a new Climate Change Leadership plan that fixed total oil sands emissions at a cap of 100 megatonnes (Mt) of CO2eq per year and increased the carbon tax to $30/tonne of CO2 eq. to be applied to oil sands facilities. Those constraints add an incremental cost (carbon tax and investment to mitigate emissions) on the already costly oil sands projects. On their own accord, the oil industry has committed to reduce the use of freshwater by 50 percent by 2022 in the in situ extraction, and a reduction of 30 percent of the water take from Athabasca river by 2022 in the oil mining extraction. To address these challenges, industry is exploring other technological options in conjunction with improving the existing SAGD process. For some years now, project proponents have been testing adding solvent to the steam. This article provides an overview of what has been taking place in this technology development. The in situ solvent assisted extraction process consists of using a combination of solvent and steam or pure solvent as a replacement of steam to heat the oil deposit in the reservoir and reduce its viscosity causing heated oil to drain into the lower wellbore. Three different in situ solvent based extraction methods are discussed below: Steam solvent hybrid is characterized by co-injection of steam and solvent; the proportion of a solvent is far less than the volume of steam injected around 10-20 percent. The injection of a combination of hydrocarbon-based solvent (C4-C12) and steam will condense and evaporate at the same temperature as water and will reduce the viscosity of bitumen.
Are Solvents the New Holy Grail for Alberta’s Oil Sands? Update on the Use of Solvents in SAGD Alpha Sow The majority of Alberta oil sands reserves (approximately 80 percent) is buried too deep to be recovered by open-pit mining, and are recoverable using in situ methods. The story of in situ bitumen development began in the 1960s, when Imperial Oil Ltd. built a test project to extract bitumen from Cold Lake deposits. This involved injecting steam under high pressure into the oil sand formation. Once the bitumen was heated by steam and inclined to flow, it could be pumped to the surface. This technique became known as CSS or Cyclic Steam Stimulation. But technological development continued. One key collaboration of the Alberta government, industry and academia was the Underground Test Facility near Fort McMurray, which demonstrated the value of horizontal wells for in situ bitumen production. This research led to the development of a new technology known as SAGD or Steam Assisted Gravity Drainage, widely used by industry today. SAGD consists of a pair of horizontal wells, situated 4 to 6 meters above one another, drilled from a central well pad. In a plant nearby, water is transformed into steam by use of natural gas-fired boilers which then travels through above-ground pipelines to the wells and enters the ground via a steam injection (top) well (Alberta Energy). The SAGD process has been constantly improving since 1987 (see Figure 1). The energy-intensity factor affects the future of Alberta oil sands growth because a highly energy-intensive extraction method can be costly and limits Alberta oil sands competitiveness in the international market, especially in today’s low oil price environment. The
June 2016
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Pure solvent on the other hand involves injecting pure solvent vapors that diffuse through the reservoir producing less viscous bitumen that flows down to the production reservoir by gravity. That process produces a higher oil recovery factor. Steam additives process or surfactant additive process consists of injecting a small quantity of surfactant and steam to enhance the oil recovery. The process involves a molecular interfacial tension reduction and can be applied between two liquids or between a liquid and a solid.1 They are known for their detergents, wetting agents, emulsifiers, foaming and dispersant agents and are commonly used in oil sands mining. Some of these processes show promising performance by reducing energy and GHG intensity and improving oil recovery. The ES-SAGD tested by Encana Senlac showed a 50 percent improvement in oil recovery rate and a 150 percent recovery rate in Christina Lake (Gupta 2005). Cenovus, on the other hand, has developed the solvent aided process (SAP) that adds natural gas liquids to the steam resulting in a reduction of the Steam-Oil Ratio (SOR) of 30 percent. Liquid addition to steam for enhancing recovery (LASER) developed by Imperial Oil
adds a solvent (C5+ condensate) to mid-life cycle steam in existing CSS wells and showed a reduction in GHG emissions by more than 25 percent. The VAPEX process is composed of low hydrocarbons such as propane, methane and butane or a combination thereof. Testing of the technology is still ongoing as hot VAPEX looks promising. The challenge is to improve in solvent recovery. Cyclic Solvent Process (CSP) is another process developed by Imperial Oil at their Cold Lake site in 2009 and has been incorporated in the operating facilities since June 2014. Economic Analysis of In Situ Based Solvent Extraction The main challenge of hydrocarbon solvent addition is the cost of solvent and the solvent recovery factor (solvent retained in the reservoir/solvent injected). Most of the solvents used are oil derivatives (small hydrocarbons such as propane and butane, etc.), with their price linked directly or indirectly to oil price. As the oil price starts to recover, it is expected that the prices of oil derivatives will too. The recent experimentation shows major challenges of engineering solvent addition processes. Operation teams
Figure 1: Technology Innovation Chronology of Oil Sands In Situ Extraction
Source: CERI; Laricina Energy with CAPP production data
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are facing a large numbers of possible recipes, combined with the poorly understood and unpredictable nature of solvent effects. Solving this problem will be the main factor for in situ solvent-based extraction adoption and its economic viability. Numerous numeric simulations and experiments are developed by R&D divisions at oil companies and universities to improve the understanding of how solvent flows in the reservoir and how to match the reservoir characteristics variability and solvent during the life cycle of the extraction. In most cases there is no linearity and limited learning opportunity from the previous injection. Laricina Energy is working on a comprehensive method that matches the economic and chemical constraints, called Genetic Algorithm (GA). It is an eleven-step process that constantly optimizes the real time match between reservoir properties and solvent composition and volume.
Compliances and Environmental Risk The environmental aspect of in situ solvent-based extraction is not well known; there is possible contamination of underground water and how to avoid it is not scientifically established. There is no policy or specific regulation about solvent use in the industry, all solvent-based projects are in the experimental project regulation stage. If the solvent-based methods for in situ extraction are adopted on a commercial scale, the regulation will evolve and new requirements will be added to the current in situ extraction compliances. The industry will have to manage this new “underground tailing”. How long and what will be an acceptable level of the chemical components of the waste allowed will need to be studied extensively. It is also not clear who will carry the risk in the long run, as new regulations will be adopted and fall somewhere between tailings management and actual regulation and well remediation.
Table 1: Examples of In Situ Solvent Technology
Steam Solvent Hybrid Pure Solvent Steam Additives Process
Liquid Addition to Steam to Enhance Recovery LASER
Source: CERI
Table 2: Comparison of Key Performance Factors
Technology Type Test Field Year Oil Production Im-provement
SOR Reduction Solvent Recovery
GHG Intensity
SAP Cenovus (Encana) Senlac
2002 50% 2.5 to 1.5 NA NA
SAP Cenovus Christi-na Lake
2004 150% 5 to 1.5 NA NA
LASER (C5+ con-densate)
Imperial Oil Cold Lake
2002/2009 + 30% NA 80% 25%
ES-SAGD Nexen Long Lake +50% -40% More GHG SAGD plant
N-Solv Suncor Dover Lease
2013 NA -100% 50 to 70% -80%
Additive (LITE)
Suncor Mackay River
Laboratory stage and proof of concept but no field test release publicly available data
Source: CERI
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To conclude, Figure 1 shows improvement in bitumen production as far as technologies and processes are concerned. Since the beginning, Alberta oil sands have been a challenging area to develop, but by constant innovation and continuous improvement oil producers have been overcoming these challenges. Many solvent-based extraction technologies are under development and most of the pilot plants show interesting results. Solvent recovery is the major challenge; improvements in imaging technologies, data analytics and numeric simulation, cheap and reliable sensors, new proactive innovation, ecosystem and carbon regulations are all likely to accelerate these technologies’ maturations. The goal is to decarbonize oil sands production, use less water and extract bitumen at competitive costs. Endnote 1Subodh Chandra Gupta /Khalil Zeidani (Cenovus Energy): surfactant steam process: An innovative Enhanced Heavy Oil Recovery Method for Thermal applications. Bibliography 1. http://www.spe.org/events/sio/2014/pages/
Figure A.1 describes the efficiency of different hydrocarbon solvents mixed with steam. All hybrid solvent steam configurations perform better than simple steam, the higher the hydrocarbon (i.e., more carbon atoms in the molecule) the better the performance. The exception is octane (C8H18) which performs slightly less than hexane (C6H14) because of its molecular structure. Figure A.2 shows a numeric simulation of a thermodynamic reaction in the reservoir after injecting solvent. The reaction leads to a movement of oil and solvent mixture from the injection well to the production well. Figure A.3 illustrates steam chamber growth after the injection of steam and propane. This solvent heat-assisted recovery process shows the reflux of propane in the reservoir mobilizing bitumen.
A1: Historic Light Sweet Crude Futures Prices ($US per barrel)
A2: Historic Crude Product Futures Prices (¢US per gallon)
Notes (Tables A1 and A2): Prices are listed by contract month. Close: final contract close on the last day of trading. Last 3 Day Average Close: simple average con-
tract close on last three days of trading. Average When Near Month: simple average closing price on trading days when contract was near month. 12-Month Strip
Average: simple average of daily near 12-month contract closing prices in a given contract month. Spread: difference between one-month and two-month forward
prices in a given period. Source: New York Mercantile Exchange (NYMEX).
NYMEX Light Sweet Crude
Last 3 Day Avg. When 12-Month Spread
Close Average Near Mo. Strip Avg. (1-2 Mo.)
2013 96.82 97.37 97.01 97.45 -0.12
2014 96.53 96.37 96.73 87.56 0.54
2015 49.68 49.80 51.41 53.75 -0.78
2Q 2015 53.32 53.04 52.84 56.55 -1.51
3Q 2015 50.39 50.63 53.14 54.10 -0.42
4Q 2015 43.92 44.17 44.89 47.38 -0.70
1Q 2016 30.92 31.19 34.29 38.10 -1.44
2Q 2016 43.94 43.15 40.39 43.31 -1.24
Yr-on-Yr Chg. -17.6% -18.6% -23.6% -23.4%
Jul-15 59.68 59.91 59.63 61.11 -0.41
Aug-15 50.36 50.47 54.66 53.70 -0.36
Sep-15 41.14 41.52 45.12 47.50 -0.49
Oct-15 45.83 45.73 44.47 46.73 -0.57
Nov-15 45.55 46.23 46.32 48.55 -0.51
Dec-15 40.39 40.56 43.88 46.86 -1.03
Jan-16 34.74 34.81 38.61 42.22 -1.39
Feb-16 26.55 28.14 33.74 36.96 -1.10
Mar-16 31.48 30.63 30.52 35.13 -1.83
Apr-16 41.45 40.27 36.44 40.15 -1.69
May-16 42.63 41.16 39.32 42.33 -1.30
Jun-16 47.75 48.03 45.43 47.45 -0.72
Jul-16 48.85 48.73 49.03 50.88 -0.55
Yr-on-Yr Chg. -18.1% -18.7% -17.8% -16.7%
NYMEX Unleaded Gasoline NYMEX Heating Oil
Last 3 Day Avg. When 12-Month Spread Last 3 Day Avg. When 12-Month Spread
Close Average Near Mo. Strip Avg. (1-2 Mo.) Close Average Near Mo. Strip Avg. (1-2 Mo.)
A3: World Crude Oil Contract Prices (FOB, $US per barrel)
A4: North American Posted Crude Prices (FOB, $US per barrel)
Notes: 1. ANS is Delivered price on US West Coast. 2. Edmonton Light Sweet prices are discontinued as of May 1, 2014 and replaced by the Canadian Light Crude
blend which is traded daily on the Net Energy Index. 3. Hardisty Heavy. Posted prices are based on price at the end of each month. Sources: Oil & Gas Journal;
Natural Resources Canada.
Notes: 1. Urals is Delivered price at Mediterranean. Contract prices are based on prices at the end of each month. Source: OPEC Monthly Oil Market Report.
Saudi U.A.E. Oman U.K. Norway Russia Venez. Kuwait Ecuador Mexico Nigeria Indon.
Arab Lgt Dubai Oman Brent Ekofisk Urals1 T.J. Light Blend Oriente Isthmus Bonny Lgt Minas
A5: Crude Oil Quality Differentials (FOB, $US per barrel)
A6: Crude Oil Spot Prices and Differentials (FOB, $US per barrel)
Notes: 1. OPEC-Reference Basket is average price of seven crude streams: Algeria Saharan Blend, Dubai Fateh, Indonesia Minas, Mexico Isthmus, Nigeria Bonny
Light, Saudi Arabia Light and Venezuela Tia Juana Light. Source: OPEC Monthly Oil Market Report.
Notes: 1. Edmonton Light Sweet prices are discontinued as of May 1, 2014 and replaced by the Canadian Light Crude blend which is traded daily on the Net Energy Index. 2. Hardisty Heavy. Based on contract prices at the end of each month. Sources: OPEC Monthly Oil Market Report: Oil & Gas Journal; Natural Resources Canada.
A7: World Petroleum Product Spot Prices ($US per barrel)
A8: Product Spot Prices in Selected American Cities (¢US per gallon)
Notes: 1. Reformulated regular unleaded gasoline. Spot prices are based on average daily prices over a specific timeframe. Source: EIA Weekly Petroleum Status
Report.
Notes: 1. Regular unleaded gasoline. 2. Waterborne 3. High Sulfur (3.5-4.0%) Residual Fuel Oil. Spot prices are based on average daily prices over a specific timeframe. Source: IEA Oil Market Report.
US Gulf Coast, Pipeline Rotterdam, Barges Singapore, Cargoes
B1: World Petroleum Supply and Demand Balance (million barrels per day)
Notes: 1. Totals for OECD and non-OECD supply include net refining gains; specific regions/groupings within each do not. 2. OPEC demand is an estimate based on
historical annual data. 3. Balance for World equals global stockbuilds (+) and stockdraws (-) for crude oil and petroleum products and miscellaneous gains and loss-
es. Regional surpluses (+) and deficits (-) are balanced through net-imports and stock changes in the short-term, and net-imports in the longer term. Supply includes
crude oil, condensates, NGLs, oil from non-conventional sources and processing gains. Demand is for petroleum products.
Source: IEA Oil Market Report.
OECD Non-OECD OPEC World
Americas Europe Asia Ocean. Total1 Asia Non-Asia FSU Total1 P. Gulf Non-Gulf Total2 Total3
Notes: 1. Production includes crude oil, condensates and NGLs. 2. Reserve-Production ratio is based on latest month production and British Petroleum reserve
estimates. Sources: IEA Oil Market Report and BP Statistical Review of World Energy.
Notes: 1. Product includes only finished petroleum products. 2. Total stocks include NGLs, refinery feedstocks, additives/oxygenates and other hydrocarbons. All
stocks are closing levels for respective reporting period. Source: IEA Oil Market Report.
OECD Non-OECD OPEC World
Americas Europe Asia Oc. Total Asia Non-Asia FSU Total P. Gulf Non-Gulf Total Total1
B4: OPEC Crude Oil Production and Targets (million barrels per day)
Notes: 1. Does not include NGLs; OPEC production targets apply to crude oil only. 2. Iraq does not have an official OPEC target. Source: IEA Oil Market Report.
Notes: 1. Based on dated Brent being processed in average US Gulf cracking refinery. 2. Based on dated Brent in average Rotterdam cracking refinery. 3. Based on
spot Dubai in average Singapore hydroskimming refinery. Source: IEA Oil Market Report.
C1: US Petroleum Supply and Demand Balance (million barrels per day)
Notes: 1. Does not balance because of unaccounted for crude oil. Regional surpluses (+) and deficits (-) are balanced through net-imports/transfers and stock chang-
es in the short-term, and net-imports/transfers in the longer term. 2. As of most recent month. Supply includes crude oil, condensates, NGLs, oil from non-
conventional sources and processing gains. Demand is for petroleum products. Source: EIA Petroleum Supply Monthly.
C2: US Petroleum Demand by Product (million barrels per day)
Notes: 1. Total includes other finished petroleum products. 2. Total petroleum demand includes refinery feedstocks, additives/oxygenates and other hydrocarbons.
Source: EIA Petroleum Supply Monthly.
C3: US Petroleum Stocks (million barrels)
Notes: 1. Petroleum stocks include crude oil, finished products, NGLs, refinery feedstocks, additives/oxygenates and other hydrocarbons. 2. Includes Strategic
Petroleum Reserves. 3. Total includes other finished petroleum products. All stocks are closing levels for respective reporting period. Source: EIA Petroleum Supply
Monthly.
Finished Petroleum Products NGLs Petroleum
Gasoline Jet Fuel Distil. Resid. Total1 Total Total2
C4: US Petroleum Net Imports by Source (million barrels per day)
Notes: 1. Total includes net-imports from Russia and Asia-Pacific region. 2. Total OPEC includes the other eight cartel members. 3. As of latest month. Source EIA
Petroleum Supply Monthly.
C5: US Regional Crude Oil Production (million barrels per day)
Notes: 1. California includes Federal Offshore crude oil production. 2. Gulf of Mexico includes Federal Offshore production adjacent to Texas and Louisiana. 3. Crude
oil Reserve-Production ratio as of latest production month. Crude oil production does not include NGLs. Source: EIA Petroleum Supply Monthly.
OPEC
Canada Mexico Lat. Am. Europe Africa M.E. Total1 Venez. S. Arabia Nigeria Total2 P. Gulf
C6: US Refinery Activity Crude Input (MMbpd) - Utilization (percent)
Notes: 1) As of most recent month. Source: EIA Petroleum Supply Monthly.
C7: US Refinery Margins ($US per barrel)
Note: Based on specific crude being processed in average cracking refinery in a given area. As of February 2010, NY Harbor Arab Med. is now East Coast Composite.
D1: Canada Petroleum Supply and Demand Balances (million barrels per day)
D2: Canada Demand by Product (million barrels per day)
Notes: 1. As of most recent month. See notes for Table C1 for additional comments. Source: Statistics Canada’s Energy Statistics Handbook.
D3: Canada Petroleum Stocks (million barrels)
Notes: 1. Total includes other finished petroleum products. 2. Total petroleum demand includes refinery feedstocks, additives/oxygenates and other hydrocarbons. Source: Statistics Canada’s Energy Statistics Handbook.
Notes: 1. Total includes other finished petroleum products. 2. Total petroleum stocks include NGLs, refinery feedstocks, additives/oxygenates and other hydrocarbons. All stocks are closing levels. Source: Statistics Canada’s Energy Statistics Handbook.
D4: Canada Crude Oil Production (million barrels per day)
Note: Total includes small amounts of production from Manitoba and Ontario. Source: Statistics Canada’s Energy Statistics Handbook.
D5: Canada Petroleum Imports by Source (thousand barrels per day)
Notes: 1. Includes all non-OPEC production. 2. Includes production by the other seven OPEC members. 3. As of most recent month. Sources: Statistics Canada’s
Energy Statistics Handbook.
Non-OPEC OPEC Imports
Mexico U.S. U.K. Norway Total1 Algeria Nigeria S. Arabia Venez. Total2 P. Gulf Total
1. The World: OECD is comprised of countries from three regions: North America (Canada, Mexico, US); Europe (Austria, Belgium, Czech Republ ic,
Denmark, Finland, France, Germany, Greece, Hungary, Iceland, Ireland, Italy, Luxembourg, the Netherlands, Norway, Poland, Portugal, the Slovak
Republic, Spain, Sweden, Switzerland, Turkey, UK); and Asia-Pacific (Australia, Japan, New Zealand, South Korea). OPEC is comprised of Persian Gulf (Iran,
Iraq, Kuwait, Qatar, Saudi Arabia, United Arab Emirates) and non-Persian Gulf countries (Algeria, Indonesia, Libya, Nigeria, Venezuela). Non-OECD is
comprised of countries from three regions: Former Soviet Union (Armenia, Azerbaijan, Belarus, Georgia, Kazakhstan, Kirghizstan, Moldova, Russia,
Tajikistan, Turkmenistan, Ukraine, Uzbekistan); Asia (including non-OECD
Oceania); and non-Asia (Africa, Middle East, Latin America, and non-
OECD Europe). 2. United States: East (PADD I) – New England
(Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island,
Vermont); Central Atlantic (Delaware, Maryland, New Jersey, New York,
Pennsylvania, and the District of Columbia) and Lower Atlantic (Florida,
Georgia, North Carolina, South Carolina, Virginia, and West Virginia). Mid
3. Canada: East is comprised of Ontario, Manitoba, Quebec and the
Maritime provinces (New Brunswick, Newfoundland and Labrador, Nova
Scotia, and Prince Edward Island). West is comprised of Alberta, British
Columbia, Saskatchewan and the northern territories (NorthWest
Territories, Nunavuut, and Yukon).
Additional Notes
1. Petroleum and oil refer to crude oil and natural gas liquids (NGLs),
whereas crude oil refers to its namesake and field condensates.
Condensates derived from natural gas processing plants are classified as
NGLs. 2. The spot price is for immediate delivery of crude oil or refined
products at a specific location. Spot transactions are generally on a cargo
by cargo basis. In contrast, a futures price is for delivery of a specified
quantity of a commodity at a specified time and place in the future. 3.
Crude oil sold Free-On-Board (FOB) is made available to the buyer at the
loading port at a particular time, with transportation and insurance the
responsibility of the buyer. Crude oil sold Cost-Insurance-Freight (CIF) is
priced at a major destination point, with the seller responsible for the
transportation and insurance to that point. A “Delivered” transaction is
similar to a CIF transaction, except the buyer in the former pays based on the quantity and quality ascertained at the unloading port, whereas in a CIF
transaction, the buyer accepts the quantity and quality as determined at the loading port. 4. Processing gain is the volume of which refinery output is
greater than crude oil inputs. The difference is due to the processing of crude oil products, which in total have a lower specific gravity than crude oil. 5.
Unaccounted for crude oil reconciles the difference between crude input to refineries and the sum of domestic production, net imports/exports, stock
changes and documented losses (in the U.S.). 6. Totals may not equal the sum of their parts in the statistical tables due to rounding.
Crude Stream
Producing
Country or
Region
API
Gravity
(@60° F)
Sulfur
Content
(%)
BBLs/Metric
Tonne
Tapis Blend Malaysia 44 0.1 7.910
Ekofisk Blend Norway 43 0.2 7.773
WTI Texas 40 0.3 7.640
GCS Gulf of Mexico 40 0.3 7.640
Oklahoma Sweet Oklahoma 40 0.3 7.640
Kansas Sweet Kansas 40 0.4 7.640
Wyoming Sweet Wyoming 40 0.2 7.640
ELS Alberta 40 0.5 7.640
Brent Blend United kingdom 38 0.8 7.551
Bonny Light Nigeria 37 0.1 7.506
Oman Blend Oman 36 0.8 7.462
Arabian Light Saudi Arabia 34 1.8 7.373
Minas Indonesia 34 0.1 7.373
Isthmus Mexico 34 1.5 7.373
Michigan Sour Michigan 34 1.7 7.373
WTS Texas 33 1.7 7.328
Urals Russia 32 1.7 7.284
Tia Juana Light Venezuela 32 1.2 7.284
Dubai U.A.E. 31 1.7 7.239
Lost Hills California 30 0.6 7.194
Cano Limon Colombia 28 0.6 7.105
Arabian Heavy Saudi Arabia 27 2.8 7.061
ANS Alaska 27 1.1 7.061
Oriente Ecuador 25 1.4 6.971
Hardisty Heavy Alberta 25 2.1 6.971
Maya Mexico 22 3.3 6.838
Kern River California 13 1.0 6.436
Crude Oil Qualities
For more information, please contact Dinara Millington at [email protected]. Canadian Energy Research Institute 150, 3512 – 33 Street NW Calgary, AB T2L 2A6
