Survey of Energy Resources 2007
Natural Bitumen - Economics of Production, Transportation, and Refining Technology
Production technologies: Canada
Natural bitumen deposits occurring at depths of up to 250 feet can be surface-mined. The bitumen is then separated from the mined sand by a hot water process. The bitumen mined at two of the three operating mining/separation projects (Suncor Energy and Syncrude Canada) is upgraded onsite into a synthetic crude oil (SCO), which is then transported by pipeline to conventional refineries. The third project, Albian Sands Energy, transports a mixture of bitumen and diluents to the Scotford upgrading facility about 270 miles south, near Edmonton. In 2005, mined production amounted to 551 thousand b/d for the three Alberta oil sand mining projects. Of the 174 billion barrels of bitumen estimated by the Alberta Energy and Utilities Board (EUB, 2006) to be recoverable from identified deposits, 32 billion barrels is accessible with current surface-mining technology.
In a limited number of areas, bitumen that is too deep for surface mining is produced from wells for short periods without injection of steam. In cold production with sand (Cold heavy oil production with sand - CHOPS) bitumen and sand are pumped to the surface through the well bore and then separated. Sand production creates channels or high-permeability zones for the bitumen to flow through (Dusseault, 2001).
Most bitumen deposits are not amenable to cold production over extended periods, so steam is commonly injected into the reservoir to raise the temperature and reduce the viscosity of the bitumen. Fig. 4-3 shows the dramatic reduction in fluid viscosity with increasing temperatures for the bitumen at Athabasca and Cold Lake. Steam can be injected through vertical or lateral (horizontal) wells. At Cold Lake, bitumen has historically been produced with cyclic steam stimulation. In this process, steam is injected into the formation during the 'soak' time period or cycle to heat the formation. The production cycle begins after injection wells are converted to producers and ends when the heat is dissipated within the produced fluids. This cycle of soak and produce is repeated until the response becomes marginal because of increasing water production and declining reservoir pressure. After a number of cycles, steam may also be injected as a steam flood to improve reservoir pressure (Dusseault, 2006).
An alternative extraction method is the steam-assisted gravity drainage (SAGD) process (Fig. 4-4 ), where a horizontal steam-injection well is drilled about 5 metres above a horizontal production well. Injected steam creates a heated chamber, the heated bitumen is mobilised, and gravity causes the fluid to move to the producing well where it is pumped to the surface. Diluents may also be injected to assist in lowering the viscosity of the reservoir fluids.
When the EUB estimates recoverable bitumen resources it assumes the following recovery factors for the original bitumen in place: cold production, 5%; cyclic thermal production at Cold Lake, 25%; SAGD at Peace River, 40%; and SAGD at Athabasca, 50%. The EUB estimate of the recovery efficiency of mining and extraction of the in-place bitumen is 82% (National Energy Board [NEB], 2006).
Production technology: Venezuela
In the Orinoco Oil Belt, cold production of extra-heavy oil is achieved through multilateral (horizontal) wells that are precisely positioned in thin but relatively continuous sands, in combination with electric submersible pumps and progressing cavity pumps. Horizontal multilateral wells maximise the borehole contact with the reservoir. Extra-heavy oil mobility in the Orinoco Oil Belt reservoirs is typically greater than that of bitumen in the Alberta sands because of higher reservoir temperatures, greater reservoir permeability, higher ratio of gas to oil, and the lower viscosity of extra-heavy oil (Dusseault, 2001). Efforts are also continuing to improve production of viscous oil through down-hole electrical resistance heating.
The recovery factor for the cold production of extra-heavy oil in the Orinoco is estimated to be 8-12% of the in-place oil. It is fully expected that the Orinoco projects will install enhanced recovery methods after the cold production phase of recovery is completed. While it is generally recognised that thermal recovery methods will be applied following cold production, other tertiary recovery methods involving gas injection and in-situ combustion could also be profitably applied to the extra-heavy oil and natural bitumen reservoirs following steam thermal recovery methods (Dusseault, 2006).
Production economics: Canada
Fig. 4-5 shows the NEB estimates of bitumen and synthetic oil supply costs in 2005 Canadian dollars (1 CDN$ = US$ 0.85). The NEB cost estimates assume a US price of West Texas Intermediate of US$ 50/bbl, NY Exchange price of gas at US$ 7.5/million Btu and a 10% real return. Costs associated with cold production are low because of low operating costs. However, recovery by cold production is also low and for the Alberta sands not sustainable for long periods of time. The SAGD process costs appear to be slightly lower than cyclic steam costs. The range of costs for the mining/extraction process is within the cost range of the SAGD process. The NEB's published per barrel cost of supply estimates were based on historical information, regulatory filings for new operations, and internal engineering cost models. The capital investment costs are CDN$ 15 000 - 20 000 per sustainable daily barrel (NEB, 2006), so a project capable of producing 30 000 b/d would have a nominal investment cost of CDN$ 450 to 600 million.
In most cases operating costs account for half of the supply costs. For the thermal processes, the cost of natural gas used to generate steam makes up approximately 65-75% of operating costs. Under favourable conditions, each barrel of bitumen produced consumes 1.05 thousand cubic feet of natural gas, based on a steam-to-oil ratio of 2.5:1. If gas is used as fuel in the mining/extraction configurations, gas requirements are 0.7 thousand cubic feet per barrel of bitumen produced. There is great concern regarding the large volumes of water and natural gas used in the thermal recovery processes. Recent research has focused on reducing thermal process gas requirements by substituting other fuels or by reducing the steam-to-oil ratio by injecting solvents into the reservoir. Unless there is onsite upgrading to SCO, the product that will be transported to upgrading facilities will be a blend of two-thirds bitumen and one-third diluents. The availability of natural gas liquids or light oil to use as diluents in transporting the bitumen to upgrade facilities is also a potential challenge to expansion.
Production economics: Venezuela
The unit supply cost for the Orinoco extra-heavy oil utilising cold production is much lower than the supply cost for cold production of bitumen in Canada because of more favourable fluid and reservoir conditions. The sustainability of a well production plateau is much longer, and the level well production is as much as an order of magnitude higher in Orinoco extra-heavy oil than in the Canadian bitumen projects. Current estimates of the supply costs for the Orinoco extra-heavy crude oil are as little as half of the supply cost for Canadian bitumen (Fig. 4-4 ).