bluuebunny/crossref_metadata_2025_split huggingface dataset:
Nodal Analysis for SAGD Production Wells with ESPs
Authors: Duncan Grant J. , Stahl Richard M. , Moseley Phillip E. 
Published: June 2014

Abstract
Steam Assisted Gravity Drainage (SAGD) is an enhanced oil recovery process whereby a long horizontal steam injection well is located above a long horizontal production well. Injected steam forms a steam chamber above the SAGD well pair, heating the reservoir rock and reservoir fluids. Heated oil (or bitumen) plus condensed steam flows down the sides of the steam chamber towards the production well. The condensed steam and bitumen are then lifted to surface with a downhole pump or by gas lift. Over the past decade, SAGD has become an increasingly popular method for extracting bitumen from Canadian oilsand leases that are too deep for surface mining, largely due to the high recovery factor from SAGD.
Nodal analysis for oil and gas wells enables the user to model well production or injection performance from the producing reservoir to the surface gathering system. Nodal analysis for well performance is based on the principle that reservoir inflow and wellbore outflow can be independently characterized as functions of flow rate. The single rate that balances the pressure losses in the inflow-outflow components with the pressure drop across the total system defines well flow. Nodal analysis is used to design new wells and optimize production or injection on existing wells. In addition, wellbore simulations are cheaper than instrumentation, meters or single well tests. Well evaluation software is the most popular package in Suncor's conventional production engineering toolkit because it is very accurate and easy to use.
Due to a rapidly increasing number of SAGD well pairs, Suncor required a tool that could accurately model these thermal wells. Over the past few years we worked with our software provider to develop nodal analysis for SAGD production wells, and we can now model SAGD producers with electric submersible pumps (ESP) with a high degree of confidence. The new SAGD nodal models quite closely match production rates, plus surface and downhole pressure and temperature data. Reliable and rigorous SAGD nodal models will enable improved decisions with respect to SAGD field development and production optimization.
Aquathermolysis and Sources of Produced Gases in SAGD
Authors: Thimm Harald F. 
Published: June 2014

Abstract
It has long been known that heavy oil and bitumen recovery by SAGD and CSS processes is accompanied by significant production of acid gases, as well as solution gas. Since the old laboratory studies of aquathermolysis from the 1970's and 1980's, there has been considerable development in the knowledge concerning production of methane and acid gases from Athabasca, Cold Lake, Peace River, Venezuela and Utah oil sands. It is found that both GOR and gas composition may vary with the deposits concerned. There is considerable divergence of opinion about the chemical origin of some gases, notably carbon dioxide. This affects the methods of control that may be available in operating individual reservoirs, and the matter is discussed. Also discussed will be the means of taking advantage of aquathermolysis phenomenon. It has been shown that both the GOR and gas composition of a SAGD project can be calculated from first principles. This permits estimation of the daily throughput of hydrogen sulphide and therefore allows a prediction or control of the requirements for sulphur recovery. The control of scale in SAGD plants has also been achieved by application of the current state of knowledge. Finally, there are implications for hydrogen sulphide release during loss of well control, an important regulatory aspect.
Feasibility Study of Using Transient Temperature Analysis to Evaluate Fracture Length in Cyclic Steam Stimulation Process
Authors: Wu Meng , Zeng Fanhua 
Published: June 2014

Abstract
In Cyclic Steam Stimulation (CSS), steam is usually injected above fracturing pressure into oil sands to achieve desired injectivity; thus fractures are generally induced. The induced fractures will affect heating and flow patterns and thus affect the choice of well spacing and steam injection strategies. Therefore, it is critical to evaluate fracture length for successful CSS projects.
Transient Temperature Analysis (TTA) is a technique which uses well-bore transient temperature data to estimate reservoir/wellbore characteristics. This paper discusses the feasibility of using TTA to evaluate the lengths of steam-induced fractures in cold lake oil sands by using wellbore transient temperature data in the soaking period of CSS. Numerical simulation model was first established based on history matching production data of a typical well in cold lake oil sands. Then the effect of different fracture lengths on temperature response in soaking phase was examined. Simulation results shows, in the middle and later period of soaking phase, linear relationships are found when temperature drop versus square root time are plotted. However, the correlation between fracture length and the slope is not clear. Based on the heated zone size and heated zone shape analysis at the very first moment of soaking phase, it is found the combined impact of reservoir permeability, reservoir thermal conductivity and fracture length determines the shut-in temperature response, which can be reflected on the slopes of the plots, with certain injection volume. But the qualitative representation of slope using fracture length, permeability and thermal conductivity cannot be found based on the results of finite difference based simulator. Aside from Finite difference method, simulation tools based on other numerical methods can be attempted to conduct TTA to evaluate the lengths of steam-induced fractures in CSS process.
Investigation of Interburden Dilution on Oil Sand Processability
Authors: Yang Xiaoli , Sedgwick Andrea 
Published: June 2014

Abstract
Surface mining of oil sands is generally limited to areas where the overburden thickness is less than ~75 m. Oil sands consist of a mixture of coarse sands, fine mineral solids, clays, formation water, and bitumen. Usually the orebody varies from 20 to 90 m in thickness, and the oil sand formation deposit is not homogeneous as it is intermingled with clays lenses (interburden). Bitumen content has been traditionally used as an indicator of ore processability. In fact, ores with a bitumen content of below 7% are considered uneconomical for processing. In this study, four types of ores were selected to evaluate the effect of adding two types of interburden with high clay contents on their ore processability. Ore processability was tested using the batch extraction unit. It was found that the interburden dilution does not always detrimentally affect the recovery. Depending on the ore grade, interburden dilution may boost the recovery for coarse grained ores, and depress the recovery for average and low grade ores. Current operational use of a maximum allowable fraction of interburden blended into oil sand feed may be overly simplistic. The results suggest that dilution to a maximum fines content of the blend is required rather than to a maximum fraction of interburden. Interburden effect on tailings settling behavior was also studied.
Understanding the Impact of Temperature-Dependent Thermal Conductivity on the Steam-Assisted Gravity-Drainage (SAGD) Process. Part 1: Temperature Front Prediction
Authors: Irani Mazda , Cokar Marya 
Published: June 2014

Abstract
Steam-assisted gravity drainage (SAGD) is the preferred thermal recovery method used to recover bitumen from Athabasca deposits in Alberta, Canada. In SAGD, steam injected into a horizontal injection well is forced into the reservoir, losing its latent heat when it comes into contact with the cold bitumen at the edge of a depletion chamber. Heat energy is transferred from steam to reservoir, reducing the viscosity of the bitumen, which flows under gravity toward a horizontal production well. Conduction is the main heat transfer mechanism in early SAGD, and reservoir thermal conductivity is a key parameter in conductive heat transfer. Conductive heat transfer occurs at a higher rate across reservoirs with higher thermal conductivity, which in turn affects the temperature profile ahead of the steam interface. Consequently, a reservoir with higher thermal conductivity will result in higher reservoir heating rates, and higher oil production rates. When the oil sands reservoir undergoes a temperature change from reservoir temperature to steam chamber temperature the thermal conductivity decreases up to 25% (depending on the initial reservoir and steam temperature), which affects the temperature profile and conductive heating within the reservoir. This study provides a modified Butler's model which includes a temperature-dependent thermal conductivity value. A simplified method is suggested using the thermal conductivity at average temperature of steam and reservoir will keep error under 1% for the range of SAGD applications. This novel approach is the first of its kind to incorporate a temperature-dependent thermal conductivity within the reservoir to a SAGD analytical model.
Preformed Particle Gel-Enhanced Surfactant Imbibition for Improving Oil Recovery in Fractured Carbonate Reservoirs
Authors: Muhammed Farag A. , Bai Baojun , Imqam Abdulmohsin , Almansour Abdullah O. 
Published: June 2014

Abstract
Oil recovery from naturally fractured carbonate reservoirs has always been a challenging task because of two inherent features, (1) Fracture networks which aggravate the effectiveness of water or chemical flooding and (2) Oil-wet matrix which limits the capillary imbibition process that governs the recovery in the fractured reservoirs. To overcome these challenges, we propose a technique that combines two existing enhance oil recovery (EOR) methods. Millimeter-sized preformed particle gels (PPGs) treatment along with surfactant imbibition. This coupled method can improve the imbibition process by providing fast transport mechanism for the surfactant to the oil-wet matrix which will accelerates the recovery rate. The coupled injection of PPGs and surfactant will result in a higher injection pressure gradient in the reservoir because of the high flow resistance resulting from the gel particles. Which will generate an additional force to divert surfactant into the matrix area thus forced imbibition can be realized. The combination of PPG treatment and surfactant imbibition can be a viable EOR process that will provide more cost-effective method for improving oil recovery while reducing water production in naturally fractured reservoirs if the PPG and surfactant were chosen appropriately.
A New Approach to Stimulating Thin and Stranded Oil Sand Reservoirs: A Simulation Study
Authors: Shahri M. A. , Cavender T. W. , Person J. , Kamali A. , Jamali A. , Solima M. Y. , Sheng J. J. 
Published: June 2014

Abstract
Several recovery processes have been proposed for heavy oil and oil sand reservoirs, depending on the reservoir and fluid properties. Among these, steam-assisted gravity drainage (SAGD) is widely used, and surface mining is considered the best approach in very shallow depths. However, deposits exist that are too shallow for SAGD but too deep for mining, requiring special techniques to recover the hydrocarbon economically. In addition, significant reserves are left behind as stranded reserves, as well as reserves that are usually characterized with weak caprock integrity and without enough pay thickness for SAGD to be economically viable. This paper focuses on a new technology that involves creating several mechanically induced inclusions in a single well. The production process is similar to a single-well SAGD. This method is proposed to assist both more uniform steam injection and bitumen production processes. The current setup is developed for vertical well applications; however, upon successful planning, the next version will be employed for horizontal applications.
The current system consists of a vertical well with multiple vertical inclusions, which are used for simultaneous steam injection and liquid production purposes. Steam is injected into the upper part of the formation, and the drained liquid is collected at the bottom of the inclusions. Unlike the conventional steam chamber geometry in SAGD processes, steam moves outward from the inclusion faces into the formation and tends to move laterally out and vertically upward over time. Simulation studies of the system show that the success of such a technique depends on the inclusion dimensions as well as injection rate and pressure. In this study, the effects of inclusion dimensions and steam properties on the performance of such a process are investigated. Reservoir simulations of realistic reservoir conditions show promising results in terms of cumulative steam oil ratio (CSOR) and production rate. Early peak oil production occurred at approximately 100 days from the startup, and the CSOR dropped to under 3 m3/m3 after 100 days. The optimum inclusion dimensions and the best injection scenario for different net pays at different depths and geological conditions are illustrated in the paper.
SAGD Wellbore Completion Optimization Using Scab Liner and Steam Splitter
Authors: Ghesmat K. , Zhao L. 
Published: June 2014

Abstract
Steam assisted gravity drainage (SAGD) process has been widely used commercially in Western Canada for bitumen production. Improving oil production rate and reducing steam oil ratio has been the focus of the industry. In heterogeneous reservoirs, oil production could be impeded by local steam break through and high liquid level above the other section of the producer. Various completion methods have been proposed to improve production efficiency. Steam splitter is proposed to match steam delivery to reservoir requirement and scab liner may be used in producer to maximize oil production. In general, oil drainage into producer may need to be slowed down at some locations and speeded up at other locations of the well. Non-uniformity of the reservoir pay and quality also has a direct impact on oil production and consequently, it is significant to divert required amount of steam to the desired spots of the reservoir. In this study, we address how to design steam splitter and scab liner in order to optimize SAGD production. Results from reservoir simulation with coupled wellbore hydraulics will be presented to show how a wellbore could be optimized by attaining favorite pressure profiles inside the injector and producer liners. This investigation will also address sensitivities on steam splitter location, size and number of holes in splitter, and size and length of scab liner.
Recovery of Bitumen in Heterogeneous Carbonate through Application of Warm Solvent
Authors: Bryan J. , Huang H. , Kantzas A. 
Published: June 2014

Abstract
Alberta contains significant bitumen resource volumes in heterogeneous carbonate formations. Recovery of this bitumen requires reduction of oil viscosity, coupled with drainage of low viscosity oil to high permeability production pathways. Oil viscosity reduction is most commonly accomplished through heat, via steam injection into the reservoir. While steam leads to fast drainage of oil from high permeable secondary porosity, access to the matrix is more difficult. Imbibition of water (steam condensate) can potentially lead to some access to the rock matrix, but wettability is still not well-defined in these systems. This work considers the results of several core flooding studies whereby solvent is used to recover bypassed oil in the carbonate pore matrix.
Solvent soaking tests are presented, validating the potential for solvent processes to mobilize bitumen at low and intermediate temperatures. Subsequently the results are provided for full diameter carbonate cores, which were first exposed to steam, and then were circulated in steam/solvent and solvent with varying temperatures. A process is described, whereby a heated reservoir is contacted by solvent while it cools. The combination of initial heat (elevated mass transfer) and subsequent cooling (elevated solvent solubility) leads to significant incremental oil production beyond that of steam alone. The application of solvent as a post-steam recovery process has considerable potential for increasing oil recovery by accessing previous bypassed oil within the carbonate matrix.
Time-Dependent Neural Network Based Proxy Modeling of SAGD Process
Authors: Fedutenko E.. , Yang C.. , Card C.. , Nghiem L. X. 
Published: June 2014

Abstract
The present study proposes a novel single-layer Neural Network proxy to efficiently predict the production performance of oil reservoirs from a limited number of reservoir simulations. The proposed model is shown to provide powerful means for learning reservoir's dynamics from input-output relationships that is defined by multiple combinations of inputs and controls. A SAGD case with 3 well pairs is used to illustrate the approach. The workflow is organized as follows: Different numbers (from 30 to 200) of direct numerical simulations are conducted for the time horizon of ten years for the given reservoir. These simulations correspond to different combinations of the operational parameters sampled according to the Latin Hypercube Experimental Design (LHD).The time series of the simulated entire field production performance (particularly: Cumulative Oil Production, cumulative SOR, Oil Recovery Factor, and Oil Production Rate) are used to build the corresponding Radial Basis Function (RBF) Network proxy model which represents production performance as objective functions of the operational parameters and time. The nodal Radial Functions of the Network are defined to exactly match the simulator's training outputs. The big advantage of this model is a combination of low computational complexity with high prediction accuracy.The proxy model is then used to predict the production data for the given reservoir for any time period (within 10 training years) and any combination of the operational parameters.The predicted data are compared with the actual simulation results for the same time period and the same combinations of the operational parameters to evaluate the prediction quality. It is shown that the proposed RBF proxy model can be used as a light version of simulator to estimate the production results for any combination of operational parameters and time horizon with much less computational efforts. The proposed approach is shown to provide a very efficient forecasting mechanism for the reservoir considered. The difference between the predicted and actual data could be as low as a few percent for the majority of the operational parameters depending on the number of simulations used to train the RBF model. In general, the accuracy of the proxy model increases with the number of training simulations.
Equation of State Based Simulation of Hybrid and Thermal Processes
Authors: Heidari M. , Maini B. B. 
Published: June 2014

Abstract
In development of early generations of thermal compositional simulators several assumptions are used based on characteristic of dead oil and steam mixture. K-value approach is used for phase splitting and equilibrium ratios are only function of temperature and pressure. Phase properties such as density, enthalpy and internal energy are calculated from correlations and ideal solution assumption. Excess properties such as excess enthalpy and density and mutual solubility of water in oil phase and vice versa are neglected in such models.
The latter assumptions may work properly for simple fluid mixtures with pure steam injection but could produce false results in more complicated processes such as hybrid processes with more intermediate components. In hybrid processes, where a hydrocarbon solvent is added to the steam, equilibrium ratios change with the variation of composition and neglecting this effect may lead to thermodynamically inconsistent or wrong results. Solubility of water in oil phase increases with temperature and it could become significantly high in some cases.
The purpose of this study was to develop a 3-D, fully implicit, equation of state (EOS) based thermal compositional simulator capable of modeling hybrid and thermal process of heavy oil recovery. By using an equation of state we aim to correctly model the thermodynamic and compositional effect on the phase behaviour. Water is allowed to be soluble in all phases and mutual solubility of oil and water is taken into account in our proposed simulator and its effect on the oil recovery can be investigated. Thermal expansion, fluid compressibility, solvent extraction, and steam distillation are calculated by our thermodynamic model. Steam properties are calculated from EOS or steam tables.
Different features of current simulator were validated against the analytical models and commercial simulators. Then several synthetic mixtures from published papers were selected and used in thermal and hybrid processes. The field production and injection rates from the current simulator are compared with the K-Value approach simulators. Detailed grid to grid level comparisons between EOS and K-Value approaches were also performed to investigate the effect of solvent additives on the equilibrium ratios, mutual solubility of oleic and aqueous phase, and phase splitting.
Sub-Pore Scale Modeling of Viscous Fingering during Heavy Oil Miscible Flood
Authors: Taheri S. , Ghomeshi S. , Bryan J. , Kryuchkov S. , Kantzas A. 
Published: June 2014

Abstract
Although heavy oil reserves are abundant, recovering them efficiently and economically remains a crucial technical challenge as a result of their high viscosity. Solvent based non-thermal recovery processes are designed to reduce the heavy oil viscosity through mixing and dilution with solvent. Solvent and heavy oil mixing occurs over a narrow zone, so localized viscous fingering can have a significant impact on the effectiveness of the solvent. In this study, direct pore scale modeling was used to simulate viscous fingering phenomenon during unfavorable mobility ratio miscible displacement of heavy oil in a three dimensional heterogeneous porous medium pattern.
In direct pore-level modeling, Navier-Stokes, Diffusion-Convection and Continuity equations, as the governing equations of dispersion, are directly applied and solved on the 3-D porous medium without any simplification in medium geometry.
To study the impact of unfavorable mobility ratio on the miscible displacement at the sub pore scale level, simulations have been run to model miscible displacement at five different unfavorable mobility ratios on the same porous medium pattern. Additional simulations were run to investigate the effect of pore pattern and different injection rates on the patterns, which were generated based on the process/object based reconstruction method. Base line simulations also have been done to model miscible displacement on the same medium when the mobility ratio is equal to one.
Heterogeneity of the pattern and lower viscosity of the solvent leads to appearance of some fingers just after starting solvent injection. The results show that growth rate of the fingers become smaller by decreasing mobility ratio. Finger transitions are the same for different mobility ratios but the fingers size and growth rate of the fingers are different for different mobility ratios. Generated fingers accelerate concentration spreading, so the solvent is mixed faster than that predicted by Convection-Dispersion equation. As the mobility ratio decrease toward one, growth of mixing zone length tends to 0.5, which is the growth rate caused by dispersion alone. By increasing the mobility ratio, fingers causes the mixing zone length growth tends to 1, so, for large mobility ratio, mixing zone grows because of two mechanisms: Dispersion and Fingering.