Uploaded April 10, 2014
Last updated February 21, 2015
 

 

For audio of the seven-minute brief, at about 34min 35sec, and for a shorter brief at the end, see:

http://parlvu.parl.gc.ca/PARLVU/ContentEntityDetailView.aspx?contententityid=11532&date=20140401&lang=en

 

 

 

 

 

 

 

 

 

 

            -Sources of Alberta's Oil Reserves;

 

            -Quantity of Alberta's Oil Reserves; and,

 

·           -Valuing Alberta’s Oil Reserves.

 

                     

           -Adding Value; and,

 

           -Infrastructure.

 

 

 

 

Bitumen sands are naturally occurring deposits consisting of bitumen, sand, clay and water that require physical separation after extraction, and further chemical processing of the raw bitumen by upgrading, refining, and petro-chemical processes, in order to manufacture useful and valuable products. Bitumen carbonates contain deposits of bitumen in hard-rock limestone and dolomite (carbonates) that produce no sand.

 

 

 

By convention, all types of crude are called oil when evaluating the recoverable quantity of the resource known as reserves.

 

 

 

 

Alberta enjoys a total original-oil-in-place (OOIP) resource of 2,268 billion bbl (ERCB ST98-2013).

 

Most of it, 1,844 billion bbl, is in bitumen sands (1,270 billion bbl) and bitumen carbonates (574 billion bbl) deposits extending over 54,132 square miles. The remaining 424 billion bbl is conventional light crude in Alberta's tight oil shales and siltstones.

 

This exceeds estimates of 1,300 billion bbl by the United States Geological Survey for Venezuela’s oil resource and 716 billion bbl by OPEC for Saudi Arabia’s oil resource —the other rivals for largest oil resources on earth, combined.

 

 

 

Alberta’s oil reserves are sourced by;

 

Strip-mining shallow bitumen sands deposits:

                 -where 90 percent recovery of OOIP is achieved; but,

                 -only seven percent of the bitumen sands resource is ultimately accessible by strip-mining.

 

In situ extraction of bitumen sands in deeper deposits using:

                 -Cyclic steam stimulation, or CSS);

                            >now achieving recovery factors of 35-40 percent; and

                -Steam-assisted gravity drainage, or SAGD;

                            >typically achieving recovery factors exceeding 50 percent, and sometimes up to 70 percent;

                            >in use only since 2001, the majority of all new in situ projects use SAGD.

 

In situ extraction of bitumen carbonates deposits:

                 -where two successful commercial-scale pilot projects in the Grosmont deposit are now both                                  proceeding to full-scale development;

                           >first applications of horizontal drilling, SAGD and 3-D seismic to bitumen carbonates                                                demonstrated recovery factors comparable to bitumen sands;

                           >carbonate core lab tests indicate SAGD recovery factors of 30 to 60 percent, comparable to

                              bitumen sands lab tests; and by,

 

                -  contain a very large light oil resource little developed as yet;

                -  classed as “proved undeveloped” based on success exploiting analogous tight oil shales in                                 the US.;

                           >apply a nominal ten percent recovery factor.

 

There are some operations producing an extra heavy crude oil, with a density slightly less than fresh water, but nevertheless classed as bitumen because it is produced from within the designated bitumen sands area and requires diluent to be pipelined, under primary production —typically with large quantities of sand.  These operations have recovery factors as low as five percent, and many will doubtless be converted to CSS or SAGD projects having recovery factors many times higher.

 

 

 

 

These recent developments and improvements in recovery factors indicate Alberta’s technically-recoverable, or proved, oil reserves are 848 billion bbl —after deducting six percent shrinkage and deducting 10 billion bbl of cumulative production to year-end 2013.

 

Alberta’s remaining conventional oil reserves of 1.7 billion bbl are tiny in comparison.

 

When compared to similarly-defined “proved” oil reserves of Alberta’s two rivals for largest oil resources and reserves, Alberta’s oil resource and proved reserves are the largest on earth, by far:

Continuing development and application of new technologies, such as fracturing of the formation, adding infill and “wedge” wells, applying steam flooding principles, converting CSS projects to SAGD projects, co-injection of air and solvents, and many other technologies under development, will result in continuing improvements in recovery factors and economics for in situ extraction methods.

The ERCB does not fully recognize actual recovery factors achieved to-date for in situ reserves, does not apply them to the full bitumen sands resource area, recognizes only a token quantity of bitumen carbonate resources as “ultimate potential” reserves -but not as “proved” reserves, and recognizes no proved reserves at all for Alberta’s tight oil shales for which, to be fair, it has not completed evaluation of all prospective formations, but nevertheless already ascribes an in-place resource of 424 billion bbl.

 

     Raw bitumen is valued at average operating costs of $35-$50/bbl.

     Dilbit obtains the benchmark Western Canada Select (WCS) price of $60-75/bbl;

     Upgraded bitumen, or syncrude, obtains the WTI price of $85-$100/bbl and requires no diluent;

     Syncrude and conventional crudes obtain Brent Price of $105-$115/bbl at tidewater other than at US Gulf        Coast refineries and ports;

     Refined products such as gasoline and diesel obtain $200/bbl at retail of $1.25/litre in Canada; and                  U$160/bbl at retail of U$3.80/US gal in the US.

The undiscounted value of Alberta’s 848 billion bbl of “proved” oil reserves at $100/bbl is $84.8 trillion, equivalent to $2.4 million for each and every Canadian, assuming a constant crude price of $100/bbl.

In 2013, the Canadian Association of Petroleum Producers forecasted bitumen production of 5.2 million bbl/d by 2030, up from today’s two million bbl/d.  Total western Canada oil production was forecasted at 6.6 million bbl/d in 2030.

At a constant production rate of 5.2 million bbl/d, Alberta’s technically-recoverable oil reserves sourced from bitumen alone enjoy a remaining reserves life of about 400 years in 2030, providing an undiscounted, potential value of $190 billion/year at a constant crude price of $100/bbl.

However, economic benefits accruing to Canadians as a result of developing the oil and gas industry fall far short of potential due to:

First, foreign ownership of bitumen production:
          -   currently estimated at 50 to 70 percent depending on how foreign ownership is defined and who is doing the tally;
          -   will only increase over time - no limit on foreign corporate investment.

Second, to increasing exports of low value raw bitumen as dilbit:
          -   because all in situ projects produce dilbit, only seven percent of which is upgraded;
          -   the recently-commissioned Imperial/ExxonMobil Kearl and in-development Suncor Fort Hills projects, the first bitumen sands strip-mines without upgraders, together with Imperial/ExxonMobil’s announced Kearl in situ project, will produce a total of 687,000 bbl/d of raw bitumen contained in almost one million bbl/d of dilbit for export;
         -   In 2013, Suncor, cancelled its Voyager upgrader.

Third, to low Alberta bitumen royalties of only one to nine percent until project payout and depending on oil price which can take decades:
          -   in 2012, Alberta produced 1.5 billion bbl of oil equivalent (BOE) and collected $6.13 billion in non-renewable royalties which is only $4/BOE.

Fourth, to Alberta’s subsidy of raw bitumen production, which effectively encourages export of raw bitumen:             -   the cost of diluents reduces royalties for bitumen and extra heavy crude producers;

         -   this disadvantages companies that want to upgrade bitumen; and,
         -   denies Canadians added-value and tax revenues.

And fifth, to high diluent costs:
          -   The cost to purchase diluent on the Gulf Coast at a premium to the West Texas Intermediate (WTI) price, pipeline it to northern Alberta, pipeline it back to the Gulf Coast as dilbit, sell it as dilbit at a discount to WTI, and failure to obtain added-value as upgraded bitumen, exceeds $25 per barrel of bitumen;
          -   three barrels diluent required to pipeline each seven barrels raw bitumen.

          

 

The monetary value of a wide variety of municipal, provincial and federal taxes, business profits, wages (i.e., jobs), shareholder value, and re-investment foregone by exporting raw bitumen as dilbit and not upgrading, refining and otherwise adding value by manufacturing petro-chemicals in Canada, and exporting the finished products, is at least $150/bbl.

Every barrel of raw bitumen exported reduces potential oil and gas revenue by $150, or $55 billion/year for each one million bbl/d of raw bitumen exported, assuming Canadian ownership.

 

 

To maximize the cross-Canada benefits of the oil resource no better means can be found than pipelining partially or fully-upgraded bitumen from land-locked Alberta to safe, environmentally-acceptable refineries and marine terminals on the East and West Coasts.  Along the way, Canadians in Fort McMurray, Edmonton, Sarnia, Montreal, Saint John, Canso and Vancouver will have the opportunity to upgrade, refine, and produce petro-chemicals for domestic use or for export and to export all remaining partially- or fully-upgraded bitumen.

 

          -   Ship 2.2 million bbl/d of light, medium and heavy conventional crudes, syncrude, partially upgraded bitumen, and raw bitumen in dilbit to Eastern Canada and Atlantic Canada marine terminals:
                    >  Create major pipeline hub near Montreal, PQ;
                    >  Supply Montreal refineries and petro-chemical industries;
                    >  Supply refinery and marine terminal at Levis, PQ;
                    >  Supply an expanded Irving refinery at Saint John, NB;
                    >  Start-up major petro-chemical industry in Saint John, NB;
                    >  Export refined products and petro-chemicals to US Eastern Seaboard, and Latin/South America                                 from Canaport, NB marine terminal;
                    >  Extension to Canso, NS Superport to export upgraded bitumen to Europe and India via Suez and                               Cape of Good Hope using the largest marine tankers;
                    >  Option to reverse Portland, ME to Montreal, PQ pipelines to export refined products and crude;
                    >  Option to supply Sarnia, ON upgrading, refining and petro-chemical complex from Montreal, PQ                                 pipeline hub.
                    >  Energy East Line 2 helps make Northern Gateway and Keystone XL unnecessary until 2028, and                               perhaps forever.

TransMountain Pipeline Expansion

 

          -   Ship additional 590,000 bbl/d of light, medium and heavy conventional crudes, syncrude, partially                         upgraded bitumen, and raw bitumen in dilbit to relocated marine terminal at Tsawwassen, BC;

                    >  Eliminates: pipeline construction in densely populated Burnaby, BC; expansion of tank farm on                              Burnaby Mtn. and expansion of existing Westridge marine terminal;
                    >  Eliminates all tanker traffic underneath Second Narrows bridges and Lions Gate bridge, through                          Vancouver’s inner and central harbours, past Stanley Park, in Burrard Inlet and much of the                                    Salish Sea;
                    >  Eliminates two major pipeline crossings of the Fraser River;
                    >  Use proceeds of sale of BC Ferries’ Tsawwassen terminal to Kinder Morgan to build a new ferry                          terminal near the Vancouver airport, reducing overall transit times to Islands by half and                                          rationalizing BC Ferries’ fleet;
                    >  Tsawwassen marine terminal allows loading of the largest marine tankers reducing additional                            Salish Sea traffic by three-quarters;
                    >  Provides option to re-locate Chevron refinery to Tsawwassen/Delta and expanding it to world-                                class environmental standards per Irving Saint John refinery to meet all of the Lower Mainland’s                          and Islands’ petroleum needs;

                    > Requires a world-class spill-response centre with trained personnel, vessels, aircraft,                                              specialized  equipment, supplies, centralized communications and command - all available                                  24/7, as well as on-going training, research and development, to effectively respond to the                                      largest spill in the Salish Sea within one hour.  Fully funded by the federal government, the                                      province of Alberta, oil producers, oil shippers, the pipeline company, oil owners, and marine                                tanker owners.

                    >  Requires a committment by the province of Alberta to gradually phase out the volumes of dilbit                                     being transported to the west coast for export.

 

 

          -Plans to build 550,000 to 800,000 bbl/d of rail terminals in Alberta within two or three years replaces                    volume of a denied Keystone XL.
                   >  Shipping raw bitumen, syncrude, and conventional crudes is very cost competitive to shipping                               dilbit by pipeline, and provides greater marketing flexibility and freedom from long-term contracts;
                   >  Much safer than shipping highly-volatile crude responsible for Lac-Megantic disaster and safer                             than rail shipment of dilbit due to volatile, toxic nature of diluents;
                   >  Constrained by lack of suitable rail cars and capacity of safe trackage;

          -On-going and planned expansions increase capacity by 350,000  bbl/d.
                   >  Supply Sarnia complex and Montreal pipeline hub via Line 9 reversal.

          -Limited to 300,000 bbl/d due to physical limitations of existing pipe; 
                   >  Probably unnecessary with Energy East Line 2;
                   >  Removes one of two independent, competitive sources of crude supply for Sarnia complex and                             Nanticoke, ON refinery;
                   >  Sarnia complex and Nanticoke, ON refinery to be supplied entirely by crude supplies transported                           through a foreign ountry.

 

In Conclusion

          -Alberta’s crude oil resource and “proved” reserves are the largest on Earth, by far.

          -Increasing exports of low-value dilbit, high foreign ownership, costs of diluent, low bitumen royalties before project payout, subsidies for exports of dilbit, and lack of upgrading, refining and petro-chemical opportunities results in failure to capture more than a small fraction of the potential economic benefits of the largest oil reserves on earth.

          -New pipelines connected to bitumen upgraders in Alberta, and to upgraders, refineries and marine terminals on Canada’s East and West Coasts, maximize the cross-Canada value of the largest oil reserves on Earth, provide energy security, and by adding four million bbl/d of capacity, together with new crude rail terminals, make low value export pipelines such as Keystone XL and Northern Gateway unnecessary until at least 2025.

 

 

The bitumen sands “established” reserves are estimated by the ERCB as 167 billion bbl but are incorrectly widely regarded as “proved” reserves.

“Established” reserves are a restricted sub-class of “proved” reserves.

The ERCB defines “established” reserves as “…those reserves recoverable under current technology and present and anticipated economic conditions, specifically proved by drilling, testing, or production, plus that judgment portion of contiguous recoverable reserves that are interpreted to exist, from geological,            geophysical or similar information, with reasonable certainty.”

The ERCB states it uses the Inter-Provincial Advisory Committee on Energy (IPACE) system altered  “…to more fully report the resource endowment of Alberta.”, i.e., crude bitumen.

“Proved” reserves definitions as approved by the Board of Directors of the Society of Petroleum Engineers and the Executive Board of the World Petroleum Council in 1997 are as follows:
          -Reserves are considered proved if commercial producibility of the reservoir is supported by production or formation tests.
          -The area of the reservoir considered proved includes undrilled areas that can be reasonably judged as commercially productive on the basis of available geologic and engineering data.
          -Reserves are considered proved undeveloped if there is a reasonable expectation that facilities to process and transport those reserves will be installed.
          -Reserves are considered proved undeveloped where there is reasonable certainty the objective formation is laterally continuous and contains commercially recoverable petroleum at locations beyond direct offsets.
         -Reserves to be produced through application of established enhanced recovery methods are considered proved when successful pilot tests provide support.

The bitumen sands and carbonate deposits meet all of the above definitions for “proved” reserves throughout each deposit’s area.  The ERCB used cut-offs of thickness, mass saturation in the bitumen sands and porosity in the bitumen carbonates to eliminate areas of non-commercial/non-producible reserves from OOIP calculations.

         -Reserves to be produced through application of established enhanced recovery methods are considered proved when there is a favourable response in an analogous reservoir with similar rock and fluid properties that provides support.

Alberta’s tight oil shales meet this definition of proved reserves based on highly-successful enhanced recovery from several US tight oil formations (Bakken, Eagle Ford, Marcellus, etc.).

Bitumen “ultimate potential” reserves are estimated by the ERCB as 315 billion bbl.

 

Author Bio

"Mike Priaro, B.Eng.Sc. (Chem. Eng.), U.W.O. '76, P.Eng., Lifetime Member of Association of Professional Engineers and Geoscientists of Alberta (APEGA), worked in facilities, production, operations and reservoir engineering, as engineering consultant, area superintendent, and engineering management in Alberta's oil patch for 25 years for companies such as Amoco and PetroCanada.

Mike increased oil production from the historic Turner Valley oilfield and brought in under-balanced drilling technology to drill out, complete and test several of the highest producing gas wells ever on mainland Canada at Ladyfern.  He co-authored Advanced Fracturing Fluids Improve Well Economics in Schlumberger's Oilfield Review and developed the course material for the Advanced Production Engineering course at Southern Alberta Institute of Technology.”

“Mike has presented his work to Canada’s House Committee on Natural Resources in Ottawa and had work published by the Macdonald-Laurier Institute in the March and April, 2014 and February, 2015 editions of Inside Policy magazine, by U.S. energy industry websites such as RBN Energy, in the July 17, 2014 edition of the Oil and Gas Journal, and in Petroleum Technology Quarterly, Q3 2014.”

Mike has no formal connection to any oil company, environmental organization, think tank, labour organization, lobbying or special interest group, academia, or to provincial or federal politics."  However, Mike has been recently retained by Alberta Sulphur Research Limited to help promote its new partial upgrading process.

"Mike is author of A ‘Canada-First’ Canadian Energy Strategy (see https://www.behance.net/portfolio/editor?project_id=5808629 ) and is available for special projects and speaking engagements."