Impacts and Mitigations of In Situ Bitumen Production from

Neil Edmunds, P.Eng. V.P. Laricina Energy Ltd. , 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 . 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 basin, contains almost all of the population and agriculture. It includes a semi-arid zone, and there are serious concerns about water supply in , 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. More water can usually be found at increasing depths, with increasing salinity.

Water for SAGD Alberta regulation requires the use of deep, non-potable water for steam generation, if available in the area (which is usually the case). The general standard is greater than 2000 ppm TDS. As another legacy of the California steamflood pioneers, and the extremely stressed water situation in that state, the industry has over the years developed water recycling technology of increasing efficiency. Standard recycle rates are now in the range of 80- 95% of the produced water. In a typical SAGD operation, essentially 100% of the water injected as steam is produced again and available for recycle. The average steam/oil ratio (SOR) for Alberta SAGD is currently about 3, meaning 3 volumes of water are boiled into steam to recover one volume of bitumen. The industry is not technologically mature, however, and this average can be expected to fall to the 2-2.5 range over the next decade or so.The best operators (e.g. Cenovus) are currently in that range. The amount of makeup (brackish) water required to produce a volume of bitumen is then within the range: SOR=3 & 80% recycle → uses 0.6 bbl (brackish) water / bbl oil SOR=2 & 90% recycle → uses 0.2 bbl (brackish) water / bbl oil

Relative to local capacity The maximum/optimum scale SAGD projects will tend to be about or less than 100,000 bpd. This follows largely from the technical and economic limits of pipelining high pressure steam for long distances. A single plant can reasonably reach reserves over an area about the size of a township (36 sq. miles, or 93 km2). How big a draw is this on the local resources? The water is sourced from deep wells, but is this sustainable in terms of the amount of rainfall available for aquifer recharge? Given the previous table, a 100,000 bopd project will require 10,000 - 60,000 bwpd makeup from deep wells, to service a one-township lease. Typical annual rainfall in the oil sands region is perhaps 40 cm/year. The volume of water falling on a township in a year is then 0.4 m x 93e6 m2 = 37e6 m3. Dividing by 365 days and converting to barrels, the average daily rainfall on a single township is found to be about 640,000 bbls of water per day.

Relative to other products Table 4 gives estimates of the amount of water required to produce agricultural staples, compared to oil sands bitumen. In modern urban society, our individual water footprints are dominated by food production, especially livestock (cows don't drink so much water, but they eat many times their weight in grain, over their lives).

- 7 - Table 4. Volumes of water used to produce things Product Average virtual water content* (m3/tonne or kg/kg) Beef 15,500 Rice 2300 Wheat 1300 Corn 900 SAGD Bitumen 0.2-0.6 *http://www.waterfootprint.org/Reports/ResearchData/Appendix%20XV.xls

Waste Water Disposal Water recycling and other processes generate small volumes of concentrated waste water that cannot be processed further. By default, this water is injected into deep formations, below the oil sands. Generally the injected water is of higher quality than that in the receiving formation. The target formation, well design, injected substances, concentrations, volumes, and pressures are all regulated and enforced. Where suitable zones for deep injection are not available, operators have employed zero-discharge evaporation technology, which recycles about 95% of the produced water. The small volume of remaining sludge (mostly salt) is placed in landfills designed and monitored to prevent leaching. Evaporation is not the default choice over deep injection, because it requires increasing amounts of fuel, and therefore emissions, to approach 100% recycle.

The Athabasca River As opposed to in situ mehods, the extraction technology used by oil sands miners does require fresh water, which is sourced from the Athabasca River. The total future draw on the river, assuming maximum possible mine developement, remains a modest fraction of the average annual flow, i.e. less than 5%. There is however a problem during low flow periods of the river, in fall and winter. The Province is currently moving to further limit or suspend water draw during these periods. This may require mine operations to store water on site, for use during such times, but this is not economically prohibitive by any means. Tailings from the mining extraction process are impounded in surface ponds; most of this water is recycled many times. Figure 4 shows photographs of a naturally occuring oil sand outcrop, forming the banks on a tributary of the Athabasca River. The McMurray formation outcrops in the Athabasca valley for a distance of more than 150 km.The river, and most of the tributaries along this section, are still actively cutting through the oil sand. Bitumen is found in the river bed sediments, and in warm weather, natural hydrocarbon sheens are common on the water surface.

- 8 - Figure 4. Natural Oil Sand Outcrops, Athabasca Area This natural history must be borne in mind when evaluating reports of hydrocarbon contamination in the river, and reference made to historical baseline and upstream samples.

Carbon Emissions & Air Quality

“3 times” What, Exactly? A widely disseminated criticism of oil sands development is the statement that it causes “3-5 times” the CO2 emissions, compared to “conventional” oil production. This statement is true as far as it goes, but is also largely meaningless, for the following reasons:  The “conventional oil” referred to means light, sweet (i.e. low sulfur) crude produced on the North American plains.Such low-cost opportunities were mostly exhausted some time ago, however, and they do not constitute an actual alternative to oil sand production, in terms of replacing the decline of current production. The remaining alternatives are increasingly heavy and/or remote, and thus also involve substantially higher emissions from production, transportation, and/or refining operations.  The emissions required to produce conventional oil is a very small fraction of the total life cycle emissions through to the end use of the products. 3 times a very small number is still a small number. To put it another way, onshore conventional oil production uses very little fuel relative to the amount produced.  A commercial fuel producer can only afford to burn so much fuel itself, and still remain in business. Emissions are directly proportional to fuel burned (Figure 5). Those in situ operations that are currently at the high end of the range (i.e. "5x"),

- 9 - are in fact economically challenged and must improve to continue, let alone be expanded.  The gravity-based in situ technologies which have and are being pioneered in Alberta, are technologically immature. There is considerable room for improvement, and incentives as large as the resource. As discussed below, material improvements in energy efficiency are already appearing in commercial application.

100.0 kg CO2e / produced bbl 90.0 Duri, Sumatra 80.0 Midway-Sunset *

n 70.0

e Kern River m

u S. Belridge t

i 60.0 b

l Cold Lake b 50.0 b

/

Foster Creek (SAGD) e

2 40.0 O solvent additive C

g 30.0 technology k *burning 1 bbl of 20.0 gasoline emits ~ 425 kg CO 10.0 2

0.0 0 0.5 1 1.5 2 2.5 3 3.5 4 Steam/Oil Ratio, 100% vapor equiv.

Figure 5. Carbon Intensity of In Situ Production vs. SOR

“Wells to Wheels”: Life Cycle Analyses of Fuel from Oil Sands Figures 6 and 7 summarize the results of three independent studies of carbon emissions due to hydrocarbon fuel consumption, from all sources between the wellhead and the end use. In figure 7, the green portion represents emissions due to combustion, e.g. what is emitted by the end consumer. This is about 70-80% of the total.

- 10 - Figure 6.TIAX & Jacobs LCA Studies of Various Crude Sources

Life Cycle GHG Emissions from Products for Various Crudes In Situ Light/Sweet 4000 450 150 3500 l

e 3000 u f

L 2500 0 0 0

1 2000 / e 2 1500 Consumer o C 2750

g 1000 k 500

0 Canadian Brent Arab Canadian Nigerian Mexican Canadian Canadian Venezuelan California Light Blend Light In Situ Excravos Mined In Situ Partial In Situ (SOR 1.5) (SOR 3.0) Upgrader

Combustion Transportation Refining Production

Source: T.J. McCann & Associates & IOSA

Figure 7. T.J. McCann & Associates LCA Comparison

More detail in the non-consumer portion is shown in figure 8. Here "upgrading" means partial refining at the production site, which reduces the amount of "refining" downstream. The world crude oil supply is increasingly heavy and sour (i.e. sulphurous), such that energy requirements for refining bitumen are not much different from that of an average refiners' slate. Figure 8 does however highlight some

- 11 - fundamental inefficiencies in the use of field upgraders, compared to shipping diluted bitumen to integrated refining operations with extra heavy conversion capacity.

Figure 8. Breakdown of Non-Consumer Emissions Overall, and setting aside economically pathological examples, the life-cycle emissions due to consumption of fuels sourced from oil sands are in the range of 5- 15% higher compared to the actual world slate of crudes available to refiners today. With respect to the Low Carbon Fuel Standards advance by the state of California, it can be seen that steamflood production of heavy oil in that state proves to have one of the largest carbon footprints in the world. It is produced by technology that is previous-generation, from the point of Alberta SAGD operators, and the properties of the crude are much closer to oil sand bitumen than to light sweet crude. (Despite these realities, California producers were exempted from the LCFS, before it was enacted.)

Effect of Cogeneration In the context of a SAGD or other steamflood project, cogeneration involves the use of gas turbines to generate electrical power, for local supply and export to the grid. The hot exhaust from the turbine, which contains about 2/3 of the total fuel input as waste heat, is reburned in a specially designed steam boiler. The boiler uses the waste heat, with additional fuel, to make steam, about as efficiently as a regular boiler.

- 12 - The combined effect of this arrangement is that, given a suitable steam “host”, cogeneration can produce electricity with an effective incremental thermal efficiency approaching 100%. is used as the turbine fuel. In Alberta, most current electricity is coal-fired, with a maximum thermal efficiency of about 45%. A certain carbon offset can thus be realized by substituting future coal- fired electrical generation capacity with gas-fired cogeneration, hosted by in situ plants. Figure 9, based on the Jacobs study, indicates that cogeneration has the ability to reduce the carbon footprint of oil sands-derived fuels to the equivalent of conventional crudes.

Figure 9. Magnitude of Cogeneration Substitution Credit for Alberta SAGD

In Situ Emissions on the Global Scale

The following table compares the resulting future annual CO2 emissions, with 2006 global and Canadian emissions due to fossil fuel combustion. It assumes a potential future scale of SAGD development of 5 million bpd, a steam/oil ratio of 3.0 (roughly the median of current operations), and without any CCS, offsets, cogeneration credits, or further improvement in either technology or execution.

- 13 - Table 5. Pro Forma In Situ Emissions vs. 2006 World & Canadian Fossil Fuel

kt CO2/year %

World (2006) 28,431,741 100.0

Canada (2006) 544,680 1.9

5e6 bpd SAGD Bitumen (pro forma) 137,000 0.5 A conservative estimate of the maximum forseeable rate of carbon emissions from future in situ oil sands operations, is thus about one half of one percent of global 2006 emissions, due to fossil fuel combustion.

Reduced Impacts Going Forward: Solvent Additive Processes For steam-based recovery processes such as SAGD, makeup water requirements and carbon emissions per unit of production are both directly proportional to the ratio of steam (cold water volume) injected to the oil produced, or SOR. Economically speaking, the SOR is responsible for more than half of the total (capital and operating) production cost. Producing at the minimum possible SOR (with due regard to other required resources, notably the number of wells) has thus always been the foremost objective in SAGD engineering and operations. SAGD is the most efficient steam-based oil oil recovery process yet to be demonstrated at commercial scale. It is also a novel, dynamic, and demanding technology. Many of the current operators are new to the technology, operating in new reservoirs. These operators will find significant optimizations compared to current performances, as they and the industry as a whole gain experience, and best practises are accumulated. There are however limits to what can be accomplished with basic SAGD, constrained by the physical properties of steam itself. In particular, the temperature of the steam, and hence the reservoir rock, is determined by the operating pressure, and usually translates into temperatures of 200˚C or more (from an initial 10-15˚C). Other factors being equal, the SOR is proportional to this temperature rise. SOR reduction ultimately requires that bitumen be mobilized and produced from regions of the reservoir that are below steam temperature. An early concept for SAGD was simply to mix some non-condensible gas, such as methane or CO2, into the steam and thus dilute the saturation temperature to a desired value. This concept fails because of the tendency of the gas additive to accumulate and concentrate at the front, which impairs further steam flow and heat transfer. In the late 1990's PanCanadian (later EnCana and now Cenovus) showed that butane was an effective additive for SAGD SOR reduction, with a first trial in a heavy oil pool at Senlac, Saskatchewan. 30-40% improvements were demonstrated. Cenovus continued to advance this process and has recently begun to apply it on a commercial basis at their Christina Lake Project, in the Athabasca region.

- 14 - The mechanism for improvement is illustrated in Figure 10. The top insert shows the situation for classic SAGD using pure steam: bitumen only drains once the sand has been raised to at or near steam temperature, so the average recovery temperature is the same as steam temperature.

Steam Front (SAGD)

depleted low-temp zone Steam+Solvent Front

Temperature Oil Sat.

Oil Mobility

Figure 10. Cartoon Comparing Solvent-Assisted Drainage to Pure Steam In the main picture, a solvent such as butane is being co-injected with the steam. The solvent will be chosen so that it condenses at some temperature that is less than steam but higher than the initial reservoir. At the point where the solvent finally condenses, it mixes with and dilutes the bitumen; bitumen can now drain faster than by steam alone, but at a much lower termperature. The result is that bitumen has been drained from a rather larger volume of reservoir than has been steamed, and so the average temperature of the total depleted zone is now significantly less than that of the steam zone. There are further advantages. One is that the solvent front tends to recover more of the bitumen, leaving a low residual saturation. The other is that production is often faster than with steam alone, meaning that less time is required to deplete. This further increases thermal efficiency by reducing the amount of heat that is lost by diffusion to strata above and below the oil sands.

The above factors combine to provide for SOR and CO2 reductions of up to 50%. Appropriate solvents are limited to the alkanes: propane through about heptane. These are not toxic and occur naturally to some degree in all crude oils. More exotic hydrocarbons such as cyclics or aromatics would be technically superior, but economically prohibitive. As it is, economical use of alkanes revolves around recovering a high percentage of what is injected.

- 15 - As a new company in a position to implement advanced technology, Laricina Energy Ltd. has been researching solvent additives since its inception in 2006. Larina has uniquely applied genetic algorithms to the problem of finding an economic optimum timing, dosage, and composition of additive injection. The company is now constructing its first pilot project, closely followed by a second project in an adjacent reservoir. Both projects will begin with a conventional SAGD steam operation for baseline evaluation, but incorporate solvent injection and recycle for later operations. Additives are expected to reduce the SOR and emissions of these projects by between 25 and 50%, relative to pure steam. An additional positive effect of solvents is to reduce the residual bitumen amounts left in the treated zones, enough to increase bitumen recovery by about 10%.

Conclusions Going forward, most new oil sands development in Alberta will be in situ projects. Environmental impacts from in situ projects are reasonable and responsible in relation to:  absolute/cumulative local impacts  international norms & intensities  an exacting regulatory environment Carbon dioxide emissions from (successful) Alberta in situ oil sands development currently exceed the life-cycle emissions due to conventional crude sources, by about 10-15%. Bitumen produced by mining causes only about 5% excess life-cycle CO2. The efficiency of SAGD (steam) technology is about to get a material boost from solvent additives, cutting emissions by as much as half. In situ plants make natural cogeneration hosts.By replacing coal-fired power, cogeneration renders in situ bitumen carbon-equivalent to any available source of crude.

- 16 -