by Dinara Millington| senior research director Canadian Energy Research Institute (CERI)

Another year has passed and 2012 was a year of growth for the Canadian oil sands. The fact remains that the oil sands is and will be one of the primary drivers of growth in the Canadian oil and gas industry. Over the past year, as per the Energy Annual Report by the Government of Alberta, the oil sands industry has drilled 2,171 wells, produced 1.7 million barrels per day of crude bitumen and contributed 4.5 billion dollars to provincial coffers.


All in all, 2012 marked a year of growth for oil sands producers amid transportation issues, lack of market diversification, increasing production of tight oil in the US and Canada, and on-going skilled labour shortages and rising project costs. It is clear that among all these themes, one dominated the most - transportation challenges.
While the skilled labour shortage remains a significant concern, the new oil sands projects will not come online due to pipeline constraints regardless of whether or not there are enough skilled personnel to work on these projects. Hence, when the US government rejected TransCanada’s Keystone XL project, originally intended as a 700,000-900,000 barrels per day (BPD) line to carry mainly oil sands streams from Hardisty, Alberta to the Gulf Coast via Cushing, it was a major impediment for the industry and provincial economy and has become a focal point of the political and environmental pro and anti-oil sands debate in the US. In the meantime, the future of Enbridge’s Northern Gateway project that would initially take 525,000 BPD of heavy oil sands streams west to British Columbia’s port of Kitimat - and then to markets mainly in Asia - has become the center of heated support and intense resistance in Canada.


It is not all doom and gloom for pipeline projects. Some have caught traction. The Seaway line that used to flow north to Cushing has recently been reversed with a current capacity of 150,000 BPD. It was expanded to a capacity of 400,000 BPD from Cushing to the Gulf Coast in early 2013 and further expansion to 600,000 BPD is planned by mid-2014. Since the original Keystone XL was rejected, the Keystone XL project has been split into two parts: a southern leg from Cushing to the Gulf that has received all necessary permissions to proceed and is expected to start operations by late 2013.
A Seaway reversal and expansion, with the Keystone XL southern leg, will add over 1.65 million barrels per day (MMBPD) of capacity out of Cushing to the Gulf by 2014. This will substantially alleviate the “Cushing congestion” but given the oil sands production forecast, pipeline capacity might still be an issue. Given current constraints and opposition to expansion of existing pipeline capacity and new pipeline developments, companies have been proactive at exploring other transport options such as rail. It seems that producers have come full circle, returning to shipping crude in rail cars. While rail is emerging as a serious option to pipeline transportation, it is subject to limited availability of rail cars, terminals, and storage capacity, not to mention that rail, as pipelines, has a finite capacity along with safety and environmental concerns.


Every year, the Canadian Energy Research Institute (CERI) publishes an update on developments within the Canadian oil sands industry. In May 2013 CERI released its eighth annual update, Study 133, Canadian Oil Sands Supply Costs and Development Projects (2012-2046) examining production, supply costs, and constraining factors for oil sands development. This article will summarize the report’s key findings.



Oil Sands Background
The phrase “resources beyond belief ” has often been used to describe Alberta’s oil sands. Decades of research and development from all levels of government in Canada, in addition to industry, have transformed the oil sands from a worthless mixture of sand and oil (only good for paving roads), into one of the most sought after commodities on the planet. Alberta’s oil sands are one of the largest hydrocarbon deposits in the world, placing third on the world scale after Saudi Arabia and Venezuela (in 2011, the Oil and Gas Journal updated reserves number for Venezuelan deposits; the update results from the inclusion of massive reserves of extra-heavy oil in Venezuela’s Orinoco belt, vaulting Venezuela into second place on the world scale of hydrocarbon reserves).
In Alberta, the geological formations and geographical area containing bitumen – crude bitumen, or bitumen, is a term that reflects the extra heavy oil within the oil sands areas; the term oil sands includes the crude bitumen, minerals, and rocks that are found together with the bitumen - are designated as three distinct oil sands areas (OSAs) - Athabasca, Cold Lake and Peace River, and are illustrated in Figure 1.


Together these regions cover an area over 142,000 square kilometers (km2). Within the OSAs, there are 15 deposits that cover the geological plays containing the oil sands, with the remaining established reserves at 168 billion barrels of an extremely heavy crude oil, referred to as bitumen, of which approximately 15 per cent is currently under active development.
Mining and in situ production are the two bitumen recovery methods that are currently employed in the oil sands. Of the recoverable bitumen remaining, 80 per cent is estimated to be recoverable using in situ methods, which target deposits that are too deep for mining (generally more than 75 meters). In situ extraction includes primary methods, similar to conventional crude oil production, enhanced oil recovery (EOR), and other methods, where steam, water, and/or solvents are injected in the reservoir to reduce viscosity of the bitumen, allowing it to flow. The remaining recoverable bitumen occurs near the surface and is anticipated to be recovered using mining techniques.


The Alberta provincial regulator continues to estimate and update Alberta’s crude bitumen resources and reserves. Table 1 provides a breakdown of the initial volume-in-place, initial established reserves, cumulative production, as well as the remaining established reserves as of December 1, 2012.
While the resource base is very large, it is worth noting the quality of the oil sands deposit is not the same throughout. The quality of an oil sands deposit depends mainly on the degree of bitumen saturation within the reservoir and the thickness of the saturated interval. The bitumen saturation level can also vary significantly, depending on the shale or clay content or amount of water within the pore space of the rock.



Oil Sands Supply Costs
Supply cost is a constant dollar price needed to recover all capital expenditures, operating costs, royalties and taxes and earn a specified return on investment. Supply costs are calculated using an annual discount rate of 10 per cent (real), which is equivalent to an annual return on investment of 12.5 per cent (nominal) based on the assumed inflation rate of 2.5 per cent per annum. Based on these and other assumptions, the supply costs for the production of crude bitumen using primary recovery, steam assisted gravity drainage (SAGD), surface mining and extraction, and integrated mining and upgrading have been calculated for a hypothetical project.
Figure 2 illustrates the supply costs for primary recovery, SAGD, mining and integrated mining. The plant gate supply costs, which exclude transportation and blending costs, are 30.32 dollars/bbl, 47.57/ dollars/bbl, 99.02 dollars/bbl, and 68.30 dollars/bbl for primary recovery, SAGD, integrated mining and upgrading, and standalone mining, respectively, expressed in 2011 real Canadian dollars.


After adjusting for blending and transportation, the WTI equivalent break-even price at Cushing, Oklahoma for primary recovery is 58.61 dollars/bbl; for SAGD projects - 77.85dollars/ bbl;103.16 dollars/bbl for integrated mining and upgrading projects; and 99.49 dollars/bbl for stand-alone mining projects. While capital costs and the return on investment account for a substantial portion of the total supply cost, the province of Alberta stands to gain 6.4 to 12.9 dollars in royalty revenues for each barrel of oil produced on average, over the life of an oil sands project.
Compared with CERI’s estimates last year, the costs are up by 6.3 per cent for SAGD, 10.9 per cent for integrated mining, and 13.2 per cent for stand-alone mining. The higher supply costs are driven by higher capital and operating costs. Labour shortages, material scarcity, administrative and frontend engineering delays have contributed to increased costs.



Oil Sands Forecasts – Reference Case Scenario
CERI Study 133 is based on three plausible scenarios that take into account possible paths for the economic recovery (and demand for oil), emissions legislation, and lastly the impact that the emerging economies could have on the demand growth for crude. However, the scope of this article precludes a detailed assessment of high and low case scenarios and focuses on the reference case scenario projection over the next 35 years.
In 2012, total production from Canadian oil sands areas is estimated to have increased by 13 per cent from the prior year to 1.9 MMBPD (millions barrel per day). In a reference case scenario, CERI projects production from mining and in situ extraction, which totaled 1.7 MMBPD in 2011, will reach 3.1 MMBPD by 2020 and 5.6 MMBPD by 2046. Illustrated in Figure 3 are the production projections by extraction type.
Total mined bitumen production is expected to increase from 0.9 MMBPD in 2011 to its peak of just over 2 MMBPD by 2038, at which point the production remains flat for the remainder of the projection period. As well, in situ production is expected to increase from 0.8 MMBPD (including Primary and EOR projects) in 2011 to 3.7 MMBPD by 2046 due to the addition of new proposed projects and the accelerated development schedules for existing and approved projects. Cold bitumen production from primary and EOR wells is forecasted to increase from 0.2 MMBPD in 2011 to its peak of 0.4 MMBPD by 2017 and then slowly taper off to just above 0.1 MMBPD by the end of projection period.


The increase in projected production is a result of relatively high oil prices and the availability of foreign capital investment. Mined bitumen maintains a majority status of oil sands volumes until 2014, when in situ production volumes overtake mined volumes. The share of bitumen production from mining is estimated to decrease from 51 per cent in 2011 to 35 per cent in 2046. By the end of the projection period in 2046, in situ bitumen accounts for 65 per cent of total production volumes, or 3.7 MMBPD, compared to mined bitumen production at just over 2.0 MMBPD.
Achieving the level of production outlined above requires a substantial number of inputs, of which capital (both strategic and sustaining), and natural gas are critical. Without the required capital, an oil sands project cannot be constructed. The project, with current technologies, cannot operate without an abundant and affordable supply of natural gas. Lastly, once the facility is operating there is an ongoing need for sustaining capital to ensure that production volumes stay at their design capacities.


Initial (or strategic) and sustaining capital requirements are broken down by project type and are illustrated in Figure 4. Over the 35-year projection period from 2012 to 2046 inclusive, the total initial and sustaining capital required for all projects is projected to be 546.7 billion dollars (nominal Canadian dollars) under the reference case scenario, comprised of 240.7 billion dollars in initial capital costs and 306 billion dollars in sustaining capital. Capital investment in situ projects surpasses the capital spent for mining projects, which is consistent with the ongoing trend to invest more into in situ projects rather than mining.
From 2012 to 2046, it is projected that 229.3 billion dollars (initial and sustaining) will be invested into mining projects and 283.1 billion dollars in situ thermal and solvent as well as primary and EOR cold bitumen projects. Upgrading projects see the least amount of capital spent from 2012 to 2046, amounting to 34.3 billion dollars. Total operating costs average 34 billion a year and over the projection period cumulatively add up to 1,195 billion.


More than the conventional oil and gas industries, the oil sands industry is a large consumer of energy. Given that most in situ projects generate steam using natural gas-fired steam generators, the single highest operating cost for these in situ thermal projects is the cost of natural gas. Although mining, extraction and upgrading projects use proportionately less natural gas than in situ projects, the industry’s demand for natural gas is still substantial.
When estimating the gas required for oil sands production projections, CERI used the historical steam-oil ratios where they are provided, otherwise default values are assigned for gas use for different technologies. In reality, however, steamoil ratios are not constant, and the volume of gas used can vary significantly due to varying temperature and pressure requirements.
By 2046, natural gas requirements will increase by 2 to 3 times the current levels. Given the robust production projection, natural gas use is estimated to rise from the current 1,259 million cubic feet a day (MMcf/d) in 2011 to 3,183 MMcf/d. The technological innovation driven by human ingenuity and environmental push towards “greener” technologies will likely put downward pressure on the industry’s natural gas requirements. Also, considering how aggressively shale gas production in the US has come on stream, and the potential for shale production in Canada, meeting the oil sands industry’s future demand for natural gas should not be a concern (for more information on natural gas production forecast, please see CERI’s forthcoming study Natural Gas Pathways).


Without equipment to sequester emissions, the greenhouse gas (GHG) emissions grow proportionately to the increases in production. While technological innovation within the oil sands industry (in addition to carbon capture and storage) is expected to help reduce these emissions, the emissions are still expected to rise.
Emissions will rise from 47 million tonnes a year (Mt/year) in 2011 to 55 Mt/year in 2012 and 156 Mt/year in 2046 under the reference case scenario. However, the oil sands industry has been reducing its per unit emissions, and in 2011 per barrel emissions intensity was 26 percent lower than in 1990. This reduction in GHG intensity is significant, as larger and larger portions of crude supply are derived from oil sands. Cumulative emissions are projected to be 4,442 Mt from 2012 to 2046, which is 1.2 per cent lower than last year’s projection. This can partially be attributed to Shell’s Quest project, starting in late 2015, which will capture and store more than one million tonnes per year of CO2 produced at the Scotford Upgrader.



Conclusion
The plans to expand oil sands production, increase pipeline take-away capacity and gain access to other markets are still, however, dependent on key elements that must align for the industry. CERI believes these elements are:
i) favourable oil prices at levels where oil sands projects can be economic;
ii) continuous improvement in an environmental performance among producers to maintain their social license to operate;
iii) appropriately managing project cost inflation by addressing skilled labour shortages and operational efficiencies;
iv) the ability to collaborate effectively in a competitive environment.