Impacts and Mitigations of in Situ Bitumen Production from Alberta Oil Sands
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Impacts and Mitigations of In Situ Bitumen Production from Alberta Oil Sands Neil Edmunds, P.Eng. V.P. Enhanced Oil Recovery Laricina Energy Ltd. Calgary, Alberta Submission to the XXIst World Energy Congress Montréal 2010 - 1 - Introduction: In Situ is the Future of Oil Sands The currently recognized recoverable resource in Alberta’s oil sands is 174 billion barrels, second largest in the world. Of this, about 150 billion bbls, or 85%, is too deep to mine and must be recovered by in situ methods, i.e. from drill holes. This estimate does not include any contributions from the Grosmont carbonate platform, or other reservoirs that are now at the early stages of development. Considering these additions, together with foreseeable technological advances, the ultimate resource potential is probably some 50% higher, perhaps 315 billion bbls. Commercial in situ bitumen recovery was made possible in the 1980's and '90s by the development in Alberta, of the Steam Assisted Gravity Drainage (SAGD) process. SAGD employs surface facilities very similar to steamflooding technology developed in California in the ’50’s and 60’s, but differs significantly in terms of the well count, geometry and reservoir flow. Conventional steamflooding employs vertical wells and is based on the idea of pushing the oil from one well to another. SAGD uses closely spaced pairs of horizontal wells, and effectively creates a melt cavity in the reservoir, from which mobilized bitumen can be collected at the bottom well. Figure 1. Schematic of a SAGD Well Pair (courtesy Cenovus) Economically and environmentally, SAGD is a major advance compared to California-style steam processes: it uses about 30% less steam (hence water and emissions) for the same oil recovery; it recovers more of the oil in place; and its surface impact is modest. A typical injector/producer pair of SAGD wells occupys about 1 hectare of cleared space, including wellsites and its associated share of - 2 - facilities, roads, and utility right-of-ways. A typical production rate per pair is 500 bopd, with some at 2000 bopd; making SAGD wells among the most productive to be found onshore in North America. Figure 2 is a photo of a 10,000 bpd commercial SAGD project in the Athabasca region. Figure 2. A SAGD oil sands facility designed to produce 10,000 barrels of bitumen per day for ~ 25 years (courtesy Connacher Oil and Gas Ltd.) On the other hand, SAGD and derivative technologies make possible the large scale development of the largest hydrocarbon resource on earth. Does this impending development threaten the local ecosystem? Is it a global carbon dioxide menace, as suggested by Al Gore and others? Are there not other ways of producing this energy that are less impactful on the environment? This paper does not presume to answer such questions, which are of global and societal scope. However the debate has been proceeding on the basis of a selective set of facts and some very big exaggerations. The intent of this submission is to support the debate (on both sides) with a quantitative account of the principal impacts of in situ oil sands development in Alberta. Impacts on land (habitats), water, and air are considered in terms of local capacity, global benchmarks, and comparisons to alternative renewable technologies. Land Use Intensity Habitat Impacts It has been claimed that oil sands development in Alberta will result in a “hole the size of Florida [170,304 km2]”, or England [130,357 km2]. These statements were presumably founded on the erroneous idea that all oil sands involves open pit mining, multiplied over the total “designated” oil sands area [140,800 km2]. However, the oil sands areas designated by the Alberta Energy Resources Conservation Board (ERCB) - 3 - are administrative districts, that are intended to contain any and all shows of bitumen found in the province. Due to geological variation, only a small fraction of this huge area is host to economically feasible concentrations of bitumen; this is true even within the principal leases of major operators. Secondly, as has been noted, only a small (and concentrated) fraction of the resource is actually close enough to the surface to be mined. The majority is buried from 50- 500 metres underground, and will be recovered in situ, using horizontal wells with a lateral reach of up to a kilometre. The combined effect of these factors is that in situ production will sit rather lightly on the forests of northern Alberta. The oldest and largest such operation, Cenovus' Foster Creek Project, is shown in satellite views in Figure 3. At the time of the picture, sufficient land had been cleared for 80,000 bpd of production. A line of well pads is connected to the central facility by a single road. The development follows the typically channelized concentration of oil sand below the surface. The picture includes the greater lease, most of which is not prospective and will remain undisturbed by oil producers (gas production is widespread in the area). Figure 3. Satellite views of Cenovus' Foster Creek SAGD Project (2006, ca. 80k bopd) The following table puts some numbers to this. The cumulative and active areas are calculated assuming productivity of 500 bopd per hectare of disturbance, and 1e6 barrels of reserves per well pair. These are conservative numbers, representative of current technology, which remains fairly immature. In this table, the potential for Alberta in situ production is estimated at 5 million barrels per day, and the ultimate resource is taken to be 300e9 bbls. It would take 164 - 4 - years to produce 300 billion barrels at that rate; so it is doubtful that the hydrocarbon age will last as long as the resource. Table 1. Areas of Disturbance vs. the Habitat Area, km2 Canadian boreal forest 5,265,000 Alberta boreal forest 317,700 AERCB oil sands area 140,800 Cumulative disturbance, 300e9 bbl (164 yrs @ 5e6 bpd) 30,000 Active (unreclaimed) area for 5e6 bopd in situ 100 Regulation, Reclamation and Mitigation On the basis that optimum SAGD well lifetimes are typically less than 10 years, a typical clearing-to-reclamation cycle is likely to be ~20 years. The future development of secondary recovery processes could extend this somewhat, but with the benefit of reducing the need for new development elsewhere. Local residents are consulted with regard to special places in the affected regions; in situ siting is flexible and must also respond to various regulatory requirements, especially with a view to preserving the local drainage. In a recent case, the provincial government summarily revoked a significant oil sands lease, when the operators failed to allay concerns of the residents regarding possible effects on an overlying lake. Project approval requirements are exacting, particularly with respect to environmental assays and impact assessments. Timely reclamation of abandoned operations is mandatory. The industry practises further land use mitigation by my means of shared use of roads and right of ways with conventional oil & gas, forestry, and power transmission operators. Land Consumption Compared to Renewable Alternatives Table 2 below compares the land areas required to support various alternative energy sources, relative to SAGD bitumen. Once again a SAGD productivity of 500 bopd per hectare of (temporary) disturbance is assumed. In the case of wind turbines, which produce electrical energy directly, their output is compared to that of the other, thermal sources at a conversion rate of 3:1, reflecting an - 5 - assumed thermal electricity generation and transmission efficiency of 33%. However, an availability factor of 20% is also applied to wind sources, which is at the high end of values realized so far by actual turbines. The area affected by a given wind turbine is primarily an aesthetic judgement, however they are low density power sources that require service roads and transmission lines. It is suggested that 1 hectare (i.e. 100 x 100m) per turbine is an appropriate comparison, even in the absence of aesthetic objections. Ethanol has been equated to bitumen at equal liquid volumes, which is close enough for our purposes here. It can be seen that proposals to replace hydrocarbon fuels with various alternatives, must be considered in terms of all possible impacts to the environment (or else food production), and not just carbon emissions. Table 2. Comparison of Land Requirements for Alternative Energy Sources Energy Source Area to support Area to support 100,000 500 bopd or bopd or equivalent* equivalent* Bitumen, Alberta SAGD 1 ha (2.5 acres) 200 ha Wind turbines (plus roads, 50 x 1.5 MW 10,000 x 1.5 MW turbines power lines): turbines Ethanol from Iowa corn: 7,000 hectares 1,400,000 ha (14,000 km2) *see text Water Water consumption and potential contamination of ground water or aquifers is perhaps the easiest of concerns to address with respect to the environmental impact of oil sands development. The main points to be made are that in situ technology uses only deep well water, unsuitable for any domestic or agricultural use; that it uses a very small amount of water relative to other products, and to the locally available volumes; and that waste water is disposed of in (deeper) wells, and not released in the environment. Water is unevenly distributed in Alberta. The southern half of the province, in the Saskatchewan basin, contains almost all of the population and agriculture. It includes a semi-arid zone, and there are serious concerns about water supply in southern Alberta, going forward. The northern half of the province, containing all of the oil sands, is part of the Mackenzie basin. In the boreal muskeg the water table is most often at the surface. As abundant as bitumen may be in the area, fresh water in shallow glacial deposits - 6 - greatly exceeds that.