Energy consumption and greenhouse gas emissions in the recovery and extraction of crude bitumen from Canada’s oil sands

As traditional petroleum supplies dwindled and prices soared over the past few years, oil companies have shifted their attention to oil sands, a mix of sand, water, and a heavy, viscous hydrocarbon called bitumen that can be converted to oil. With the plunge in oil prices in fall 2008, many producers began canceling or postponing plans to expand oil sands development projects, but this turn of events could yet reverse, as Canada’s vast oil sands deposits are lauded as a secure source of imported oil for the United States. At the same time, however, oil sands present troubling questions in terms of the environmental health effects associated with their development.

Life cycle assessment of greenhouse gas emissions from Canada's oil sands-derived transportation fuels

Energy consumption and greenhouse gas emissions in upgrading and refining of Canada's oil sands products

Energy security and greenhouse gas reductions are thought to be two of the most urgent priorities for sustaining and improving the human condition in the future. Few places pit the two goals so directly in opposition to one another as the Alberta oil sands. Here, Canadian natural gas is burned in massive quantities to extract oil from one of North America’s largest native sources of carbon-intensive heavy oil. This conflict need not continue, however; non-emitting nuclear energy can replace natural gas as a fuel source in an economical and more environmentally sound way. This would allow for the continued extraction of transportation fuels without greenhouse gas emissions, while freeing up the natural gas supply for hydrogen feedstock and other valuable applications. Bitumen production in Alberta has expanded dramatically in the past five years as the price of oil has risen to record levels. This paper explores the feasibility and economics of using nuclear energy to power future oil sands production and upgrading activities, and puts forth several nuclear energy application scenarios for providing steam and electricity to in-situ and surface mining operations. This review includes the Enhanced CANDU 6, the Advanced CANDU Reactor (ACR) and the Pebble Bed Modular Reactor (PBMR). Based on reasonable projections of available cost information, nuclear energy used for steam production is expected to be less expensive than steam produced by natural gas at current natural gas prices and under $7/MMBtu (CAD). For electricity production, nuclear becomes competitive with natural gas plants at natural gas prices of $10–13/MMBtu (CAD). Costs of constructing nuclear plants in Alberta are affected by higher local labor costs, which this paper took into account in making these estimates. Although more definitive analysis of construction costs and project economics will be required to confirm these findings, there appears to be sufficient merit in the potential economics to support further study. A single 500MWth PBMR reactor is able to supply high-pressure steam for a 40,000 to 60,000 bpd Steam Assisted Gravity Drainage (SAGD) plant, whereas the CANDU and ACR reactors are unable to produce sufficient steam pressures to be practical in that application. The CANDU, ACR and PBMR reactors have potential for supplying heat and electricity for surface mining operations. The primary environmental benefit of nuclear energy in this application is to reduce CO2 emissions by up to 3.1 million metric tons per year for each 100,000 barrel per day (bpd) bitumen production SAGD facility, or 2.0 million metric tons per year for the replacement of 700MWe of grid electricity with a nuclear power plant. Should carbon emissions be priced, the economic advantages of nuclear energy would be dramatically improved such that with a $50/ton CO2e at the releases expected for typical projects using natural gas, breakeven gas prices for nuclear drop to less than $3.50/MMBtu, well below the current natural gas price of $10/MMBtu for SADG steam production.

Pitched battles are a regular occurrence in northern Alberta, Canada, as development of the province’s oil sands continues to expand. One ongoing battle—with another salvo launched in February 2011 with the leak of a European Commission report1—concerns how dirty oil sands are, relative to other fuels. Another concerns the influence of the oil sands industry in monitoring its own activity.2 In an effort to cut through the rhetoric of health advocates, industry representatives, environmentalists, government officials, and local residents, the Royal Society of Canada (RSC) selected and covered expenses for an expert panel to winnow out the facts. In a report issued 15 December 20103 the panel cited substantial evidence that efforts to extract oil from the Alberta deposits have degraded air, land, and water quality to varying degrees. The extent of the degradation is sometimes controversial; water quality data, in particular, are subject to differing interpretations and attributions of causality. However, the panel says that, based on publicly available evidence, there appear to be no significant human health threats to the general population either now or from development anticipated in the next decade or so. But the panel also warns that their conclusions come with a major caveat: there are major gaps in health and environmental data, risk assessments, government oversight, information transparency, industry efforts, and disaster preparedness. The health of the region could hinge on these gaps being addressed, particularly since, according to Travis Davies, a spokesman for the Canadian Association of Petroleum Producers, 97% of projected oil extraction and processing is still to come. After the RSC panel reviewed reams of publicly available information on factors such as health status, air and water pollution, greenhouse gas emissions, land disturbance, and energy and water consumption, it concluded that “[t]he claim by some critics of the oil sands industry that it is the most environmentally destructive project on earth is not supported by the evidence. However, for Canada and Alberta, the oil sands industry involves major environmental issues on many fronts which must be addressed as a high priority.”3p293

Effectively addressing today’s energy challenges requires advanced technologies along with policies that influence economic markets while advancing the public good.

The Canadian Energy Research Institute (CERI) completed a study for Atomic Energy of Canada Limited (AECL) that compares the economics of a modified ACR-700 Advanced ™ CANDU Reactor with the economics of a natural gas-fired facility to supply steam to a hypothetical Steam Assisted Gravity Drainage (SAGD) project located in northeastern Alberta. The results were initially presented at the Petroleum Society's Canadian International Petroleum Conference 2003, Calgary, Alberta, Canada, June 10 - 12, 2003. The comparison was made by using discounted cash-flow methodology to estimate the levelized unit cost of steam that could be supplied to the SAGD project from either a nuclear or a gas-fired facility. The unit cost of steam was determined by treating the steam supply facility as a standalone business; it would ensure that all costs are recovered including capital costs, operating costs, fuel costs, and a return on investment. The study indicated that steam supply from an ACR-700 nuclear facility is economically competitive with steam supply from a gas-fired facility. An examination of key variables indicated that the cost of steam from the nuclear facility is very sensitive to the capital cost of the facility, while the cost of steam from the gas-fired facility is very sensitive to the price of natural gas and possible Kyoto Protocol compliance costs. Introduction The Alberta Energy and Utilities Board (EUB) estimated that Alberta's oil sands deposits contain 258.9 109m3 of initial crude bitumen in-place and that over 10% of the initial crude bitumen in-place (28.39 109m3) is recoverable using either surface mining (5.59 109m3) or in situ recovery (22.80 109m3) techniques(1). At year-end 2003, only 2.4% (0.67 109m3) of the initial established reserves had been produced. The EUB reported that, in 2003, Alberta produced 153.2 103m3/d of crude bitumen, with surface mining accounting for 4% and in situ recovery for 36%. In the same year, non-upgraded bitumen and synthetic crude oil accounted for 53% of Alberta's total crude oil and equivalent production. The EUB reported that it expected total mined bitumen production to increase from 97.7 103m3/d in 2003 to 226 103m3/d by 2013, and in situ crude bitumen production to increase from 55.5 103m3/d in 2003 to 139 103m3/d by 2013. Total bitumen production in 2013, 365 103m3/d, would represent a 2.4 fold increase from 2003. Based on the configuration of currently operating projects, it is estimated that achieving this production level could require approximately 60 106m3/d of natural gas in 2013, a significant quantity relative to Alberta's remaining established reserves of 1,087.6 109m3 at yearend 2003 and total production of 140.6 109m3 that year (Reserve Production Ratio of 7.7 years). Using nuclear energy to generate steam would reduce the oil sands industry's reliance on limited natural gas resources, reduce its exposure to volatile natural gas prices, and reduce its greenhouse gas (GHG) emissions. The CERI study updates work carried out over the last two decades regarding the possible application of nuclear technology for oil sands development(2, 3).

Energy infrastructure modeling for the oil sands industry: Current situation

Editor's column PTT Exploration and Production’s (PTTEP) agreement with Statoil to take a share of a Canadian oil sands development is just the latest in a string of deals by Asian oil companies made to gain access to unconventional resources in North America. Firms from China and India bought into projects throughout 2010 looking to gain access to new reserves as well as to gain technical knowhow. Thailand’s PTTEP acquired a 40% interest from Statoil Canada in the Kai Kos Dehseh Oil Sands Project in western Canada in late November for USD 2.3 billion for its debut in the oil sands market. Statoil will keep the remaining 60% of the project. Kai Kos Dehseh has estimated reserves of 4.3 billion bbl and, using steam-assisted gravity drainage (SAGD), is on target to reach early production of 10,000 b/d in the first quarter of this year. Peak output is projected to be 300,000 b/d, which would help PTTEP move toward its goal of more than tripling current production to reach 900,000 BOEPD by 2020. “This acquisition provides the company access to a highly attractive oil sands deposit in Canada and a strong platform for future growth into unconventional resources,” the company said in a statement. This follows deals by China firm Sinopec to buy ConocoPhillips’ stake in oil sands producer Syncrude Canada, China Petrochemical Corp.’s purchase of Calgary-based Addax Petroleum, and PetroChina’s buy-in of a stake in Athabasca Oil Sands’ MacKay and Dover oil sands projects. China first began buying small stakes in oil sands projects in 2005. Asian state oil companies are investing billions of dollars in oil sands projects in Canada and shale plays in the US. The goal is to secure new resources to fuel their booming economies and to learn the techniques and technologies that will help them develop unconventional resources in their own backyards. With oil prices steady above USD 70/bbl, SAGD oil sands projects remain economic and, with gas prices still depressed, independent producers are welcoming the infusion of Asian cash. Shale developments in North America have attracted a string of deals over the past 2 years, the latest being Chinese National Offshore Oil Corp.’s purchase of a one-third stake in Chesapeake Energy’s Eagle Ford shale acreage in south Texas in November. Although reserves estimates for Asia’s unconventionals potential are sketchy, the International Energy Agency puts China’s unconventional gas reserves at 144 trillion cm. Some analysts believe that figure is much higher. Last August, China inaugurated a shale gas research center and set goals of locating 1 trillion cm of recoverable shale gas reserves, building 15 billion cm to 30 billion cm of production capacity, and producing 8% to 12% of China’s natural gas needs from shale by 2020. The US government is also encouraging China’s development of shale in hopes that it will help the country cut carbon emissions.

Small modular nuclear reactors: A pathway to cost savings and environmental progress in SAGD operations

Economic and environmental analysis of a Steam Assisted Gravity Drainage (SAGD) facility for oil recovery from Canadian oil sands

The in-situ extraction of bitumen is one of the most energy-intensive processes and a large natural gas consumer in the Canadian oil sands industry, contributing significantly to Canada’s anthropogenic GHG emissions. In this regard, industry and technology developers are constantly looking for ways to reduce CO2 emissions from their operations through process improvements and more efficient heat production and utilisation. Post-combustion carbon capture (PCC) is one of the solutions available to achieve significant GHG reductions. This work focuses on improving the energy performance of integrated steam-assisted gravity drainage (SAGD) processes with PCC technologies. Three typical SAGD configurations have been selected, all with different water treatment and steam generation systems that are representative of active facilities, and simulated using Aspen HYSYS®. Analysis of the selected SAGD configurations revealed that significant energy savings and GHG reductions could be achieved through optimised heat recovery. The proposed retrofit projects could decrease natural gas consumption for steam generation by up to 10%. Then, several PCC technologies were considered to analyse the systems aspect when integrated into SAGD facilities, with a view to maximising the synergies between the two processes from an energy and water standpoint. The results revealed that the SAGD process configuration, the type of PCC technology, and the level of heat integration within the SAGD plant have a direct impact on the amount of CO2 that can be captured.

There is a major concern that the existence of thief zones such as top water and/or gas cap overlying the oil sand deposit has a detrimental effect on the oil recovery in the application of the steam-assisted gravity drainage (SAGD) process The objective of this numerical study is to investigate the SAGD performance in the Athabasca oil sands in the presence of a top water zone. The reservoir model, STARS, developed by the Computer Modelling Group (CMG) Ltd. has been previously validated based on a 3-D SAGD laboratory experiment with top water that was conducted at the Alberta Research Council (ARC). It is believed that the numerical simulation captured the major mechanism of oil movement from the pay zone into the top water zone as observed in the experiment. In the field-scale simulation, SAGD performance in the presence of confined and non-confined top water zones was investigated. The operating strategies under the conditions of non-depleted top water/non-depleted pay zones and depleted top water/non-depleted pay zones were considered. Numerical findings indicated that:there is detrimental effect of top water zone on SAGD performance,plugging of top water zone with oil was not observed in this study for a top water thickness of 8 meters, andoperating conditions that lead to higher pressure difference between the steam chamber and the top water, either by depletion of the top water zone pressure or a higher steam injection pressure, results in more detrimental effect on the SAGD performance. Introduction There is a major concern by Alberta oil producers that the production of natural gas in association with oil sands would lower reservoir pressure, reduce oil recovery and may be prohibit economic oil recovery. Alberta Department of Energy (ADOE) and Alberta Energy and Utilities Board (AEUB) initiated a series of field-scale numerical modeling studies1,2 to assess the potential applicability of the steam-assisted gravity drainage (SAGD) oil recovery process under a variety of reservoir conditions such as reservoir thickness, reservoir depth, initial pressure, oil saturation, and the presence of top water zones and gas caps. It was found that top water zones and gas caps are thief zones to SAGD process. These thief zones have a detrimental effect on SAGD recovery performance especially when the pressure in the thief zones is reduced below optimum SAGD operating pressures due to natural gas production. Movement of oil into the top water zones and gas caps is simulated to occur. The volume of this oil seems to be generally proportional to the amount of outflow from the pattern due to thickness of the top water zones/gas caps and the pressure difference between the steam chamber and the top thief zones. SAGD process costs depend on the amount of steam that flows into the top water zones and gas caps, from which no oil is produced. A case in point is the Gulf Surmont oil sands lease. The lease has a gas cap and a mobile water zone overlying the pay zone. An observation well indicates that gas cap pressure at the pilot site fallen from 1,327 kPa to 858 kPa over 3 years due to production of the gas. It is estimated that the pressure may fall to less than 300 kPa when the gas wells will be abandoned. Based on the geology and pressure measurements, there is communication between the gas cap and the pay zone. This indicates that the gas cap may be a thief zone to the SAGD process at the site. It is also believed that the mobile top water zone may extend the area of influence of the pressure-depleted gas caps.

In this paper, we used the life-cycle analysis (LCA) method to evaluate the energy consumption and greenhouse gas (GHG) emissions of natural gas (NG) distributed generation (DG) projects in China. We took the China Resources Snow Breweries (CRSB) NG DG project in Sichuan province of China as a base scenario and compared its life cycle energy consumption and GHG emissions performance against five further scenarios. We found the CRSB DG project (all energy input is NG) can reduce GHG emissions by 22%, but increase energy consumption by 12% relative to the scenario, using coal combined with grid electricity as an energy input. The LCA also indicated that the CRSB project can save 24% of energy and reduce GHG emissions by 48% relative to the all-coal scenario. The studied NG-based DG project presents major GHG emissions reduction advantages over the traditional centralized energy system. Moreover, this reduction of energy consumption and GHG emissions can be expanded if the extra electricity from the DG project can be supplied to the public grid. The action of combining renewable energy into the NG DG system can also strengthen the dual merit of energy conservation and GHG emissions reduction. The marginal CO2 abatement cost of the studied project is about 51 USD/ton CO2 equivalent, which is relatively low. Policymakers are recommended to support NG DG technology development and application in China and globally to boost NG utilization and control GHG emissions.

The fundamentals of Steam Assisted Gravity Drainage (SAGD) steam chamber development are now well understood through Butler's analytical models, as well as extensive field and laboratory testing. However, as the industry continues to extend SAGD to new reservoirs and look towards SAGD wind-down at the end life of projects, it is important that we recognize the value of not only understanding the steam chamber, but also of the movement of fluid in the reservoir. The Dover SAGD Pilot is the most mature pilot of its kind in the world. A study of this project has been undertaken in an attempt to understand the behaviour of the fluid within and in front of the steam chamber. The economics of SAGD are significantly impacted by the cost of generating steam. At roughly 283.17 m3/bbl (1 mcf/bbl) of bitumen produced for a steam-oil ratio (SOR) in the range of 2.3 to 2.5 m3/m3, natural gas is the single largest operating cost in a SAGD project. Water movement within the reservoir can impact the natural gas consumption, whereas warm steam condensate not reproduced must be replaced in the process by colder make-up water decreasing the heat efficiency of the steam generation. Further, where water loss to the reservoir is high, the SOR may be negatively impacted. On the 20th anniversary of the initiation of the Dover Pilot, the cold water injection test performed prior to any thermal operations taking place is revisited here. Understanding the transmissibility of water in the reservoir is key to choosing the optimal operating pressures and maximizing the value of a project. It has been widely published(1,2) that the injection of non-condensable gas (NCG) into SAGD chambers will result in the accumulation of the NCG at the top of the chamber, cooling the chamber. The lower temperatures within the chamber cause the viscosity of the bitumen to increase, thereby reducing the bitumen production rate. This has been suggested as a method of winding down steam chambers as they reach their economic producing limits(3–5). From April 1998 to May 2002, NGC was injected with steam at the Dover Pilot. The gas volume injected was triple the volume of the produced bitumen over that time. The SAGD chambers did not behave as predicted. The bitumen production rate did not fall off any more than would be expected from a mature steam chamber and live steam was still detectable through the thermocouples within the steam chamber. Furthermore, an increased overall recovery was observed, most likely from gas assistance in the production of previously inaccessible reserves. The simulation model developed to describe the behaviour of NCG in the reservoir, as well as further observations regarding this behaviour, are discussed. Introduction Geographically located in northeast Alberta, the Athabasca oil sands deposit forms part of the Western Canadian oil sands. With an estimated 1.7 trillion barrels of oil-in-place, it is arguably the single largest oil deposit in the world. SAGD, developed by Butler in the early 1980s(6) is, to date, the most successful in situ method of exploiting this resource.