Water flooding has been applied for more than seventy years in both conventional and unconventional heavy oil reservoirs. Although it is generally accepted that the mechanisms of water flooding in heavy oil systems are totally different than that of light oil reservoirs, there is not a systematic study to specifically investigate water flooding in heavy oil systems. This article presents the findings of core flooding experiments in water-wet systems and gives some insights on the interplay between capillary and viscous forces in imbibition displacement processes. Seven different oils of various viscosities, ranging from 1 to 15,000 mPa.s at 25 °C, were used in nineteen core flooding experiments where injection velocity was changed from 0.7 to 24.3 ft/D (2.5 × 10 −6 m/s to 86.0 × 10 −6 m/s). An in-line densitometer was used to precisely determine breakthrough time. Capillary forces and instability analysis were used to quantify the balance between viscous and capillary forces. On physical grounds, the capillary number, which is the relative magnitude of viscous and capillary forces during a displacement, should be the first-order influence on residual oil saturation. However, Abrams ( Abrams, 1975 ) showed that accounting for the viscosity ratio improves the correlation to residual oil saturation for oil viscosity below 37 mPa.s. Our observations extend the range of oil viscosity to 15,000 mPa.s and when combined with 178 datasets from the literature indicate that viscosity ratio has much more influence than capillary number on residual oil saturation. Standard models such as Buckley-Leverett theory predict that oil recovery at water breakthrough depends only on phase mobilities. However, our observations indicate that flow velocity also influences breakthrough oil recovery. At oil to water viscosity ratios smaller than 20, breakthrough oil recovery monotonically increases with increasing injection velocity. For intermediate viscosity ratios (20 < μ o < 160), breakthrough oil recovery increases with decreasing injection velocity. At higher values of viscosity ratios, breakthrough oil recovery is almost independent of injection velocity. In these cases, late time oil recovery remarkably increases with decreasing injection velocity. This effect is more pronounced in more viscous oil systems suggesting the importance of imbibition in these systems. Our observations prove that water flooding, if applied at the most optimized mode that is a strong function of oil viscosity, can still be a very efficient EOR technique.

A novel positive displacement hydraulically actuated quad-pump system (Quad-Pump) has been developed to improve production in deviated and horizontal oil wells. This downhole pump technology can be used in high temperature environment with large volume production such as SAGD wells. This paper describes the working principle of Quad-Pump downhole assembly and its hydraulic power system. Its operation advantages in SAGD environment are also presented. Design details of a test apparatus (flow loop) used to test the newly developed Quad-Pump is provided in this paper. A series of experiment is designed to verify the pump working principle and evaluate pump performance. A 4.75" Quad-Pump was manufactured and tested with producing fluid temperature of 100 °C and 200 °C. Testing results show the pump can produce up to 3600 bbl/day of fluid when a 60 hp electric motor is used to power the hydraulic drive system.

Dispersion of a solvent into heavy oil and bitumen in porous media has special significance in the context of solvent-based as well as solvent-aided versions of SAGD and CSS recovery processes. While solvent is injected with steam, the mixture condensation temperature changes based on solvent partial pressure. In addition, water condensate creates a film which acts as a barrier and impacts solvent dissolution in oil. The solvent, which is not soluble or has very low solubility in water, may not be able to diffuse in the oleic phase due to the presence of the water film. The objective of the present study is to investigate the pore-scale solvent diffusion in oil for solvent-based and hybrid (steam + solvent) processes through the following steps: Developing a pore-scale simulator, capable of handling steam and solvent condensation as well as mass transfer in porous media. Investigating solvent dissolution in the oleic phase at the pore-level considering the asynchronous condensation of solvent and steam. Investigating the dissolution of solvent, either in gaseous phase or in the form of liquified thin bulk films of condensed solvent and water condensate, in the oleic phase. A pore-scale simulator was developed with the capability of modelling solvent mass transfer and condensation of both solvent and steam, along with a Navier-Stokes type solution for the velocity field. In addition, conjugate heat transfer was included in the model that takes into account the heat transfer from solvent and steam to the solid grains by considering the two media (i.e. solid and fluid) for the solution. A realistic description of a 2-dimensional porous medium is used for direct numerical simulation (DNS). The properties of a typical heavy oil and solvent were implemented in the model with diffusion coefficient as functions of both temperature and solvent concentration. After model setup, the newly added features of mass transfer and conjugate heat transfer were validated by comparison with analytical models. For mass transfer validation, the numerical results were in agreement with analytical solution for a capillary whereas the model performance for conjugate heat transfer were inline with the analytical solution proposed for heat flow over a slab. The pore-scale simulator was then used to model two-dimensional pore-scale experiments of solvent co-injection with steam. To reproduce the experimental results, the interface advancement velocity was calculated as an evidence of the chamber growth. The 2D numerical simulation results were in agreement with the experimental data. The condensation of solvent vapor and steam also changes fluid flow and flow pathways of solvent at the pore-scale which results in some complex fluid flow and behavior such as excessive unexpected channeling. The present study is the first of its kind which considers condensation of steam and solvent vapor at the pore scale. The model is used to investigate solvent vapor condensation in competition with steam at the pore-scale and to study the impact of solvent type and operating conditions such as pressure. The outcome of the present study improves our understanding of mass transfer in porous media for solvent- based and solvent-aided thermal recovery processes.

This paper proposes a new criterion to estimate the impact of lean zones on thermal or thermal-solvent processes, such as SAGD, SA-SAGD, or EBRT (Imperial Oil's "Enhanced Bitumen Recovery Technology"). The interface stability of the steam/solvent chamber in the lean zone is related to the competition of heat transfer in either conductive or convective forms. This competition is described by a non-dimensional number, the Rayleigh number in porous media, which can be calculated by the parameters of the lean zone thickness, water mobility, thermal diffusivity, and steam chamber temperature. When a system's Rayleigh number is larger than a critical value, the primary heat transfer mechanism in the lean zone will be convection, in which the interface becomes unstable and may cause significant loss of steam or solvent. Analytical solution to obtain the critical Rayleigh number was given in literature ( Philip, 1982 ). For long axis horizontal cross sections, the critical Rayleigh number is estimated between 0.1 and 1. A significant number of simulation cases have been analyzed in a sensitivity study with CMOST (Computer assisted Matching, Optimization, and Sensitivity analysis Tool, Computer Modeling Group) to validate the above hypothesis. Monte Carlo simulation results have shown a strong correlation between the solvent recovery and the product of water mobility and lean zone thickness. This product is the essential part of the formula of modified Rayleigh number. Further calculation indicated that the critical Rayleigh number for the simulation models is between 0.1 ∼ 1 for SA-SAGD or SAGD and about 0.17 ∼ 0.32 for EBRT. Both are within the range given by the analytical solution. The critical Rayleigh number is introduced to the lean zone analysis for the first time. This physics-based criterion is able to give an answer to the estimate of performance impact of the lean zone for thermal and thermal-solvent gravity drainage processes. The Monte Carlo simulation confirmed the consistency between the numerical studies and the analytical solution.

Solvent Assisted-Steam Assisted Gravity Drainage (SA-SAGD) has been studied as a more efficient process for extracting bitumen from oil sands than the SAGD process. In the SA-SAGD process, solvent is injected with steam to decrease the viscosity of bitumen by dissolution of the condensed solvent. The dissolution of solvent causes a composition change of bitumen, which can lead to asphaltene precipitation. The effects of the asphaltene precipitation have been studied as part of a solvent-based recovery process such as Vapor Extraction (VAPEX). One of the advantages of the asphaltene precipitation is in-situ upgrading of the bitumen, whereas the disadvantage is that it causes a formation damage. To evaluate the effect of the asphaltene precipitation in the SA-SAGD process, it is essential to investigate the asphaltene precipitation under the conditions expected in the SA-SAGD process. However, it takes a lot of time to obtain sufficient data with a conventional method to quantify asphaltene precipitation under high-pressure/high- temperature (HP/HT) conditions. Therefore, the aim of this study is to develop an experimental procedure to evaluate the asphaltene precipitation with pressure/volume/temperature (PVT) apparatus in a reasonable time. The complex phenomenon at the edge of the chamber in the SA-SAGD process was simplified to a model of repetitions of mixing and drainage processes, and the experiment was configured in this manner. Solvent was added to a pre-diluted bitumen sample in a PVT cell. The supernatant liquid was sampled to analyze the asphaltene weight fraction remaining in the liquid phase and evaluate the asphaltene precipitation amount in the PVT cell. This process was repeated with increase in the solvent concentration. The asphaltene precipitation amount (APA) is calculated from the sample analysis data with recurrence relations under several assumptions. This procedure enables a wide range of APAs to be obtained from a mixture of bitumen and solvent in a single experiment, which enables sensitivity analysis under various conditions. In this research, the experiment was conducted under two different temperature conditions of 120°C and 150°C and the pressure was fixed at 3.5 MPa. The APA curves obtained from both experiments had almost the similar trend. Another important observation is that even the multi-component solvent (as used at the operation site) can still induce asphaltene precipitation under the HP/HT conditions expected in the SA-SAGD process.

There is abundant heavy oil resource in Bohai Oilfield and thermal recovery is an effective method to realize the high-efficient development. Till now, several field pilots have been conducted. However, for the offshore thermal recovery well, the onshore common used rod pump artificial lift technology is not applicable. The ordinary electric submersible pump (ESP) system cannot be directly used either, because it cannot stand the high-temperature steam. Therefore, artificial lift technologies suitable for offshore thermal recovery well is developed in recent years. For the ESP system, a high-temperature safety control system was developed, consisting of downhole safety valve, cable packer, and vent valve. The overall temperature and pressure resistance value could reach as high as 350°C and 21MPa, respectively. And the high temperature electric submersible pump could stand 250°C cyclic steam. This ESP system has been used in about 30 thermal recovery wells in Bohai Oilfild, satisfying the artificial lift requirements for the moment. With this ESP system, the overall process of each huff-and-puff cycle includes: lowering steam injection tubing, steam injecting, soaking, replacing production tubing, producing. That means two workover operations for tubing changes are required in each huff-and-puff cycle, which adds more cost to the oil production and has bad effect on the thermal recovery. Considering the drawbacks of the current ESP system, a new concentric-tubing jet pump system suitable for offshore oilfield with function of both steam injection and oil production is developed. Besides, the matched surface equipment, such as oil-water-sand separator and power fluid pump, are designed. The temperature resistance of the designed jet pump system reaches 400°C. With this system, no workover for tubing replacement is needed any more during one huff-and-puff cycle. Till now, this new jet pump system has been put into field pilot in one thermal recovery well. Both the steam injection and oil production process completed successfully, indicating its applicability for the offshore thermal recovery wells. In this paper, the tubing string structure details of the jet pump system and the specific field operation process is introduced. This new artificial lift technology will be gradually applied in other wells to improve the thermal recovery effect because of its advantages comparing with ESP system. Great progress and breakthrough of the artificial lift technologies suitable for offshore thermal recovery have been achieved in recent years in Bohai Oilfield, which will provide powerful technical support for the high efficiency development of the heavy oil resource in Bohai Bay.

Caprock integrity in steam-assisted gravity drainage (SAGD) has been evaluated by various researchers. However, most of these caprock integrity studies assume that the caprock is not fractured, which is not a valid assumption in most cases. This paper provides a comprehensive analysis of caprock integrity in the Athabasca oil sands with presence of natural fractures of various dip-angles in the Clearwater shale. Geological studies have shown that natural fractures exist in the Clearwater shale formation, which acts as the caprock for the McMurray oil sands. Based on some publicly available data in the Athabasca oil sands, we developed a numerical simulation model for a SAGD pad where reservoir and mechanical properties were characterized. A discrete fracture network model with natural fractures of different dip-angles was developed for the Clearwater shale. Coupled reservoir and geomechanical simulations were performed to evaluate the stress changes and deformations caused by steam injection in the reservoir. The impact of such stress changes on the natural fracture deformations was evaluated. It is observed that with steam injection, the temperature increases, steam chamber grows—which causes horizontal stresses to increase in the reservoir. When the steam chamber reaches the caprock, the temperature at the bottom of the caprock also increases due to thermal conduction. Such temperature increase results in horizontal stress increase there. Shear slip is induced in the low-angle fractures at the bottom of the caprock due to the stress changes. This plastic shear deformation increases with time. The top part of the caprock is less disturbed and the low-angle fractures there remain stable. High-angle fractures that are present from the bottom to the top of the caprock tend to slip as well. These plastically deformed fractures of different dip-angles provide a network of higher hydraulic conductivity conduits for fluid to more easily pass, and therefore are a potential risk to caprock integrity. The behavior of natural fractures in the caprock and their impact on caprock integrity in SAGD operations have rarely been addressed in the literature. This paper aims to fill the gap by presenting an analysis of natural fractures in the Clearwater shale and a comprehensive approach of simulating their shear slip tendency and thereafter the impact on caprock integrity in SAGD.

Gas-lift is an important artificial lift strategy for increasing the production of hydrocarbons from heavy oil and offshore reservoirs with declining pressure. The optimum design and operation of gas-lift has a considerable impact on the optimum production and economics of the entire field and can only be achieved by considering all related variables in connected reservoirs, gas-lifted wells and facilities. Therefore, it is essential to formulate the gas-lift model as an optimization problem within an integrated modeling environment, where all the time dependent physical and operational constraints of reservoirs, wells and facilities can be collectively taken into account during the time evolutionary modeling of the asset. However, this could pose a computationally challenging problem for most derivative based optimizers, as some of the governing equations and models representing the gas-lifted asset could be very nonlinear, physically or mathematically discontinuo us, and the system may not have a solution under some of the conditions proposed by the optimizer due to physical operational restrictions or infeasibility. To overcome these problems we applied a mesh adaptive direct search (MADS) derivative free optimization technique to optimize the gas-lift problems in an integrated reservoir, wells and production facilities environment. The results proved the suitability of the MADS strategy for optimizing these systems particularly for systems with narrow or discontinuous boundaries of physical operation.

The conventional approach used to account for geomechanical effects when modeling steam injection operations is based on dilation/compaction tables. These tables are mostly empirical and are usually employed as a history-matching parameter to calibrate simulation models to observed injection/production rates and pressures. In this study, we use a more rigorous workflow that couples a geomechanical simulator to more accurately model the changes in permeability and pore volume that occur during high-pressure steam injection. This paper demonstrates a new approach for incorporating and modeling the geomechanical effects observed while injecting steam for heavy oil recovery, specifically during SAGD (Steam-Assisted Gravity Drainage) operations. This workflow does not need an explicit, empirical table relating pressure to permeability and porosity; instead it uses a mechanical simulator to determine the evolution of the reservoir's stresses and strains to calculate a new property distribution that is updated in the reservoir simulator to account for dilation and compaction phenomena. To model the complex thermo-poro-mechanical coupling that prevails during thermal stimulation processes, we use a numerical workflow that integrates finite-difference reservoir and finite-element geomechanical simulators. This coupling technique enables a more rigorous modeling of the fluid and heat flows while predicting their influence on the reservoir deformation and stresses. Consequently, a direct link between stress/strain and porosity/permeability can be used to model the geomechanical changes that occur in the reservoir during high-pressure steam injection. We also compare the predicted behavior of SAGD models using the coupled approach against the use of empirical dilation/compaction pressure tables. A comparison of the simulation results obtained using the proposed coupled approach versus those obtained using empirical tables (uncoupled) showed significant differences in steam injectivity and distribution as well as oil and water production.

The phase behavior and physical properties of heavy oil have been considered of great importance during cold production process. In this study, constant composition expansion and compression (CCEC) tests were performed to measure and evaluate the live oil expansion and compression under various temperatures and pressures conditions through a PVT apparatus. The live oil viscosity and density were also obtained from the the experiments. CCEC tests were conducted using the recombined live oil (with specified gas-oil ratio) in the PVT cell without mixing by utilizing three different constant volume change rates (i.e. "Fast Rate", 1.5 cc/min; "Moderate Rate", 0.015 cc/min; and "Slow Rate", 0.0003 cc/min) at 75°C and 15°C. During the expansion period, the total volume was monitored continuously until it reaches the cell maximum. Following the expansion process, the oil and gas were compressed back to the initial pressure following the same rates as the expansion stage. The P-V diagram has been plotted according to the PVT data, therefore pseudo-bubblepoint pressure was able to be determined based on the slope change of the P-V curve. It is found that pseudo-bubblepoint pressure determined at 75°C is higher than that of 15°C. For different volume expansion rates, a faster rate results in a lower determined pseudo-bubblepoint pressure, indicating a strong foamy oil behavior. On the other hand, however, the volume compression rate did not significantly affect the tendency of total volume reduction curve regarding the PVT experiments. The results obtained from the current study will facilitate industry to make better design for heavy oil reservoir development.

Understanding how SAGD works is important as most of the in-situ production of bitumen in Alberta is using SAGD technology. A key parameter in simulation-based SAGD performance prediction is the residual oil saturation, which usually in SAGD simulations is a fixed number based on typical two-phase end-point relative permeability curves, combined with Stone's model to yield oil's relative permeability. Therefore, in simulations residual oil saturation (S or ) never goes below a certain number (typically 0.15-0.2). In reality, based on retrieved cores, there is evidence of S or continuously decreasing to as low as 0.03 and below. This paper explains the reason for this discrepancy and suggests modifications to the relative permeability model for more realistic simulations. Observations from retrieved cores suggest the residual oil saturation is dependent on the length of SAGD operation. This is also supported by Cardwell-Parsons correlation albeit for a two-phase system. The discrepancy between the current simulation results and actual observations point to the inadequacy of the relative permeability models containing the end points where kr og and kr og vanish at abscissas S w , S g less than 1. In this work effect of extending mobility of the oil phase all the way to S w , S g = 1 and k rw , k rg all the way to S w , S g = 0 is examined. First, a column drainage is numerically simulated, and relevant curve parameters are retrieved by comparing results against field results. These curves are then extended to simulate SAGD. The results show that the modified relative permeability curves mimic the observed behavior better with residual oil phase saturation progressively decreasing with time, rather than remaining constant after a certain point. Improved correlation with observed saturations obtained using modified curves suggest that the fixed residual saturations resulting from current models are a myth. When extended to solvent aided processes, the model reinforces the benefit of solvent additives even further. To the best of the authors’ knowledge most current SAGD simulations are done in a manner resulting in a fixed residual oil saturation. The proposed method presents an opportunity for better prediction of oil saturation with time and location and the corresponding performance of the SAGD process.

Reaction kinetics experiments are conducted to estimate important combustion parameters for crude oils. However, at elevated temperatures not only crude oil, but also reservoir rock is reactive, and the interaction of reservoir rocks with fluids may change the fate of the In-Situ Combustion (ISC) process. This study investigates the role of carbonates on the reaction kinetics of a bitumen sample from Canada. To reach this goal, Thermogravimetric Analysis/Differential Scanning Calorimetry (TGA/DSC) experiments were conducted at a constant heating rate on a bitumen sample and the blends of bitumen with calcite (CaCO 3 ) and dolomite (CaMg(CO 3 ) 2 ) minerals. The bitumen sample has been divided into its saturates, aromatics, resins, and asphaltenes (SARA) fractions. TGA/DSC experiments were conducted on the individual fractions and their pseudo blends in the presence and absence of carbonates to understand the contribution of each fraction in ISC success and their mutual interactions. Model fitting approach was used to analyze TGA/DSC graphs analytically to obtain activation energy and heat of reaction for each pseudo fraction, their blends, and initial bitumen samples at low (LTO) and high (HTO) temperature oxidation regions. It has been observed that among all SARA fractions, the aromatics fraction alone generated the greatest amount of energy. Saturates are known as the ignitor for the combustion and its ignition characteristics are enhanced with the presence of carbonates. Similarly, the energy generation at low temperature oxidation (LTO) region for saturates becomes more significant for the saturates-aromatics pseudo blend. While the aromatics heat generation increased more for the pseudo blend with asphaltenes in the presence of carbonates, the energy generation of aromatics is negatively affected for the pseudo blend prepared with resins and carbonates. Thus, it was concluded that for the specific bitumen sample worked in this study, resins are the critical fraction determining the ISC fate in a carbonate reservoir. Moreover, we found that thermal decomposition of carbonate minerals negatively affects asphaltenes cracking and combustion reactions since both asphaltenes cracking and thermal decomposition of carbonate rock start at around the same temperature. Our findings indicate that reaction kinetics studies should be conducted in the presence of all reservoir components (rock and fluids). However, because it is difficult to understand the contribution of each component to overall ISC performance, we recommend conducting reaction kinetics experiments on pseudo blends of reservoir fluid components. This procedure has been introduced for the first time with this study and enhanced our understanding towards ISC kinetics but should be extended to different crude oil and reservoir rock pairs.

Downhole RF heating continues to be the interest of the petroleum industry because of its advantages over conventional forms of heating. Previous results have shown that without a low-loss dielectric zone (LLZ) around the downhole RF emitter, none of the available linear dipole antennas can work efficiently, and most of the energy is absorbed preferentially in a few meter radius around the radiating well and will not penetrate substantially into the reservoir. To circumvent this problem, low-dielectric materials were proposed, which are composed of a solid mixed with an appropriate binder. These materials were selected to have low dielectric properties so that the RF absorption is minimized, and at the same time, low porosity to prevent water invasion during the RF heating operation. Four solids, Ottawa sand, solvent deasphalted tar, Poly(p-phenylene sulfide) (PPS) and Polyether ether ketone (PEEK) and four binders (polydicyclo pentadiene (DCPD) and phenol-formaldehyde resins (Novolac), a C-Class cement slurry, and a foamed cement) were evaluated by measuring their dielectric properties (dielectric constant and loss tangent) in the frequency range 1 - 2000 kHz and temperatures between 25–200°C. All four solids have low RF absorption as well as low porosity (<1%), and those values did not change significantly with temperature. Also, smaller dielectric properties were found for DCPD and Novolac than those found for the cement materials, and the DCPD binder has a dielectric constant almost half and a loss tangent one order of magnitude lower than those measured for the Novolac resin. Three different designs for the construction of LLZ were considered, which included underreaming the oil well, squeezing a solid-containing binder downhole, and creating a casing-less completion. Numerical simulations show that the use of a low-loss zone around the central emitter leads to a very much improved energy and temperature distribution, and higher penetrations (~12 m) than the case without it.

For methods of thermal heavy oil recovery, an alternative approach of applying electrical energy, such as electromagnetic heating, can be used to generate heat in reservoirs that are not suitable for steam injection or to improve the economics and reduce environmental impact of the heavy oil recovery compared to using steam injection. While much progress in the development of electromagnetic heating technology has been made in recent years, the ability to accurately and effectively mathematically model the application of an electromagnetic heating process to a reservoir has been limited. In this paper, based on our reliable and efficient electromagnetic heating simulator, the effects of operational parameters on electromagnetic heating performance are investigated including evaluation of antenna location, well constraints, and applied power and frequency. The feasibility of electromagnetic heating in oil sands reservoirs has been examined for two cases: a) a single horizontal well containing a heating source and b) a horizontal well-pair with heating sources located in both wells.

The fluid level software provides useful information to optimize oil and gas production when is required. The fluid level calculation is given by the acquisition of the half travel time of a soundwave and its acoustic velocity, which is highly influenced by changes in temperature, pressure, and specific gravity of gas, commonly seen in cyclic steam and nitrogen stimulations. Considering the above concept, a process for collection and statistical analysis of acoustic velocities was developed in a heavy oil field in order to ensure accuracy in fluid level detection in two specific groups of horizontal shallow wells whose gas composition was constantly altered by two different thermal EOR stimulations. The first group contains wells injected with cyclic steam, called EOR-1, and the second group includes wells injected with cyclic steam + nitrogen simultaneously, called EOR-2. Additionally, an estimation of the specific gravity of gas was calculated as a function of gas temperature and acoustic velocity collected, assuming an ideal mixture of gases at determined temperature ranges, considering the behavior of the casing pressure ​​as a constant (less than 2 Psig average). Scatter and box-plot were made using descriptive and inferential statistical methods for the study of data. With the analysis of the acoustic velocity of gas not only was possible to create a unique reference pattern with specific statistical Tukey's fences to improve the accuracy of liquid level detection by means of outlier determination, but it could also be interpreted the behavior of the annular gas composition in presence of additional gases such as water vapor and nitrogen at different annular gas temperature ranges during their whole production cycle, without requiring an expensive chromatographic analysis. In the same way, a detection method of nitrogen channeling between wells of the same producing sand could be established regardless of the EOR methodology performed, since it was determined that acoustic velocities from 1290 ft/s to 1400 ft/s are highly related to the presence of nitrogen in the gas composition being considered atypical in steam-injected wells (EOR-1), whose determined range varies from 1400 ft/s to 1520 ft/s.

A database is developed from multiple sources to comprehensively present and evaluate enhanced oil recovery (EOR) projects in Canada. The datasets comprising of in-situ reserves, corresponding production and EOR information of Canada and worldwide EOR projects are made publicly available on a custom-built interactive data analysis platform TIBCO Spotfire. EOR projects for light, medium and heavy oils in Canada are classified into 65 solvent flooding, 6 polymer flooding and 13 Alkali-Surfactant-Polymer (ASP) flooding. Thermal methods, particularly SAGD & CSS are conducted for extra heavy oil and bitumen in oil sands. Another 31 of immiscible flooding projects are also identified. Factors contributing to success of these projects in respective fields are evaluated based on reservoir properties and EOR parameters such as miscibility, wettability, mobility ratio, capillary number, minimum miscibility pressure. With detailed technical analysis, EOR screening criterion for each method is updated and validated with world EOR data as well as Alberta oil pools data of 2019. Primary and secondary flooding projects that have potential for tertiary recovery are matched with historic EOR data to estimate future enhanced production. It has been observed that 257 pools currently employing water flooding have some similarities to fields that have seen success with EOR. Upgrading these primary or secondary projects to enhanced recovery has the potential of increasing daily production by as much as 14%.

Erosion of standalone screens in thermal wells can lead to significant damage and reduction in production. The dominant failure mechanism is the development of localized high-velocity hot spots in the screen due to steam breakthrough or flashing of the steam across the screen. This study provides methods to assess the erosion potential of screen material devices to determine the allowable production conditions which avoid erosion. In this study the effects of impact angle, flow rate, sand concentration, particle size, and fluid viscosity on erosion are systematically investigated through a multivariable study. Experimental impingement testing is performed on screens in different orientations. Erosion is accessed by collecting weight loss data of the screen. Empirical erosion models are calibrated to provide predictions of functional relationships between erosion rate and varied parameters. Computational Fluid Dynamic (CFD) simulations are performed prior to the experimental work to visualize particle flow paths through the screen and determine local flow and impact velocities and wear patterns. The performance of five existing erosion models is assessed through experimental testing of sand control screens. In order to translate short-term, high-velocity laboratory test results into field erosion predictions, an empirical erosion model is then developed and employed to provide well flow guidelines and minimize erosion potential. This suggests that the use of erosion prediction models in situations in which due to lack of time/data tuning is not possible, may still provide a reasonable estimate for the rate of material loss of the screen. The model is used to obtain threshold superficial velocity curves for several conditions. The main concern associated with existing erosion models is that they do not consider sand production, nor do they account for many other factors that affect erosion process. An erosion model, coupled with CFD simulation, has been developed, that account for factors such as geometry, size, material, fluid properties and rate, sand size, shape, and density in downhole flow conditions.

Primary Cold Heavy Oil Production with Sand (CHOPS) recovery factors are low (typically 8%) and most of the oil is left behind in the formation. Canadian Natural Resources Limited (Canadian Natural) is pursuing alternatives to primary recovery and secondary post CHOPS Enhanced Oil Recovery (EOR) to recover more of this stranded oil resource. Wire-wrapped screens were investigated, using a High-Pressure High Temperature Sand Retention Testing (HPHT-SRT) apparatus, for sand control and inflow performance in a CHOPS formation near Bonnyville, Alberta. A new HPHT-SRT apparatus was designed/commissioned to better understand the role of oil viscosity on the capability of the standalone sand control screen. The facility allows to control the temperature of the fluid flowing across the sand pack and sand control coupon at different pressure drops. Each test is performed at constant pressure drops up to 300 psi. The temperatures up to 85 °C were tested. Coupons of wire-wrapped screen with three aperture sizes (0.008″, 0.010″, and 0.012″) were tested. Canadian Natural provided oil sand cores and crude oil from the target formation for this testing. The results indicated a high dependency of the near screen flow performance on the temperature and oil viscosity. As the increase in temperature reduces the oil viscosity below 300 cP, the near screen pressure gradient falls 26% to 40% under constant pressure drop for different aperture sizes. As the screen aperture increases from 0.008″ to 0.012″, the flow rate increases up to 20% for the test stages at 85°C temperature and up to 162% for the test stages at 25°C, for the tested pressure drops. The results indicate that at higher viscosities, the aperture size is the dominant factor in screen flow performance where a slight increase in aperture increases the flow performance and reduces pressure drop. However, increasing the aperture size, up to 0.012″, led to an increase in the sanding over 0.20 lb per square feet of the screen (lb/sq.ft.), which exceeds the acceptable threshold of 0.12 to 0.15 lb/sq.ft. for typical SRTs. Based on the pressure drops and produced sand results, a 0.010″ aperture size was recommended for the target formation. This paper outlines the results of the experiments with a HPHT-SRT, which is developed to better assess the function of sand control design for heavy oil assets. This phase of the work mainly focused on better understanding the role of the oil viscosity on sand control performance.

The objective of this study is to examine the impact of polarity on surfactant-steam flooding performance in the recovery of a Canadian bitumen sample. 10 laboratory-scale core flood experiments were used to investigate the interaction between the polar head of surfactants and polar fractions of the bitumen sample (resins and asphaltenes) in the presence of steam. A Canadian bitumen from Alberta with high polar fraction content; resins (17 wt%) and asphaltenes (29 wt%), was selected. The bitumen sample was first characterized in terms of viscosity at reservoir temperature (10,000 cP) and API Gravity (12°). Then, coreflood tests were conducted by coinjecting steam with an anionic, a cationic, or a nonionic surfactant. The performance of three anionic, three cationic, and three nonionic surfactants was tested. Each core flood result was evaluated in terms of the cumulative oil recovery, the residual oil content, the produced oil quality, and the asphaltenes content of produced and residual oil samples. Then, bitumen's polar fractions (resins and asphaltenes) and bitumen itself were subjected to each surfactant solution under steam and liquid water conditions, and simultaneously their interactions were captured by an optical microscope. Analysis of microscopic images was used to explain the performance differences in each flooding test. Every surfactant-steam flooding process resulted in higher recovery than steam flooding alone. The greatest oil recovery was observed with the longest tail length anionic surfactant. It has been observed that the presence of asphaltenes in displaced oil inhibits the formation of microemulsions and consequently reduces the amount of produced oil. Further, we observed that the microemulsions are successfully formed between the resins fraction of bitumen sample and surfactant solution under steam condition. Hence, to maximize the effectiveness of surfactant processes in high asphaltenes content reservoirs, we highly recommend the use of asphaltenes precipitants prior to injection of any surfactant solutions.

Oil sand reservoirs play an important role in the economy of Canada due to their significant recoverable reserves. Due to the high viscosity of the oil in these reservoirs, conventional methods cannot be used for production. The steam-assisted gravity drainage (SAGD) method is an efficient way of producing oil from these reservoirs. Predicting oil production and steam injection rates is required for planning and managing a SAGD operation. This can be done by simulating the fluid flow with flow simulation codes, but this is very time consuming. The run time for a 3D heterogeneous model with one well pair can exceed 2 days. In this paper, a SAGD approximate simulator for predicting SAGD performance with 3D heterogeneous models of geologic properties is developed. This approximate simulator can handle different types of operating strategies. The approach is an approximate solution using a semi analytical model based on relevant theories including Butler's SAGD theory. The approximate simulator or proxy is much faster than the full simulator and it gives accurate estimated oil production and steam injection rates at different time steps. Theoretical and numerical research has been undertaken to develop the proxy, implement it in fast code, demonstrate the accuracy of prediction and apply to realistic examples. This proxy is used for other applications such as transferring uncertainty for reservoir realizations and well trajectory optimization.