The majority of oil sands are too deep for surface mining extraction; hence, in-situ techniques such as Steam-Assisted Gravity Drainage (SAGD) must be used. However, SAGD in low-pressure, top water, reservoirs shows relatively poor performance. To improve SAGD, solvent can be co-injected with steam, as in Expanding Solvent SAGD (ES-SAGD) leading to enhanced recovery, rates, and efficiency. Like most pressurized processes, a competent caprock is needed to prevent steam losses to maintain good efficiency and rates. There exist significant oil sand resources that are considered inaccessible because they are shallow (low-pressure) with little or no caprock with top water zones. Solvent addition allows reduced operating pressure, which makes it amenable for low pressure, shallow reservoirs. This research examines ES-SAGD, with non-condensable gas co-injection, in reservoirs with top water that has the potential to quench the chamber and stagnate oil drainage. The results reveal complex dynamics between the depletion chamber and overlying water zone and operating strategies that extend the life of the chamber thus raising the recovery factor. Low-pressure ES-SAGD operating strategies can be used to efficiently recover bitumen from shallow reservoirs with top water. A key finding from this study is that addition of non-condensable gas to ES-SAGD can significantly improve recovery, rate, and efficiency. Given the volume of shallow oil sands reservoirs with top water, development of processes to unlock this type of resource is important and critical to further growth of in situ oil sands recovery in Alberta. The results provide a technical basis to construct feasible low-pressure ES-SAGD processes for this type of reservoir.
Heavy oil and bitumen are expected to become increasingly important sources of fuel in the coming decades. There are extensive deposits in Alberta that could be a principal source of fuel in the coming century. The Athabasca Oil Sands, the largest petroleum accumulation in the world, the Cold Lake oil deposit, and the Lloydminster reservoir are all major Canadian oil sands deposits. SAGD, which has shown considerable promise in all three of these major deposits, remains an expensive technique and requires large energy input. Energy intensity of SAGD and the environmental concerns make it imperative to find new oil extraction technologies.
Co-injecting hydrocarbon additives with steam offers the potential of lower energy and water consumption and reduced greenhouse gas emission by improving the oil rates and recoveries. In a previous paper by the same authors(Hosseininejad Mohebati, Maini et al. 2009), it was shown that the selection of a suitable hydrocarbon additive and the effectiveness of this hybrid process are strongly dependent on the operating conditions, reservoir fluid composition, the heavy oil viscosity, and the petrophysical properties of the reservoir. Among these factors, the heavy oil viscosity which is the most prominent difference between these three reservoirs could be a very important parameter in the performance of this hybrid process. Therefore, it is important to evaluate the effect of oil viscosity on solvent assisted SAGD.
Extensive numerical studies in a 3D model by means of a fully implicit thermal simulator were conducted to evaluate the efficiency of each hydrocarbon additive in Athabasca, Cold Lake and Lloydminster reservoirs. Varying mole percents of hexane, butane and methane were co-injected with steam in with different values of heavy oil viscosity. The effect of oil viscosity on the performance of each solvent was compared in terms of oil production rate and cumulative steam oil ratio.
The majority of the world's petroleum resources are contained in heavy oil and oil sand reservoirs. Average recoveries from heavy oil and oil sand reservoirs are typically low ranging from 5 to 15 percent for cold heavy oil production and from 30 to 85 percent for steam-based in situ processes. There are two reasons for this: first, geological heterogeneity in the form of variable porosity and permeability properties and secondly, fluid heterogeneities in the form of variable saturations, fluid compositions and thus viscosity. Geological heterogeneities refer to spatial variations of porosity, permeability, relativepermeability curves, shale and mud layers, etc. Fluid heterogeneities refer to spatial variations of the fluid composition and properties such as viscosity and density. Given that the permeability often varies by less than an order of magnitude whereas the oil viscosity varies by up to two orders of magnitude in a bitumen reservoir, the controlling variable on recovery of these resources is often fluid compositional variations. Due to the large viscosity contrast between oil and water at native reservoir conditions water is often the most mobile phase within a bitumen reservoir. This research identifies preconditioning techniques that can be used to alter reservoir or fluid (oil or water) properties prior to thermal recovery reducing adverse reservoir factors and improving recovery, environmental impact and process economics. We describe here a simulation study of one application related to modifying the variation of oil viscosity in the reservoir prior to steam injection. The methods make use of mobile water within the reservoir, to distribute viscosity-reducing agents before steam injection, and represent another means of geotailoring recovery processes to the features of the reservoir. The main benefit is that recovery process performance, both in terms of oil production rate and thermal efficiency, is improved.
The need for high-temperature electric submersible pump (ESP) systems is growing as the oil industry matures. Canada's nonconventional oil reserves are estimated at just over 1 trillion barrels and Suncor's heavy oil reserves in northern Alberta, Canada, are estimated to have a potential production of 14 billion barrels of crude oil, but traditional mining methods of recovery do not make them all economically reachable. It is estimated that less than one-fifth of the oil sands resource is mineable. To deal with this, Suncor has turned to in-situ steam-assisted gravity drainage (SAGD) operations as a key part of its plans to increase bitumen supply to its upgraders.
The SAGD approach uses a pair of horizontal wells drilled parallel to each other and separated vertically by a distance of approximately 5 m. Steam injected through the uppermost well penetrates the surrounding formation, heats the heavy-oil sands, and creates a high-temperature region above the injector known as the steam chamber. Heat transferred to the oil sands reduces oil and bitumen viscosity. Gravity forces the oil, bitumen, and condensed steam downward, where these fluids, consisting of about 25-80% water, are produced into the lower well.
Suncor uses SAGD technology to recover 8 to 9 degree API bitumen and heavy oil from unconsolidated sands in the Firebag field. Wells in these fields experience bottomhole pressures of 2000 to 3000 kPa and bottomhole producing temperatures of 180ºC to 209ºC. Whereas standard ESP strings are rated to 149 ºC, bottomhole operating conditions (BOC), key components of the SAGD system featured in this paper, especially its motor, power cables, pump, and advanced protector, are built to withstand bottomhole temperatures up to 218 ºC.
Suncor has installed 21 of these ESP systems, which have enabled a reduction in downhole pressures to improve the steam/oil ratio (SOR). This is a direct reduction in operating and lifting costs, which provides several million dollars in savings by reducing the amount of water that needs to be treated and the amount of fuel burned to generate the steam. Suncor's line of ESP systems has achieved a runlife of more than 500 days.
World Oil Reserves and Demand
There are several sources of information that continually evaluate and discuss world oil reserves. The numbers may differ slightly from source to source, but almost all of them agree on a similar distribution of fossil fuel reserves as shown in Figs. 1 and 2. According to this, the world has twice as much heavy oil and bitumen than conventional oil. It is estimated than there are approximately 8 to 9 trillion barrels of heavy oil and bitumen in place worldwide, of which potentially 900 billion barrels of oil are commercially exploitable with today's technology.
As for oil demand, the International Energy Agency (IEA) projects that global primary energy demand will increase by 1.7 to 2% per year from 2000 to 2030, which is equivalent to two-thirds of the current demand. On the other hand, the supply from relatively cheap conventional sources is declining, and reserves are not being replaced with new discoveries. A conservative 3% of natural decline in production from existing reserves is estimated. While non-conventional oil is emerging as a new major source of oil, even an aggressive worldwide development scenario can only capture 10 to 15% of the required new oil supply in the next 20 years. In addition, nonconventional oil by itself cannot make up for the decline in the world conventional oil production (Isaacs, 2006).
Steam stimulation is one of the viable methods in extracting heavy oil from oil sand reservoirs in Alberta. In this thermal process, mass of steam is injected into the oil sand reservoir. The oil sand formation expands due to pore pressure increase and thermal heating. This expansion results in upward movement of the overburden, and thus heaving of the free ground surface. This paper proposes an analytical method to estimate the surface heave induced by the steam injection. The method was used to investigate the surface heave profiles under horizontal well injection. It was found the surface heave profile is governed by the mass and heat transfer and distribution within the oil sand reservoir. The effect of increase in pore pressure (or decrease in net overburden stress) on the surface heave is also compared to that due to the thermal expansion of oil sand.
Over 90% of the world's heavy oil and bitumen (oil sands) are deposited in Canada and Venezuela. Alberta holds the world's largest reserves of bitumen and the reserves are of the same order of magnitude as reserves of conventional oil in Saudi Arabia. Up to 80% of estimated reserves could be recovered by in-situ thermal operation. As the resources available for conventional crude in Canada continue to decline, further development of heavy oil and oil sands in-situ recovery technologies is critical to meeting Canada's present and future energy requirements.
Sophisticated technologies have been required to economically develop Canada's complex and varying oil fields. Various existing in-situ technologies such as hot water injection, steam flooding, cyclic steaming and combustion processes have been successfully applied in Venezuela and California. Most recently, advances made in directional drilling and measuring while drilling (MWD) technologies have facilitated development of new in-situ production technologies such as the steam assisted gravity drainage (SAGD), expanding solvent-SAGD (ES-SAGD) and solvent vapor extraction (VAPEX) that have significantly improved well-bore reservoir contact, sweep efficiencies, produced oil rates and reduced production costs.
This paper provides an overview of existing and new thermal in-situ technologies and current projects. Potential of new technologies are assessed and compared to various existing in-situ thermal processes. Critical issues affecting production performance are discussed.
Canadian Bitumen Resource
The Canadian bitumen deposits are almost entirely located in the province of Alberta. Three major deposits are defined as Athabasca, Cold Lake and Peace River. Figure 1 shows the major oil sands deposits of Canada. The average depths of the deposits are 300, 400 and 500 m, respectively. Table 1 is a summary comparison of the initial bitumen volume-in-place for the three deposits1. The Alberta Energy and Utilities Board (AEUB) estimate the total initial volume-in-place of bitumen to be 259.1 billion m3. This estimate could ultimately reach 400 billion m3 by the time all exploratory developments are completed. This shows that Canada has the world's largest bitumen deposits. Out of the total volume, 24 billion m3 are available for surface mining techniques. Athabasca deposit is the only deposit with surface mineable reserves. About 376 billion m3 lie too deep to be surface-mined and are exploitable by in-situ technologies. However, approximately 12%, or ~ 50 billion m3 of the total volume-in-place is estimated to be ultimately recovered by existing technologies. That percentage is expected to increase as more advances in recovery technologies are made. Figure 2 shows reservoir characteristics for the three deposits. The Athabasca deposit has Alberta's largest reserve of bitumen that lies in the McMurray formation. The deposit has three layers of oil sands (McMurray, Clearwater and Grad Rapids) separated by shale layers. The deposit is covered by a sand stone overburden and has an area of ~41,000 square kilometers. The Cold Lake deposit is made up of four separate reservoirs that lie in McMurray, Clearwater, Lower Grand Rapids and Upper Grand Rapids and covers an area of approximately 21,000 square kilometers. The oil deposits lie under a thick overburden that prohibits surface mining and can only be produced by in-situ techniques. Most of the Peace River deposit lies under the deepest overburden as compared to Athabasca and Cold Lake deposits. The rich Peace River deposit is contained in the Bluesky and Gething formations. Figure 3 compares Canada's proven oil reserves with those of the world deposits.
Table 2 shows existing and planned in-situ heavy oil and oil sands projects. Table 3 and Figure 4 display the forecast of Canadian crude oil production to the year 20155. This paper focuses on the in-situ production technologies for heavy oil and oil sands (bitumen).
The Alberta Energy and Utilities Board regulates all energy-related operations, including bitumen and heavy oil recovery activities, in the province of Alberta. With the high petroleum commodity prices in recent years, activity and investment levels in this sector have increased dramatically and are forecast to increase even more in the foreseeable future. New and innovative technology is moving rapidly from the laboratories to field implementation to increase recovery rates, improve operational efficiencies and reduce costs.
This paper presents a brief overview of the current regulatory process for the in situ thermal bitumen recovery sector. There is a discussion on the major regulatory issues associated with the in situ bitumen recovery projects. A summary of the bitumen reserve statistics and production forecasts, broken down to the recovery technologies, is also provided.
The convergence of increasing concern about energy supply and increasing public commitment to environmental protection provides an opportunity to mobilize public and private investment in energy innovation. To tap the vast Canadian resource potential, innovative new technologies are required - to unlock the large remaining conventional oil and gas reserves, take advantage of the hundreds of years of production remaining from bitumen, coal, and coal bed methane and ensure increasing supply from renewable energy options. As Alberta's energy innovation strategy was developed, recognition grew that solutions to the pressing challenges described above emerge when we understand the energy industry as one interconnected system, integrated horizontally along the various energy sources and vertically along the value chain. This led to the creation of the Energy Innovation Network (EnergyINet) as the vehicle to facilitate strategic collaboration and innovation among industry, governments (federal and provincial), and the research community to address the challenges of ensuring an abundant supply of environmentally responsible energy. This paper describes, as an example, the approach taken in development of oil sands technologies, where a governmentindustry partnership developed to share resources, build expertise and lower technology risks. This provided the key tools that have lead to the oil sands becoming a significant resource relative to global energy demand. The paper argues that no one single source of energy will be sufficient to meet world or Canadian demand and consequently for the need for a collaborative initiative to facilitate a long-term (20-to 25-year) effort to implement an integrated energy innovation strategy. This integrated approach is built on the premise that strategic investment in a balanced portfolio of energy innovation - with a focus on common technology platforms and points of leverage across the portfolio - has the greatest potential for returns in economic, environmental, and social terms.