Production from SAGD sites takes time. Many SAGD projects expect to be producing about 30,000 bpd. However, the formation must be steamed for about six months before any production is achieved. When bitumen production does commence, it rarely is at or near the target volume for the facility. Thereafter, production often grows quite slowly. In many cases, target production volume is achieved, but only after several years. The problem is that the SAGD owners(s) must commit to pipeline capacity, at or near the start of the project, not knowing if they will ever reach (or exceed) the target production volume. Because pipeline capacity is a “take-or-pay” commitment, the effective toll for moving small volumes during the first few years on a pipeline with excess contracted capacity is high.
Currently, producers employ trucks to mitigate the start-up production risk and its toll effect: truck initial production to a terminal where it can be aggregated into larger volumes and blended it with other oils to make a marketable product like Lloyd blend or Western Canada Select or truck bitumen to an existing upgrader like Suncor.
To mitigate the production risk, producers often employ large trucks (in particular “Super B”s: GVW 138,000 lbs or 62,500 kg) to carry barrels to a terminal. Even with these large trucks, this is a very expensive transportation solution because the load size is relatively small (240 bbls per load) when compared to the pipeline batch sizes (60,000 bbls) or railroad cars (600 bbls per car: 70,000 to 87,500 bbls per train). Further, truck operating costs are higher than most alternatives. Notwithstanding these limitations, this transportation solution is effective when moving production short distances, but it fails to be effective when the production volume grows and the distances are greater than a few hundred miles.
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Much work has been done on the costs of building new upgraders in Alberta. Fundamentally, the cost of an upgrader is a function of the upgrader’s capital cost and variable cost less shrinkage. For example, if the cost of a 100,000 bpd upgrader is $5 Billion and the cost of capital is 13% and the availability of the upgrader is about 330 days per year (86%), then the cost of capital is $22.90 per bbl. However, if the upgrader employs a coker (and most upgraders do) and upgrader has an input capacity of 100,000 bpd only 86,000 barrels of oil are produced, the remainder becomes petroleum coke. The cost of shrinkage is about $6.50 per of synthetic crude produced. Lastly, the process consumes fuel (~$3.75 per bbl) and non-fuel operating costs (~$5.75 per bbl). In short, the sum of the capital. Fuel and non-fuel costs is about $38.90 per bbl of synthetic produced. It should be noted that the product of this upgrader is a sweet synthetic oil that indicatively sells for a dollar less than WTI.
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The USGC is the largest market in North America for heavy barrels (~21 API). Historically, heavy barrels have been supplied by PDVSA from the Orinoco field or PEMEX from the Cantrell field. These barrels are delivered to the USGC refineries or neighboring tank farms using large tankers. To process these barrels gulf coast refiners in Texas and Louisiana have deployed about 1.23 million barrels of coking capacity and another 235,000 bbls/d of asphalt capacity (Source: EIA Refinery Capacity 2009). Over time, the supply of heavy oil called Maya from PEMEX’s Cantrell field has declined (it peaked at 2.1 million bbls/d in 2003 and PEMEX reported on December 9, 2009 it has declined to less than 580,000 bbls/d) and PDVSA opted to constructed several upgraders in Venezuela to turn the heavy oil into lighter oils. Although several other supply sources have attempted to fill the supply gap (such as MARS 100 and Ecuadorian heavy) the volumes have not been sufficient. In sum, at this point in time many of the cokers that were constructed to upgrade these heavy barrels are not operating at full capacity.
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Pipeline Transportation: Toll Changes
There appears to be a match between Alberta’s ability to produce bitumen and the surplus upgrading capacity in Texas and Louisiana. To supply large volumes of oil, industry typically employs large pipelines. Historically, pipeline transportation charges, called tolls, have been relatively inexpensive. However, the addition of a new pipeline, Transcanada’s Keystone, and the deployment of Enbridge’s Clipper, will have a long-term effect on pipeline tolls.
Largely, a pipeline’s effective toll is a function of the volume of oil that flows in the pipeline divided into by the amount of capital deployed times the regulated rate of return plus the pipeline’s variable costs. Indicatively, new pipelines are supported by either long-term shipping commitments (like TransCanada’s Keystone) or it is added to a pipeline company’s existing rate base (Like Enbridge’s Clipper). Because the supply of dilbit or synbit has not grown to match the new transportation capacity, rate based barrels, like those available on the Enbridge and Kinder Morgan systems, should migrate to pipelines with long-term take or pay commitments (like Keystone). The action of moving barrels from Enbridge and Kinder Morgan into the Keystone pipeline should cause the volume on the rate based systems to drop. When this volume effect is combined with the effect of adding of rate base (Clipper’s approximately $4 billion) the net effect should be a significant increase in the toll on Enbridge’s mainline. Although there have been no major capital additions to Kinder Morgan’s Transmountain Pipeline system, a volume reduction could take place. Hence we anticipate that the toll on this system will also rise to reflect lower useage.
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On December 2, 2009, Purvin and Gertz reported that Alberta produces about 80,000 bbls/d of natural gasoline (primarily pentane and hexane) and another 65,000 bbls/d of Naphtha from its indigenous natural gas. These hydrocarbons have been added to bitumen (typically a 10-12 API product) to produce a pipelinable product called dilbit (19-21 API). In recent years the indigenous supply of natural gasoline not been sufficient to meet the demand. To meet bitumen producer’s requirements, about 40,000 bbls/d of natural gasoline has been imported into Alberta, primarily using rail road tank cars. The National Energy Board (“NEB”) tracks these volumes and in a recent publication shows that it expects the demand for natural gasoline to grow by about 27,000 bpd each year for the next ten years. It is important to note that the price for this diluent is indicatively equal to the cost of railing the diluent back from supply sources like the USGC, Conway Kansas, or Wyoming.
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Diluent Transportation Penalty
Because there is an oversupply of natural gasoline in Kansas, the USGC and in countries like Algeria, the product typically sells at a discount to WTI. For example, if WTI is $75.00 US, then natural gasoline should sell for about 10% less or $67.50 per bbl. On the other hand, Alberta producers are paying the cost of transport plus terminal fees to get these barrels delivered into a terminal in Alberta. Rail transport from Mont Belvieu, Texas is about $10.00 per bbl and terminal fees adds another $2.00 per bbl. Hence, the purchase price for a barrel on natural gasoline in Edmonton should be the cost of purchasing the barrel in Mont Belvieu plus $12.00 or $79.50 per bbl.
The producer then transports this diluent barrel up to its production site (which costs another ($1.00-$2.00) then mixes it with bitumen (10 API) until the mixture is about 70% bitumen and 30% diluent (19-21 API). This product is called dilbit and is typically about 21 API. The dilbit barrel then transported using pipelines to a terminal then a distant refinery where the natural gasoline is extracted and, indicatively re-sold into the Alberta marketplace as diluent. In sum, cost of procuring and transporting diluent to Alberta, mixing it with bitumen, then transporting the dilbit to a distant refinery, creates an economic penalty equal to about $20.50 per barrel of diluent purchased. Because the diluent makes up about 30% of the dilbit barrel, the diluent penalty is $8.79 per barrel ($20.50 x 30/70) of bitumen transported.
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Net Effect on Bitumen Transportation
In addition, the shipper pays the pipeline toll from the production site through to the refinery in the USGC. The cost of pipeline transport is equal to about $8.00 per barrel. Hence the total cost of transporting a barrel of bitumen to the USGC is about $16.79 per barrel.
If the cost of carrying the diluent as inventory (102 days) and the cost of carrying the bitumen as pipeline inventory are added to the transportation cost, then the cost of bitumen transportation rises to $17.95 per bbl in this example.
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Altex, whether by employing a new technology pipeline or railroad tank cars with raw bitumen, wants to reduce or eliminate the diluent penalty from the transportation equation.
In summary, Alberta‘s supply of bitumen continues to grow at a rate of about 100,000 bbls per year. Coking capacity is available in the USGC. Hence, incremental production will be transported on pipelines like Enbridge’s mainline or Transcanada’s Keystone as 130,000 barrels of dilbit unless the cost of railing the raw bitumen to the USGC refiners is less than the cost of transporting bitumen in a dilbit pipeline.
Altex has negotiated long-term rail rates with CN and is offering transportation services to the bitumen producers at rates less than the cost of their pipeline transportation alternatives.
Furthermore, to support the shippers needs, Altex intends on constructing terminals near Peace River, Ft. McMurrary, and possibly Ft. Saskatchewan, Alberta. In addition, a delivery terminal with dock facilities is being developed near New Orleans, Louisiana.
Please contact Altex Energy Ltd at 403 508-7525 for more information.
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