Abstract Large reserves of heavy crude oil and bitumen are waiting for novel technical recovery developments. Nevertheless, the very low API gravity and impurities such as sulphur and nitrogen of the reserves, influences the economics of their industrial utilization. In situ catalytic upgrading of heavy oil and bitumen has been proposed and tested in laboratory scale experiments. Experimental evidence from laboratory scale tests are very promising and this novel technique can play an important role in the exploitation of huge resources of heavy oil and bitumen. Accurate analytical and numerical modeling is essential in order to correctly interpret experimental measurements of the in situ upgrading. This work will enhance the understanding and design of field scale processes. In this paper, simulation results of bitumen ultra-dispersed catalytic upgrading experiments in a batch reactor area reported. The results show that ultra-dispersed catalytic upgrading results in relatively high residue conversion and can potentially increase the API gravity of the produced oil. These results hold significant promise for upgrading heavy crude oils and bitumen using an ultra-dispersed catalyst. Introduction The decline of light oil reserves has made the recovery of heavy oil and bitumen an attractive substitute supply for the world's ever increasing energy demand. Large reserves of heavy crude oil and bitumen are waiting for a novel technical recovery development. The very low API gravity and impurities such as sulphur and nitrogen, in these reserves influences the economics of their industrial utilization. The selection of enhanced oil recovery (EOR) processes to produce such vast resources of heavy crude oil and bitumen depends on technological and economical considerations. Several field scale EOR techniques have been utilized in the past to exploit such huge resources. These EOR techniques include thermal and non-thermal methods. Thermal methods include Steam Assisted Gravity Drainage (SAGD), Cyclic Steam Stimulation (CSS), steam injection, In Situ Combustion (ISC), and their variants. Non-thermal methods include miscible flooding, chemical flooding, and their variants. Canada is producing about 14% of the total oil produced by the EOR methods. These are most commonly recovered using thermal operations. (1) The Energy Information Administration (EIA) states that the sulphur content and density of refineries input in the United States has been steadily increasing. (2) To improve the refineries feedstock input quality, the incoming heavy oil needs to be upgraded prior to conventional refining. Heavy oil and bitumen with low API gravity can be made more valuable if they are upgraded to meet the current conventional refining specifications. Surface upgrading of heavy oil and bitumen which is a capital and energy intensive technology has been practiced in Canada. Due to the high capital investment and energy requirement for surface upgrading downhole upgrading of heavy oil has been proposed. (3), (4), (5) Down-hole upgrading makes it possible to recover and upgrade immense heavy oil resources without using large volumes of water, burning natural gas, or emitting greenhouse gases. In situ upgrading of heavy oil and bitumen has been reported both in field scale operations and in laboratory scale experiments.

Abstract A method, based on factual observations of naturally fractured reservoirs in several countries is presented for estimating distribution of hydrocarbon cumulative production in wells drilled in fractured reservoirs of types A, B or C. These observations indicate that in reservoirs of type C most of the cumulative production is provided by just a few wells while the majority of the wells contribute a small part of the reservoir cumulative production. In reservoirs of type B the number of wells contributing significantly to cumulative production becomes larger relative to the case of type C reservoirs. Finally in reservoirs of type A, a large number of wells contribute to field production, as compared with type B reservoirs. The method is shown to be useful for tackling problems of practical importance in naturally fractured reservoirs including, performing or not infill drilling, estimating the variation in cumulative hydrocarbon production per well in a given reservoir, and estimating the number of wells that might be required for a given field hydrocarbon recovery. The method is illustrated using data from various fractured reservoirs, including the Barnett shale and sandstone reservoirs in the United States, carbonate reservoirs in Mexico and Venezuela, and coalbed methane reservoirs and tight gas sands in Canada. Introduction Methods for estimating the optimum number of wells in a given reservoir have been available for over 80 years (Haseman, 1 1929). More recently Nelson 2 (2001) analyzed cumulative production per well in individual naturally fractured reservoirs and found that there are distinctive variations in the production distributions depending on the amount of natural fracturing and heterogeneity present in the reservoir. From this observation Nelson concluded that these distributions are a function of fractured reservoir type, something that has been corroborated by this author in several instances as discussed in this study. Figure 1 shows the ABC classification of naturally fractured originally introduced by McNaughton and Garb 3 (1975). In naturally fractured reservoirs of Type A the storage capacity in the matrix porosity is large compared with storage capacity in the fractures ( Figure 1A ). This is generally equivalent to a reservoir of type 3 in Nelson's classification (2001). For this case, it can be seen in the lower part of Figure 1A that a small percentage of the total porosity is made out of fractures. In general, this situation would tend to occur in reservoirs where the matrix porosity is rather high (larger than 10 up to more than 35%). However, there are exceptions. For example reservoirs in tight gas formations can be generally classified as being of type A even if their porosity is usually smaller than 10%. If the matrix has some permeability so as to allow flow into the wellbore, Type A reservoirs can be considered equivalent to what Nelson (2001) has called "fracture permeability assist" reservoirs, i.e., reservoirs where the fractures contribute permeability to an already producible reservoir. Figure 1B shows a schematic of rocks with about the same storage capacity in fracture and matrix porosity (Type B reservoirs).

Abstract Material balance has long been used in reservoir engineering practice as a simple yet powerful tool to determine the Original-Gas-In-Place ( G ). The conventional format of the gas material balance equation is the simple straight line plot of p /Z versus cumulative gas production (G p ) which can be extrapolated to zero p /Z to obtain G . The graphical simplicity of this method makes it very popular. The method was developed for a "volumetric? gas reservoir. It assumes a constant pore volume of gas and accounts for the energy of gas expansion, but it ignores other sources of energy such as the effects of formation compressibility, residual fluids expansion and aquifer support. It also does not include other sources of gas storage such as connected reservoirs or adsorption in coal/shale. In the past, researchers have introduced modified gas material balance equations to account for these other sources of energy. However, the simplicity of the p /Z straight line is lost in the resulting complexity of these equations. In this paper, a new format of the gas material balance equation is presented which recaptures the simplicity of the straight line while accounting for all the drive mechanisms. It uses a p /Z ** instead of p /Z. The effect of each of the mentioned drive mechanisms appears as an effective compressibility term in the new gas material balance equation. Also, the physical meaning of the effective compressibilities are explained and compared with the concept of drive indices. Furthermore, the gas material balance is used to derive a generalized rigorous total compressibility in the presence of all the above-mentioned drive mechanisms, which is very important in calculating the pseudo-time used in rate transient analysis of production data. Introduction It has been of great interest to find the original-gas-in-place by using material balance. The conventional gas material balance equation was developed for a "volumetric? gas reservoir. Therefore, the p /Z versus cumulative gas production plot may give misleading results in some situations e.g. when the formation compressibility is of the same order of magnitude as gas compressibility (overpressured reservoirs) or where desorption plays a role (CBM/shale). Figure 1 shows p /Z versus G p for several scenarios with the same original-gas-in-place ( G ). It can be seen from this figure that except for the volumetric reservoir, the plot is not a straight line, because gas expansion is not the only drive mechanism. In fact, water encroachment in water-drive reservoirs, formation and residual fluid expansion in overpressured reservoirs and gas desorption in coalbed methane (CBM) or shale reservoirs can have a significant role as a driving force in these cases. In these situations, where the gas expansion is not the dominant driving force, modified material balance equations have been developed by several researchers. Among them, Ramagost and Farshad [1] modified the conventional material balance equation to account for pore volume shrinkage due to formation and residual fluid expansion and introduced a new plotting function that keeps the material balance as a straight line. So that the modified material balance equation can be used for overpressured reservoirs.

Abstract Reservoirs of Shu-one area of Liaohe oilfield Company of Petro China reserves extra heavy oil. The reservoirs are characterized in high porosity, high permeability, thick pay, bedded formation, relatively shallow burial, low original reservoir pressure and pressure and bad physical properties of crude oil. CSS is implemented in production. Casing failure often occurs due to short production time in a cycle, frequent steam injection and sanding-out of formation after several cycles of huff & puff. Mechanism studies in casing failure presented in this paper shows that the frequent variation of thermal stress as well as non-uniform loading over the perforation intervals due to sanding-out are major causes for casing failure. Casing with thicker wall and higher steel grade is used in well completion along with thermal stress compensator, prestressed casing and end locker. This increases casing collapse resistance capacity and resists casing failure due to nonuniform loading due to sanding-out. Casing life is extended significantly due to reduced casing failure through the use of advanced well completion technologies, resulting in improvement of development efficiency of the extra heavy oil. Introduction Reservoirs in the Shu 1 area of Liaohe Oil Field of China are abundant in extra heavy oil resources with OOIP in amount of greater than 100 millions tonns. He reservoirs are characterized in high porosity (about 25%), high permeability (about 1.0 µm2) and relatively thick pay (40 ∼90m). The major recovery technology is Huff & Puff. The current production capacity is over 2 millions of tonns annually. The development of extra heavy oil resources in the Shu 1 area started in 1996. Well completion techniques have been continuously improved in order to fit for Huff & Puff production scheme of the extra heavy oil. In the early development stage from 1996 to 1999, N80 casing was adopted as production casing and P110 casing was used in the perforation interval as a measure to prevent from deformation. The results were not satisfying with the application, the average casing deformation occurrence was at the 3.5th cycles and 80% of the wells were deformed. A detailed study and experimental test were carried out from 1999 to 2000 and a non-API specification casing of steel grade TP100H was developed. The performance of all major parameters was improved significantly (Table 1). It can be seen from Table 1 that the average number of cycles before casing deformation extends to 5.1, the percent of casing deformation declined to 47.8% and maintained no change until 8 cycles. although the casing deformation was under control, it can't satisfy the requirement of oil field development. An effective way to extend casing's life should be found. Characteristics of Casing Deformation in the Extra Heavy Oil Wells According to the statistical data analysis, casing deformation in the extra heavy oil wells is characterized as following: Casing deformation frequently occurred in the 3rd to 7th cycle. Based on the statistical data from 493 wells with casing deformation problems, it is found that the casing deformed for 344 wells occurred from the 3 rd to 7 th cycle, accounting for 70% of the total casing-deformed wells (Fig. 1).

Abstract Thermal recovery methods (such as steam injection) are recent remarkable technologies to recover bitumen from oil sands. The injected steam contacts the oil sand and forms an interface. The steam changes to water transferring its heat to bitumen across this interface. The heated bitumen will have a lower viscosity, mobilize and recover from the reservoir. Study on hot water-bitumen interfaces should be crucial in understanding the thermal recovery methods. The strength and energy of hot water-bitumen interfaces are expected to play important roles in the recovery of bitumen from oil sands. However, measurements on hot water-bitumen interfaces are not apparent in the literature. A relevant measurement would be the contact angle and interfacial tension of the waterbitumen interfaces at different temperatures. In this paper, it has been attempted to reveal and present the results of several water-bitumen contact angle and interfacial tension measurements. The measurements cover a temperature range from ambient to 100 ° C for a given pressure. The experiments are run in x-ray transparent cells and images are taken using a micro-CT scanner. The results of contact angle and the interfacial tensions of hot water-bitumen interface are produced by using the axisymmetric drop shape analysis (ADSA) method. Introduction Thermal recovery of bitumen causes many changes in the oil sand reservoirs and in fluids properties such as viscosity, density of each fluid, interfacial tension and wettability of the aqueous-hydrocarbon and rock-fluid interfaces. Wettability measurement in the oil recovery industry is quite popular and several different methods have been used to characterize the wettability of different reservoirs. These methods are reviewed in detail by Anderson (1) . They are generally categorized in two major groups; qualitative and quantitative methods. Common qualitative methods for wettability measurement are imbibition rates, microscope examination floatation, glass slide method, relative permeability curves, permeability saturation relationships, capillary pressure curves, displacement capillary pressure, reservoir logs, nuclear magnetic resonance (NMR) and dye adsorption. Quantitative methods include contact angle, spontaneous and forced imbibition (Amott) and USBM wettability method. According to Anderson (1) the contact angle method is used to measure the wettability of a certain surface, but the Amott and USBM methods are used for core wettability measurements. Quantitative methods are more commonly used; nevertheless, there is no single universally accepted method. Contact angle (Θ) is the angle at which a fluid-fluid interface meets the solid surface. The Θ is always measured relative to the denser phase. In this work, water is the dense phase. The contact angle method is very useful for wettability measurement when working with clean surfaces and pure fluids. Typically contact angle measurements are done on oil-waterquartz surface systems in order to study the wettability variations under different temperatures and pressures. For the measurement of Θ two immiscible fluids are placed on a solid surface; fluid 1 is the denser fluid. (Θ) can vary between 0 ° and 180 °. If Θ is less than 75 °, fluid 1 is the wetting phase and if Θ is more than 105 ° fluid 2 is the wetting phase.

Abstract Canada's oil sands are well recognized internationally, with Alberta's mined and in situ oil sands reservoirs being well developed with mature commercial technologies. The next frontier in Canadian petroleum development will be the shallow in situ oil sands residing in both Saskatchewan and Alberta. Presenting opportunities and challenges that are distinct from the mining and deeper in situ reservoir situations, the shallow reservoirs will probably need to be developed with new "gamechanger" in situ technologies that will reduce and/or replace the use of steam, reduce the use of fresh water, and dramatically reduce the emissions of greenhouse gases such as CO 2 . Significant R&D programs are now aimed at developing and demonstrating such new technologies. Piloting new shallow in situ development technologies for Saskatchewan's oil sands deposits will enable a new source of Canadian "technology oil" and serve to test more environmentally friendly technologies that could be adapted to current commercial operations. This paper will provide a detailed description of the oil sands geology and physical properties as well as highlighting Saskatchewan's oil sands and some of the novel recovery technologies that are being developed for shallow in situ reservoirs. Introduction The world liquid petroleum (oil) resources are huge, comprising over 600 billion m 3 (about 4 trillion barrels). Of this around half, about 320 billion m 3 , is represented by the bitumen contained in oil sands. The remainder is made up of conventional medium and light gravity crude oil. A practical basis for distinguishing among conventional light crude, heavy crude, and bitumen is given in Table 1. As the data in Table 1 show, conventional light and heavy crude oils can flow at reservoir temperatures. Athabasca bitumen, whose viscosity at reservoir temperature is over 1 million mPa.s is essentially immobile. A significant fraction of the world's conventional crude oil and most of the world's bitumen is contained in the Western Canadian Sedimentary Basin. Bitumen comprises the majority of Canada's liquid petroleum resources (see Table 2) at about 410 billion m 3 (2.6 trillion barrels), of which only about 28 billion m 3 are considered to be reserves, that is, economically recoverable with current technology [1] . Current daily oil (bitumen and synthetic crude) production has risen to 180,000 m 3 (1.1 million barrels) which represents about 40% of crude oil produced in Canada. The bitumen production in Canada is expected to more than triple by 2030 based on a moderate growth case [2] and taking into account the current economic slowdown. In a time of the peaking of conventional oil production and an expansive growth in energy demand the search for new oil reserves has led to unconventional in situ bitumen and heavy oil resources, for which operators are moving into substantially more challenging reservoirs than ever before. Schramm and Isaacs [3] have used the term "technology oil" to describe the products derived from oil sands and heavy oil reservoirs because technology development has been the key to allow these hydrocarbons to be produced at competitive costs.

Abstract The bitumen contained in Axe Lake Discovery in Saskatchewan has very high viscosity, well over 10 million centipoises under original reservoir condition. Since bitumen viscosity decreases with increasing temperature even at low temperatures, and since the Axe Lake reservoir is highly permeable and extremely coarse grained, preliminary reservoir simulations indicated that it is possible that effective, early time, communication between production wells at the bottom of the reservoir can be established by efficient low energy heating and intermittent water pressure pulsing. In order to evaluate the heating concept, we measured the response of the reservoir to heating with down-hole heaters at low temperatures (100 °C). A description of the field test is provided. Different analytical formulations and simulation models were used to analyze the results of the field test and the analyses were compared to prior published work. Field results were also used to determine effective thermal conductivities and effective mobilities at low temperatures for different grid sizes using Cartesian, radial and hybrid simulation grids. A comparison to analytical heat transfer formulations under different boundary conditions is discussed. Calibrated simulations show that not only can the heater be used to preheat the formation but also as an efficient bitumen viscosity reduction tool to increase bitumen mobility during the full bitumen production life of the reservoir. Moreover, high temperature heaters can be combined with cold water injection to generate steam in the reservoir directly. The paper concludes with a simple analysis which shows that such a combined technology can produce bitumen more efficiently and economically when compared to conventional SAGD. Introduction Axe Lake Discovery is located in northwestern Saskatchewan, about 90 km northeast of Fort McMurray. The bitumen reservoirs are buried about 200m below the surface. The bitumen is quite heavy and highly viscous, with a viscosity of over 10 million centipoises at original reservoir condition. Since bitumen viscosity decreases when the temperature rises, thermal technologies such as steam and hot water injection have become the preferred means for bitumen recovery. However, the bitumen reservoir at Axe Lake is relatively shallow and the efficient recovery of bitumen may be not possible using high pressure steam and hot water injection. Preliminary reservoir simulations indicated that it is possible to establish effective communication between producers at early time by efficient low energy heating and intermittent water pressure pulsing. Measuring the response of the reservoir to heating with downhole heaters at low temperature 100 °C, a two-stage test was planned and the second stage is currently being implemented. Different analytical formulations and simulation models were used to analyze the results of the measurement. The effective thermal conductivity and mobility of the bitumen at low temperature will be obtained from the results. Simulation studies also indicated that it was possible to obtain bitumen recovery effectively and economically using high temperature down-hole heater combined with cold water injection. This method takes advantage of simple and safe surface facilities and without losing heat outside the wells when compared to conventional steam injection from the surface.

Abstract Electro-thermal methods are being used for extraction of bitumen from the oil sands. Several processes have been tested or are being proposed. Shell has proposed the use of electro-thermal methods in the carbonates and have tested a process at their Shell Peace River operation. E-T Energy is using an electro-thermal process in the Athabasca Oil Sands. Other institutions and companies, for example, the Alberta Research Council has also developed electro-thermal approaches for bitumen recovery. The heat transfer mechanisms, either from horizontal or vertical wells, associated with the electro-thermal approach distinguishes the various methods. In some of the approaches, heat transfer by conduction is the dominant method of transferring heat to the reservoir. In other methods, heat is generated within the reservoir electrically and transferred conductively, and in other processes convection is a key heat transfer mechanism in combination with the others. The purpose of this paper is to present a model for radial heat transfer that can be used to compare different electro-thermal heating methods. The model compares the resulting temperature distribution, time to achieve a heated volume at some distance away from the wellbore, and the power density in the reservoir between the different electro-thermal methods. Also, insight into design issues, such as well spacing and input power requirements, as well as practical matters related to efficiency, near wellbore heating, and water vaporization are presented. Introduction Oil reservoirs are a mixture of sand, bitumen and water. In Alberta, most of the oil is heavy or bitumen (from the oil sands) and cannot be produced easily from the reservoir. Electro-thermal methods are presently being considered for mobilizing bitumen from the oil sands. Bitumen is defined as oil that is less than 10 API and will not flow to a well in its naturally occurring state. Steam assisted gravity drainage (SAGD) is a promising in-situ thermal recovery method, having the advantages of lower energy requirements and higher recovery factors over other steam injection methods. However, about two thirds of the total deposit is too deep for surface mining and too shallow for steam injection [4] as depicted in Figure 1. These shallow resources may be well suited for electro-thermal processes. Also, electro-thermal methods have the potential to produce bitumen from oil sands that are at the mineable depths [2]. All in-situ thermal recovery methods as applied in oil sand deposits have the common objective of accelerating the hydrocarbon recovery process. Raising the temperature of the host formation reduces the bitumen viscosity allowing the near solid material at original temperature to flow as a liquid. These effects assist in sweeping the bitumen to be recovered from the formation when driving agents are externally injected or when autogenous processes, such as gravity drainage come into play. Conduction Methods that use electro-thermal energy to increase the temperature of the wellbore without current flow in the reservoir have been also been developed. This is the first configuration shown in Figure 2. Electric heater elements are placed within the wellbore and are operated at very high temperatures.

Abstract Coke formation from heavy oil has been extensively studied and various kinetic models have been proposed in the literature. In this study, thermal behavior of crude oil and its asphaltene obtained from Fosterton field was investigated using thermogravimetric analysis. Non-isothermal pyrolysis experiments of whole oil and its asphaltene was performed in nitrogen atmosphere at different heating rates of 5, 10, 15 and 20 ?C/min. Although, much difference was not observed in the weight loss profile for whole oil and its asphaltene, the final amount of coke formed changes with the heating rate. Nonisothermal experiments were better described by Distributed Activation Energy Model (DAEM) compared to other applicable models. The non-isothermal pyrolysis kinetics of whole oil and its asphaltene were studied with DAEM equation. The activation energy for whole oil pyrolysis spreads over a range from 7 to 129 kJ/mol and the pre-exponential factor varies from 10 2 to 10 11 min −1 . The asphaltene fraction separated from the oil has the activation energy from 50 to 183 kJ/mol and the pre-exponential factor ranges from 10 7 to 10 14 min-1. Results from the kinetic analysis suggest that asphaltene requires more activation energy compared to the whole oil. Introduction Thermal cracking of heavy oil feedstocks results in the formation of a wide range of gaseous, liquid and solid products. During pyrolysis, several reactions take place, which influence the overall kinetics and the resulting coke formation. It is well known that thermal treatment of hydrocarbons follows a free radical mechanism, where cracking reactions take place in the initiation step, condensation and polymerization reactions comprise the final step [1]. The final step reactions explain the formation of products such as coke. Among the SARA fraction present in the whole oil, asphaltenes are precursors of coke formation. Asphaltenes are complex associated species typically isolated as a solubility class obtained by precipitation with a weak solvent [2]. Coke formations from both whole oil and its fractions like asphaltene have been extensively studied [3, 4]. However, the coke formation characteristics vary with the different sources of oil. The kinetics of the thermal decomposition of various oil from different regions of the world, have been investigated and various suggestions as to the decomposition mechanism have been reported [5, 6]. Many thermogravimetric studies have been carried out under isothermal conditions, but this method involves some inaccuracies. It is more accurate to use a nonisothermal method to determine the kinetic parameters of the pyrolysis process, employing a TGA apparatus, with the sample heated at a constant rate and recording its weight change. This is mainly because of the shorter experimental time and the fewer encountered difficulties. But the principal reason for their popularity in the field of oil pyrolysis is that it more closely simulates the conditions expected in commercial scale. Thus, such a technique for determining the reaction kinetics, such as activation energy, has been preferred by many researchers [7–9]. Hence, the kinetics of thermal degradation of whole oil and its asphaltene from fosterton region can be obtained using a TGA apparatus.

Abstract The majority of SAGD development to date has been concentrated in the McMurray Formation in the Eastern Athabasca fairway. More recently operators have identified projects with considerable resource located in shoreface sands of the Grand Rapids Formation in the Wabasca area. Laricina Energy's Germain thermal project in the Grand Rapids has associated basal water underlying much of the reservoir. In this paper the authors show that SAGD can be configured to maximize bitumen recovery for such reservoirs based on laboratory and new simulation studies. The result is a SAGD configuration where the producers are placed at the base of porosity, within the basal water zone. Introduction Laricina Energy Ltd.'s Germain project is located in the West Athabasca Oil Sands region approximately 100 km southwest of the community of Fort McMurray. Positioned in Townships 83–85, Ranges 21–22, west of the 4th Meridian, the total land base in the area is 63 sections. The primary zone of interest is the Grand Rapids Formation. It is estimated that there are approximately 2.5 billion barrels of bitumen in place with a thickness greater than 10 m within the lease area in the Grand Rapids Formation. The upper Grand Rapids sand is a regional marine deposit at an average depth of 225 m. Its unique features – clean sand with homogenous and continuous reservoir pay – results in a predictable and consistent reservoir that extends across many townships. A thin bottom water leg in communication with the bitumen is present throughout much of the lease. The Germain project is in an area that, to-date has been mainly explored and developed for natural gas production from zones other than the Grand Rapids with a few oil sands evaluation wells drilled in the region in the 1970's. Due to the significant increase in activity of oil sands projects in general, the development of oil sands in the Wabasca region is just beginning. Currently, two operators have significant nonthermal heavy oil production in the region from the Wabiskaw Member of the Clearwater Formation. Laricina Energy has submitted an application for regulatory approval to build and operate a steam assisted gravity drainage (SAGD) project in the Germain area. The current development plan is a phased approach starting with a small commercial demonstration project followed by commercial development that will increase production to over 100,000 barrels per day of bitumen. Geology Figure 1 describes the general stratigraphy in the area of Laricina Energy's Germain project. In north-east Alberta, the Mannville Group, composed primarily of unconsolidated clastic sedimentary rocks, is divided into three formations. From oldest to youngest these formations arc: the McMurray. the Clearwater. and the Grand Rapids. The Mannville sediments rest unconformably on the carbonates of the Devonian Wintcrbum Group. The unconformity at the base of the Mannville was formed during a period of subaerial exposure and erosion. The Mannville Group is conformably overlain by the Cretaceous Joli Fou Formation shales and Viking sand. The overlying Colorado shales are usually truncated by Quaternary glacial deposits.

Abstract Dual-porosity and dual-permeability naturally fractured reservoir models assume that the fractures in the reservoir are connected with each other and distributed uniformly. However, in some cases, the reservoir characteristics exhibits discrete fracture systems, which means that the fractures might be unconnected and their distribution is not uniform. In this work, a new computational model is developed to compute the transient pressure behavior for reservoirs with discrete fracture system. This computational model is based on Laplace transform. The fluid flow in the fracture system and reservoir are computed separately and flux and pressure equivalent conditions in Laplace space are applied in the fracture wall to couple the fluid flow in both systems. The results suggest that the pressure response in a reservoir with a discrete fracture system has three flow regions: fluid flow nearby the wellbore, fracture-dominated fluid flow and fluid flow beyond the fracture. The fracture orientation (i.e. the distance between the fracture and the well), fracture parameters (fracture conductivity and non-Darcy effects) and fracture distribution are the main factors affecting the pressure response. In some particular situations the fracture-dominated fluid flow region in the pressure derivative curve may present two villages, which has been met in some field cases. The model provides with a tool for identifying the fracture pattern in a specific reservoir. Also, this model can be applied for optimization design of tight gas reservoir development. Introduction Classically, the fractured reservoir is modeled with Dual porosity model (1) or dual-permeability model. Those models assume that the fractures are connected with each other and distributed uniformly. The dual-porosity model also assumes that the fluid is produced from the fractures which are intersected with the well. However, in some cases, the reservoir characteristics exhibit discrete fracture system, which means that the fractures may be unconnected and their distribution is not uniform. Such kind of reservoir system was illustrated by Gao et al. (2) , as shown in Figure 1. Gao et al. (2) , also pointed out that the chance for a vertical well to intersect a discrete natural fracture is extremely small, since natural fractures in a reservoir tends to be vertical. Another type of discrete fracture system is artificial fracture system in tight gas reservoirs. To obtain economical production rate, most of wells in a tight gas reservoir are hydraulically fractured. Therefore, the whole reservoir looks like an artificial discrete fracture system. In this work, it is assumed that the discrete fracture system has the following characteristics, The fractures in the reservoir are discrete and not connected with each other; Each fracture can be described with its orientation, geometry and diffusivity; The well is not intersected with any fracture; and, 4. The fluid flow in fracture system obeys Forchheimer equation and the fluid flow in matrix system is Darcy flow. Zeng and Zhao (3) presented a model for non-Darcy flow in hydraulic fractures. For a reservoir with only one fracture existed, if the fracture is close enough to the well, then the system is similar to the system with a hydraulically fracture well.

Abstract Relatively new bitumen recovery processes, such as SAGD, minimize the environmental footprint in terms of land disturbance and water demands. However, as a corollary, air monitoring becomes more difficult. In particular, monitoring for sulphur and nitrogen oxides, as currently practiced, suffers from significant limitations in remote regions, such as the Canadian oil sands areas. Current techniques require the placement of monitoring trailers in accessible locations, but the electrical power or even access for optimal location for trailers is not always given. In addition, the trailers are capable of monitoring air quality only at the location of their deployment. There would be an advantage in deploying monitoring techniques that require minimal power (e.g. car battery, solar cell) and are capable of measuring air quality at a distance from the place of deployment. In the autumn of 2008, a trial of DOAS (Differential Optical Absorption Spectroscopy) was undertaken in northern Alberta and northern Saskatchewan, at four SAGD plants in various stages of development. Results of this study, and a discussion of the technology, will be given. Advantages and limitations of DOAS for deployment in Athabasca will be discussed. In general it was found that SO 2 results showed remarkably low degrees of contamination, while NO 2 concentrations were more noticeable. Introduction Conventional techniques for air quality monitoring in Western Canada have, for several decades, relied on monitoring trailers deployed in strategic locations downwind from major emitters. Typically, sulphur dioxide, for example, is measured by pulsed fluorescence spectroscopic techniques. These systems have proven to be quite reliable in the past. The northern Canadian heavy oil and oil sands areas, however, present unusual challenges that limit the applicability of the conventional techniques. Most projects are located in the boreal forest areas of the Canadian west, and it is therefore necessary to minimize the environmental footprint of such projects. The more recently developed in-situ recovery techniques, primarily Steam Assisted Gravity Drainage (SAGD) are in fact capable of significantly reduced footprints by virtue of their reliance on horizontal well technology. Horizontal sections of such wells are now of the order of 800 meters, and multiple wells can be drilled from a single location. It is this reduction in land disturbance that, as a corollary, makes extensive air quality monitoring more difficult, for the following reasons: Monitoring stations of the conventional type require building of access roads or clearings. Electrical power lines need to be installed to the trailer sites chosen, because permanent mains power is required for trailer operation. Any trailer so deployed is capable of measuring air quality only at the point of deployment; air quality assessment at a distance is not possible. Given that the oil sands area in northern Alberta alone is of the order of 140,000 square kilometers in area (and is therefore larger than most European countries and just under half the size of Germany or France) adequate monitoring of air quality in the region may well become part of the footprint problem if the current technology is not at least augmented by other techniques.

Abstract Tailings ponds contain large volumes of fine tailings that often settle slowly on a timescale of years. Accelerated densification can be achieved by addition of agents such as calcium sulfate (gypsum), although some microbial activity such as methanogenesis may also accelerate densification. The latter process, however, contributes to undesired methane emissions from tailings ponds. It is known that the presence of sulfate can curtail the activity of methane-forming bacteria by diverting microbial activity from the production of methane to the reduction of sulfate to sulfide. We sought to characterize the microbial processes in a tailings pond managed by Suncor in order to estimate their contribution to densification and reduction of greenhouse gas emissions. The sulfate and sulfide concentrations, sulfide oxidation potential, and rates of microbial sulfate reduction and methanogenesis were measured as a function of depth in a Suncor tailings pond. This pond is routinely treated with gypsum (CaSO 4 -2H 2 O) to consolidate fine tailings. The highest concentration of sulfate was found at the pond surface (over 6 mM or ∼ 575 ppm) where no sulfide was detected. At various depths, the sulfate and dissolved sulfide concentrations measured correlated well with each other and with the rates of sulfate reduction. In general, the highest rates of methanogenesis (up to 80 mmol CH 4 /m 3 tailings/d) were measured where the sulfate reduction rates were lowest and vice versa, which supports the notion that methanogenesis will occur when sulfate-reducing activity is low. The fluctuating rates of sulfate reduction and methanogenesis we measured as a function of depth also shows that different microbial activities occur at discreet levels within the pond, probably due to the availability of sulfate. Based on the average rate of sulfate reduction measured in the pond samples, 10 mmol sulfate reduced/m3 tailings/d, the consumption of pond hydrocarbons by sulfate-reducing bacteria could potentially inhibit the formation of over 2 million L of methane per day from a typical pond harboring ∼10 7 m 3 of tailings. Although the stimulation of sulfate reduction would produce undesirable H2S, our data suggest that sulfide is converted to sulfate at the pond surface due to either chemical or microbial oxidation. The data collected so far support a model in which sulfide, formed by reduction of sulfate at depth, is carried upwards in gas bubbles (possibly methane) and is then oxidized back to sulfate in the upper oxygenated layers of the pond. Our observations show that the use of calcium sulfate as a consolidation agent has the additional advantage of reducing greenhouse gas emissions from tailings ponds. Introduction Tailings ponds minimally contain water, sand, clays, and residual bitumen and hydrocarbon diluent. A typical pond has a large volume (∼10 7 m 3 ) of a water-clay-bitumen suspension as its core surrounded on all sides by sand, which has segregated during oil extraction. The suspension, referred to as fine tails, settles slowly on a time scale of years, compromising water reuse and eventual pond reclamation.

Abstract Many hydraulically fractured shale gas horizontal wells in the shale gas reservoirs have been observed to exhibit transient linear behavior. This transient linear behavior is characterized by a one-half slope on a log-log plot of rate against time. This transient linear flow regime is believed to be caused by transient drainage of low permeability matrix blocks into adjoining fractures. This transient flow regime is the only flow regime available for analysis in many wells. In this paper, a linear dual porosity model is used to approximate the shale gas completions with a horizontal well and multiple hydraulic fractures. Five flow regions are identified with this model. It seems that field production data exhibit Region 4 behavior which is primarily transient drainage from the matrix. However, a skin effect for Region 4 is observed in many wells. This modifies the shape of the log-log rate plot and the square root of time plot. A new analytical equation is presented to model the effect of skin on linear flow behavior. The resulting curve shapes are somewhat surprising and tend to explain the early curve shapes of actual wells. A procedure is presented in this paper to analyze field data. Introduction Shale gas reservoirs constitute a major source of the gas production in the United States. The Gas Technology Institute estimates that organic shale reservoirs in the United States contain up to 780 tcf of gas. 1 In shales, natural fractures provide permeability and the matrix provides storage of most of the gas. Shale matrix permeabilities can be as low as 10 −9 md. 2 Shale reservoirs have been described by the dual porosity model comprising matrix blocks (storage of fluid) separated by fractures (permeability) first proposed by Warren and Root. 3 Warren and Root 3 presented well test analysis methods/interpretation for slightly compressible fluids. Traditional well test analysis methods were extended to shale gas reservoirs as demonstrated in the work by Kucuk and Sawyer4 who presented a transient matrix-fracture transfer model incorporating gas pseudopressure definitions. Subsequently, methods of analyzing production data were investigated by different authors. Carlson and Mercer5 coupled Fick's law for diffusion within the matrix and desorption in their transient radial reservoir model for shale gas. Modifications include use of the pressure-squared forms valid for gas at low pressures to modify the diffusivity equation. They provide a Laplace space equation for the gas cumulative production from their model and use it to history match a sample well. They also show that semi-infinite behavior (portions of the matrix remain at initial pressure and is unaffected by production from the fractures) occurs in shale gas reservoirs regardless of matrix geometry. Gatens et al. 6 analyzed production data from about 898 Devonian shale wells in four areas. They present three methods of analyzing production data – type curves, analytical model (slab matrix model presented by Serra et al. 7 ) and empirical equations. The analytical model is used along with an automatic history matching algorithm and a model selection procedure to determine statistically the best fit with actual data.

Abstract Vapor Extraction (VAPEX) a new developed Heavy Oil Recovery (HOR) method, has been extensively studied, both theoretically and experimentally, in conventional sandstone models. However, the applicability of this process on naturally fractured reservoirs has not been addressed yet. The objective of the present work is to evaluate the effect of fractures geometrical properties such as fracture orientation, length of extension, discontinuity in both Up Wells Region (UWR) and Far Wells Region (FWR) and vertical fractures location on VAPEX performance. Additionally, the effect of horizontal and vertical fractures dispersion in different fracture density, dispersion scheme and fractures networking on the performance of VAPEX process was assessed. Fractures discontinuity effect has been also scrutinized in the presence of parallelepiped networked fractures which confirmed the results in the case of either horizontal or vertical fractures systems. It was found that VAPEX process performance is enhanced in the case of longer vertical fractures, lower horizontal fractures dispersion, shorter horizontal fractures extension and lower vertical fractures discontinuity. Vertical fractures dispersion scheme also affects the performance. The ultimate oil recovery in the case of networked fractures will be higher than conventional model if the horizontal fractures have poor connectivity to each other. Introduction In thermal recovery methods, as far as the reservoir's oil is heated up, main fraction of the thermal energy is used up in heating the formation itself. For the reservoirs with very thin pay zone, bottom water zone and/or overlying gas zone, excessive depths and high water saturation the economical applicability of the thermal methods is doubtful. Additionally, application of thermal processes in carbonate reservoirs with low vertical fracture permeability, low porosity and low thermal conductivity where the heat capacity per unit volume of contained oil is high is not economically feasible. With respect to current available recovery technologies, these reservoirs are categorized as problematic reservoirs (1–4) . For example in the case of high pressure reservoirs, as an advantage of solvent-base technique, hydrocarbon mixture vapors with non-condensable gases are employed instead of pure solvent to ensure the solvent will be vapor in reservoir condition (5) . Some of the other main advantages of solvent-based process over that of thermal methods are less energy consumption, less environmental pollution, and lower capital cost. Furthermore, the hydrocarbon solvents are soluble only in the oil then the possibility of solvent loss to the formation and its confining environment is vanished. Therefore, the solvent-based process appears to be the only EOR technology that can be economically justifiable for problematic heavy oil reservoirs (6) . On the other hand, immiscible secondary recovery methods, even when successful, may leave significant amounts of oil in the reservoir due to the presence of capillary forces which are responsible for the entrapment of the oil (7–8) . Miscible secondary/tertiary recovery processes, in theory, are considered to be very efficient because they eliminate capillary forces. In the absence of capillary pressure, no interface exists between miscible fluids of different composition.

Abstract Bitumen extraction in oil sands-ore water slurry systems was studied using lipids and lipid derivatives as surfactants to promote the efficiency of bitumen recovery. In this study canola oil, tall oil fatty acids (TOFA) which are by-products of pulp mills using the bleached Kraft process, canola oil fatty acids methyl esters which are known as biodiesel (BD), and canola oil fatty acids monoglycerides were used as surfactant additives. Experimental findings suggest that BD, i.e., fatty acids methyl esters, a blend of fatty acids methyl esters, and fatty acids monoglycerides could also be used as surfactant additives to increase the efficiency of bitumen recovery in thermal in-situ processes such as steam assisted gravity drainage (SAGD) and cyclic steam stimulation (CSS) processes. Our experimental findings showed that the required dosage for the surfactant additives would be about 0.1 % of bitumen by mass. Also, interfacial tensions between bitumen and process water (?B,W) and BD and process water ( ϒ B,W ) were provided as supportive data for the applicability of the method proposed. This paper presents the initial observations. Experiments at high pressure conditions and the analysis of bitumen recovery and produced water chemistry are currently in progress. Background Oil sands deposits in northern Alberta, Canada contain about 142×10 9 cubic meter cube (m 3 ) or 890×10 9 barrels of bitumen, which makes it one of the largest oil sands deposits in the world (AERCB, 1984). Four commercial plants are utilizing surface mineable oil sands deposits for bitumen production using oil-sands ore water slurry based extraction processes with total bitumen production capacity exceeding 10 6 barrels/day. Reduction of the surface and interfacial tensions play an important role in the efficiency of bitumen recovery in ore-water slurry systems (Moschopedis et al., 1977 and 1980; Speight and Moschopedis, 1977; Bowman, 1968; Baptista and Bowman, 1969), which are the basic reasons for the success of the Clark How Water Extraction (CHWE) process (Clark, 1939 and Clark and Pasternack, 1932). In the CHWE process, the solubility of naturally occurred asphaltic acids in bitumen which are partly aromatic, containing oxygen functional groups such as phenolic, carboxylic and sulphonic types are increased by the use of caustic NaOH, which act as surfactants reducing the surface and interfacial tensions. This process produces tailings with poor settling characteristics which result in the use of gypsum (CaSO 4 ) as additive to alter its settling and consolidation properties. It is realized that the release water chemistry is harmed by the use of chemical additives in both extraction and tailings disposal processes (Allan, 2008 and 2008; Franklin et al. 2002). Novel extraction process aids, i.e. surfactant additives, have to replace the conventionally used additives, by which extraction efficiency would be improved without harming the fuel quality of bitumen, release water chemistry and geotechnical properties of the tailings. Our research was focused on the use of surfactants from external sources to eliminate the harmful effects of the additives used in the existing oil sands plants.

Abstract Among the three types of geological CO 2 sequestration (mature oil and gas fields, unminable coal beds and deep saline formations), depleted gas condensate reservoirs are particularly interesting. Firstly, because of the high compressibility of gas, these reservoirs have larger storage capacity than oil reservoirs or aquifers. Secondly, the condensate that has dropped out from the gas phase during natural depletion will re-vaporize due to re-pressurization of the reservoir and by miscibility with the injected CO 2 . This condensate can be recovered from producing wells and leaves more pore volume for available for storage of CO 2 . We analyzed the injection of a CO 2 -based stream into a depleted gas condensate reservoir and into a saline aquifer using a compositional reservoir simulation model. The dynamics of the reservoir impose a minimum period of injection that is required in order for the storage scheme to benefit from 100% of the reservoir storage capacity. Hence, over and above a certain CO 2 injection rate, it becomes meaningless to invest in bigger compressors to increase this rate to reduce the time of injection. When the CO 2 stream contains impurities such as N 2 or methane, the storage capacity of the reservoir decreases proportionally to the impure stream's compressibility factor and its concentration of impurities. This finding suggests that an economic optimum between the costs of separation, compression and injection can be determined. Finally, the mass of CO 2 sequestrated per pore volume in the equivalent aquifer model is about 13 times lower that of the depleted gas condensate reservoir model. This confirms that, due to their low overall compressibility, aquifers offer a far lower ratio of CO 2 stored per pore volume than depleted gas condensate reservoirs. However, aquifers tend to have a far larger extent, which often compensates somewhat for this lower ratio and so provides storage for significant volumes of CO 2 . Design Considerations in CO 2 Capture and Storage Projects In 1992, international concern about climate change led to the United Nations Framework Convention on Climate Change (UNFCCC). The ultimate objective of that Convention is the " stabilization of greenhouse gas concentrations in the atmosphere at a level that prevents dangerous anthropogenic interference with the climate system". Depending on the scenario considered, cumulative emissions of hundreds or even thousands of gigatonnes of CO 2 would need to be prevented during this century to stabilize the CO 2 concentration at 450 to 750 ppmv 1 . CO 2 Capture and Storage (CCS) could facilitate the achievement of stabilization goals. CCS would be an option for countries that have significant sources of CO 2 suitable for capture, that have access to storage sites and experience with oil or gas operations, and that need to satisfy their development aspirations in a carbon-constrained environment. Among the three main types of geological storage (mature oil and gas fields, unminable coal beds and deep saline formations), the injection of CO 2 into depleted gas condensate reservoirs is particularly interesting for two main reasons: Depleted gas condensate and/or natural gas reservoirs have larger storage capacity than oil reservoirs or aquifers.

Abstract The vapor extraction (VAPEX) process, as a non-thermal process, may be suitable for the recovery of heavy oil and bitumen. In this process, the injected solvent diffuses into the heavy oil/bitumen, reduces its viscosity, and drains it to the producing well. The VAPEX process is more acceptable than other processes due to its environmental friendliness, low capital and operating costs, and suitability for thin reservoirs. Most of the efforts in the modeling of the VAPEX process have concentrated on the application of fluid flow equations to the solvent and the diluted oil inside each grid block used in the simulation of VAPEX. This is adequate when very fine grid blocks are chosen to simulate the process where the boundary layer (transition zone) occurs over a number of grid blocks. Fine grid blocks, however, require a large amount of simulation time, which is not applicable for field-scale simulation even with today's computing power. To deal with this problem, we introduce a new approach that is based on the application of the fluid flow equations to three phases: solvent, diluted oil, and heavy oil/bitumen. With this approach, it becomes possible to have mobile solvent, mobile live oil, and immobile or slow moving heavy oil/bitumen inside a grid block. The main feature of the proposed model is its ability to capture the boundary layer within a grid block, making very fine grid blocks unnecessary in the simulation of the VAPEX process. In addition, this approach can be applied to modeling viscous fingering inside grid blocks. Introduction Heavy oil and bitumen reserves as an alternative to conventional oil reservoirs have attracted increasing attention in recent years. The magnitude of heavy oil and bitumen resources is about six trillion barrels of oil, which are about six times the total conventional oil reserves [1] . There are different techniques for recovery of these huge resources but one of the techniques which is attractive in thin reservoirs, low permeability carbonate reservoirs, and the reservoirs underlain by aqcuifers and/or gas cap is the vapor extraction (VAPEX) process. The VAPEX process is a solvent analogue of Steam- Assisted Gravity Drainage (SAGD) in which a steam chamber is replaced by a hydrocarbon vapor chamber. In this process, which was developed by Butler and Mokrys in 1991 [2,3] , a vaporized solvent is injected through an upper horizontal injection well into a heavy oil reservoir. The solvent-diluted oil, which is the heavy oil with its reduced viscosity, is then drained downward by gravity to a lower horizontal production well. Therefore, the production rates are directly related to the viscosity reduction, which in turn depends on the amount of solvent dissolved in the crude. The important benefit of this process is the potential to upgrade the oil in-situ [4] resulting from asphaltenes deposition. The two important mechanisms in VAPEX [5,6] are (1) mixing of fluids and (2) asphaltene precipitation. The mixing of heavy oil and solvent depends on the dispersion and capillary forces.

Abstract Water availability and water storage will have impacts on oil sands development as surface-mined production increases. As a result, several technologies designed to increase the percentage of recycle water are being evaluated. One such option is the use of centrifuges to produce dry stackable tailings. Dry stackable tailings can accommodate overburden and soil replacement, and ultimately lead to the restoration of the original boreal forest. Laboratory investigations and lab scale pilot studies have demonstrated that dewatering of mature fine tailings by centrifugation is a function of both the clay content and chemical properties of the tailings being dewatered. The use of additives to improve centrifuge performance has significantly improved the results that can be achieved. Laboratory-scale successes were confirmed with field scale pilot testing recently completed by Syncrude. This paper discusses the laboratory scale centrifuge performance, along with the field pilot results. Introduction Tailings management in surface-mined oil sands is complicated by mine site topography, fines and clay content in the ore, and ore water chemistry (1) . The latest ERCB (Alberta Energy Resources Conservation Board) tailings directive proposes to monitor tailings management in much the same way as bitumen production is managed (2) . In any case, there will be several management strategies that may be implemented to meet this directive, including such things as composite tailings (consolidated tailings, non-segregating tailings, etc), sand capping, accelerated dewatering, mature fine tailings (MFT) drying, and centrifuged MFT (3) . This paper discusses the preliminary results of a recent pilot scale verification of the centrifuged MFT technology. Centrifugation of MFT as a concept was tested in 1991 in order to provide an upper limit to fluid fine tailings handling costs. Although successful it was felt that the capital and operating costs would be prohibitive (4) . Centrifuged fluid tailings was tested much more extensively in 1998 to 2001, and was piloted on a 20 ton per hour extraction plant in Vernal, Utah, for the Asphalt Ridge tar sands (5,6) . Although there are slight differences in the clay content between Asphalt Ridge and the Athabasca oil sands, it was felt that similar technology would be applicable to the Alberta oil sands industry. Laboratory scale testing confirmed the positive results from Utah, and larger scale testing was quickly commissioned by both Syncrude and Suncor to verify the small scale results (7) . With confirmation of the lab or bench scale centrifuge test program, Syncrude initiated a large scale pilot test at approximately 70m 3 per hour of MFT (mature fine tailings). This would be equivalent to approximately 700 tonnes of ore per hour, a scale significantly greater than the pilot studies undertaken in Utah. Surface-mined oil sands convention defines sand as the mineral fraction larger than 44 microns and the fines as the mineral fraction smaller than 44 microns (8) . The coarse tailings are predominantly made up of the sand fraction, and the fine tailings are predominantly made up of fines. It has been demonstrated that it is the clay fraction, as a size and mineral that defines the tailings properties, and in particular, the tailings volume and water holding capacity (9) .

Abstract The Burnt Lake Oil Sand Lease is located about 300 km northeast of Edmonton. The lease is estimated to contain 330 million m 3 of bitumen in place in the Clearwater oil sands formation. Cold production was tested in the lease to recovery 11–12 °API crude bitumen between 1990 and 1993. Three pairs of SAGD operation began in April of 1997 after three months of circulation. Many interesting characteristics were identified in the injection and production history. During the first year of operation, pressure and oil production rates decreased when steam injection rates were reduced. After the second year of operation, oil production rates responded inversely to steam injection rates. Oil rates were reduced when steam rates were increased and oil rates increased when steam rates were reduced. Declines in oil rates were relatively slow over the entire operation period. When the steam injection was stopped for about five months after five years of operation, the operation pressure and oil production rates were gradually reduced during this period. Many other unexpected trends were also observed. All these features were consistently seen in all three pairs. This paper presents these behaviours in detail. A simulation study of nine years of performance of Pair 1 was conducted to understand these characteristics. The history match demonstrated that oil production was achieved by two different mechanisms: one was expansion of the steam chamber and the other was drainage of oil from the layer above the steam chamber. Many unexpected performances were the result of the combination of these two recovery mechanisms. Introduction Three pairs of SAGD wells began production in April of 1997 after three month of circulation. Cumulative performances to December 31, 2005 were: (Table available in full paper) Steam injection rates, oil production rates, and operation pressure of these SAGD pairs are shown in Figures 1 to 3. Well performances of Pair 1 were selected for the numerical history match study. Three months averaged steam injection and oil production rates are shown in Figure 4. Many interesting characteristics were identified in the injection and production history. 1. During the first year (April 1997 to April 1998), the operation pressure and oil production rates decreased when steam injection rates were reduced. Operation pressure and oil production rates were positively sensitive to the steam injection rates. This is typically expected for the SAGD process. However, this characteristic was detected mainly during the first year of operation. 2. After the second year of operation, oil production rates responded inversely to steam injection rates. When steam injection rates were increased, oil production rates were reduced and when steam injection rates were decreased, oil production rates were increased. 3. Steam injection was stopped in October of 2002 for about five months while operation pressure and oil production rates were gradually reduced during this period. Similar characteristics were also noticed in 2003 and 2004.