bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

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

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

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.
A Robust Algorithm for Multiphase Isenthalpic Flash
Authors: Zhu Di , Okuno Ryosuke
Published: June 2014

Numerical solution of many non-isothermal flow problems requires robust isenthalpic flash. However, isenthalpic flash is challenging when the total enthalpy is sensitive to temperature, which is referred to as narrow-boiling behavior.

This paper presents a robust algorithm for three-phase isenthalpic flash for water-containing hydrocarbon mixtures. The algorithm is an extension of the direct substitution (DS) presented in the literature and our previous research for two phases. A detailed analysis is given for the narrow-boiling behavior and its effects on the DS algorithm. A new method is also presented for K-value estimates for three phases for water-containing hydrocarbon mixtures. The thermodynamic model used is the Peng-Robinson equation of state with the van der Waals mixing rules.

The narrow-boiling behavior occurs when the Gibbs free energy varies in temperature-composition space in such a way that a small temperature change yields significant changes of equilibrium phase compositions relative to the overall composition. The system of equations used in the DS algorithm becomes nearly degenerate for narrow-boiling fluids. The three-phase DS algorithm in this paper adaptively switches between Newton's iteration step and the bisection step depending on the Jacobian condition number. The bisection algorithm solves for temperature based solely on the enthalpy constraint only when narrow-boiling behavior is identified. The DS algorithm is tested with a number of different isenthalpic flash calculations. Results show the robustness of the DS algorithm for narrow-boiling fluids.
Emulsion Flow at the Edge of a Steam Chamber
Authors: Li Guangyao , Mojarad Mahdie , Dehghanpour Hassan
Published: June 2014

Recently different models have been proposed to describe two- and three-phase flow at the edge of a steam chamber developed during a SAGD process. However, two-dimensional scaled SAGD experiments and recent micro model visualizations demonstrate that steam-condensate is primarily in the form of micro bubbles dispersed in the oil phase (water-in-oil emulsion). Therefore, the challenging question is: Can multiphase Darcy equation be used to describe the transport of water as a discontinuous phase? Furthermore, the physical impact of water as a continuous phase or as micro bubbles on oil flow can be different. Water micro bubbles increase the apparent oil viscosity, while a continuous water phase decreases the oil relative permeability. Investigating the impact of these two phenomena on oil mobility at the steam chamber edge and overall oil production rate during a SAGD process requires development of relevant mathematical models that is the focus of this paper.

In this paper, we develop an analytical model for lateral expansion of steam chamber that accounts formation and transport of water-in-oil emulsion. It is assumed that emulsion is generated due to condensation of steam, which is penetrated into the heated bitumen. The emulsion concentration decreases from a maximum value at the chamber interface to zero far from the interface. The oil viscosity is affected by both temperature gradient due to heat conduction and micro bubble concentration gradient due to emulsification. We conduct a sensitivity analysis by using the measured data from scaled SAGD experiments. The sensitivity analysis shows that by increasing the value of m (viscosity temperature parameter), the effect of emulsification of oil flow rate decreases. Comparing the proposed model with previous analytical models reveals that emulsification effect should be included in the SAGD analysis. We also use the proposed model to estimate the oil flow rate measured in several fields, published in the literature and find a reasonable match.

The proposed mathematical model and its application to field and experimental data help the industry to understand the effect of emulsification on oil mobility during SAGD processes. Based on this understanding, steam chamber growth rate and oil production can be estimated more accurately.
A Critical Review of the Solvent-Based Heavy Oil Recovery Methods
Authors: Lin Lixing , Ma Hongze , Zeng Fanhua , Gu Yongan
Published: June 2014

Thermal-based heavy oil recovery methods, which are exemplified by steam-assisted gravity drainage (SAGD), have been successfully used in a number of field applications to enhance heavy oil recovery over three decades. However, there are several major technical issues associated with the thermal-based methods, such as large energy and water consumptions, extensive heat losses and expensive water treatment, as well as considerable greenhouse gas emissions. Thus the thermal-based methods are not suitable for many heavy oil reservoirs with thin pay zones, bottom water, gas caps, and low rock thermal conductivities due to economic constraints and environmental concerns. Alternatively, the solvent-based heavy oil recovery methods are considered. This paper provides a critical review of several solvent-based methods by conducting a comprehensive literature search of over 100 most recent and significant technical publications. First, the basic idea and technical development of each solvent-based heavy oil recovery method are briefly introduced. The advantages of solvent-based methods are stressed. Second, solvent-based methods are classified and each method is described. Third, a large number of experimental, theoretical and numerical studies of solvent-based methods are reviewed, from physical and theoretical modeling to numerical simulations. In particular, the heavy oil recovery mechanisms, phase behaviour and mass transfer of the heavy oil–solvent systems are examined in detail. A few important factors or major phenomena as well as their effects on the solvent-based methods are analyzed, which include the operating conditions (i.e., pressure and temperature), well configuration, solvent-induced asphaltene precipitation, interfacial tension (IFT), and viscous fingering. Most importantly, a total of six pilot tests or field applications of solvent-based methods, such as vapour extraction (VAPEX), liquid addition to steam to enhance recovery (LASER), and other hybrid steam–solvent processes, are evaluated. Finally, several major technical recommendations are made accordingly for future studies and developments of solvent-based heavy oil recovery methods and their potential variations. This updated technical review will help to better understand the solvent-based heavy oil recovery processes and guide a heavy oil producer to better design a solvent-based heavy oil recovery project.
Optimum Voidage Replacement Ratio and Operational Practice for Heavy Oil Waterfloods
Authors: Brice Bradley , Ning Samson , Wood Alecia , Renouf Gay
Published: June 2014

Heavy oil waterfloods have been operating in the petroleum industry for more than fifty years. Over this time, many researchers have tried to identify flood management practices that would optimize recovery from these waterfloods. This multidisciplinary work ties simulation with the evaluation of field statistical results to determine the best operating practices for heavy oil reservoirs that have high permeability thief zones. The particular type of thief zone of concern in Alaskan heavy oil waterfloods is called a Matrix Bypass Event, or MBE. An MBE is a dramatic water breakthrough event in the form of a direct connection between the injector and producer whereby the waterflood process ceases and the injection water cycles directly to the producer without sweeping the matrix. This study evaluates operating strategies for reservoirs where MBEs have developed, taking into account the effects and interdependencies of pre-production, Voidage Replacement Ratio (VRR), and oil viscosity.

Evaluation of production from 30 Canadian heavy oil waterfloods indicated that oscillation of the VRR resulted in more oil recovery than a reservoir operated at a constant VRR ~ 1.0. This finding laid the foundation showing that an operational practice called Cyclic Injection/Production would be beneficial, especially for heavy oil waterfloods. Cyclic Injection/Production alternates active injection while production is shut in, followed by active production while injection is shut in. Simulation was performed with a 3-D compositional finite difference reservoir model based on a heavy oil reservoir in Alaska's North Slope. The simulation confirmed that optimal waterflooding practices for heavy oils are significantly different from optimal practices for light oil waterfloods. The best practices also varied according to whether the waterflood had developed an MBE. As long as no MBEs are present and the producers are not bottomhole pressure limited, VRR of less than 1.0 and continuous injection are recommended. For heavy waterfloods that have high perm thief zones, however, Cyclic Injection/Production and a VRR of less than 1.0 improve recovery.
A Simplified Model for Field-Scale Surfactant-Polymer Flooding
Authors: Thirawarapan Chanya , Thiele Marco R. , Kovscek Anthony , Batycky Rod , Clemens Torsten
Published: June 2014

Modeling surfactant/polymer (SP) flooding at the field scale remains challenging despite a significant body of experimental and numerical work over past decades uncovering the flow physics associated with this particular chemical flooding approach and its modeling. In our work, we investigate a two-parameter model (the ω(CS)-model) relating surfactant concentration directly to the miscibility factor used to modify phase residuals and shapes of the relative permeability functions in SP-flood modeling.

We find that despite its simplicity, the ω(CS)-model for miscibility factor is able to reproduce results using the prevalent capillary desaturation curve approach (CDC-model). We first study a synthetic, two-dimensional reservoir with three injectors and three producers and then apply our approach to a realistic three-dimensional field example. We use streamline simulation to model the fluid flow in the reservoir, although the miscibility factor model is not limited to streamline simulation.

The main feature of the ω(CS) model is that the miscibility factor is only a function of surfactant concentration rather than surfactant concentration and Darcy velocity as in the CDC-model. While simpler models, such as the one proposed here are not predictive for core-scale simulations, simple models are the only practical way to find near-optimal solutions under the constraint of geological uncertainty, poor data, and many wells.
Forecasting Reservoir Water Losses in a SAGD Operation. A Combined Approach
Authors: Raffa Duilio , Keller Alan
Published: June 2014

Steam Assisted Gravity Drainage (SAGD) is the in-situ method of choice to recover bitumen from reservoirs in the Athabasca basin. In SAGD, steam is injected into an upper horizontal injection well, while emulsified bitumen and condensed water are produced from the lower horizontal production well. Produced water is treated and recycled to generate steam. Water management is a key factor in the operation of the whole process. Reservoir water losses are an essential part of the physics of the subsurface process with enormous implications for the water management. Prediction of reservoir water losses is critical to the design and operation of SAGD wells and facilities. For the purpose of forecasting water losses, three different approaches have been taken. The obvious inherent assumption in these methods is the ability of cold water to move through cold reservoir from higher pressure to lower pressure areas. This paper presents three methods to forecast reservoir water losses: the empirical, the analytical and the numerical simulation methods. These different approaches are complementary and incrementally complex allowing for flexibility (depending on time demand to create the forecast and required precision of the results). Ability to forecast water losses assists in planning the most efficient and reliable strategy to maximize future value of a SAGD operation.
A Case Study in the Application of Bitumen Geochemistry for Reservoir Characterization in SAGD Development
Authors: Sereda J. N. , James B. R.
Published: June 2014

Predicting the presence of sealing or baffling shale layers in a reservoir is important as they are detrimental to the steam assisted gravity drainage (SAGD) recovery process widely used in the Athabasca oil sands. Baffles and barriers divert or halt steam chamber growth and thus slow oil production, possibly reducing bitumen recovery. However, predicting whether a shale layer is baffle or barrier is difficult. They are hard to correlate between appraisal wells as they are highly eroded in the fluvial depositional environment of the McMurray formation.

Several authors have observed that a barrier or baffle in a reservoir can be detected by discontinuities in the vertical grading of bitumen viscosity or composition that is caused by intense biodegradation. This paper presents a case study that tests bitumen geochemistry as a tool for predicting the presence of baffling or sealing shale at two different Athabasca oil sands fields.

Geochemical analysis of cuttings and core from multiple wells at two fields (Field 1 and 2) were analyzed to measure spatial variations in geochemical compositional at each field and to determine what parameters were the most robust in predicting barriers and baffles. Geochemical predictions of barriers or baffles were compared to barriers and baffles to SAGD steam chamber growth using field production and other geological data.

Results indicate that geochemistry is valuable for aiding in the characterization of barriers and baffles. For the wells tested in this study, geochemically predicted baffles and barriers were also baffles and barriers for SAGD steam chamber growth. Geochemistry is also successful in detecting baffles at thin shale layers that are difficult to see on gamma logs and in wells with significant lost core where shale layers cannot be visually examined.

In this study, Field 1 bitumen was more degraded than Field 2, and showed significant lateral heterogeneity in bitumen composition trends. Field 2 on the other hand had very little lateral variability in geochemical trends. Alkylnaphthalenes, alkylphenanthrenes, and steranes were found to be effective indicators of baffles and barriers at both fields, despite the greater heterogeneity at Field 1. Geochemical analysis from drill cuttings and from core stored at ambient conditions for 10 years provided good quality data for predicting baffles and barriers. Geochemistry provides a tool to help improve the interpretation of lateral shale continuity, and has future implications for SAGD design, such as determining pay thickness, optimal well location, and as a baseline in production allocation studies.
An Integrated Application of Cluster Analysis and Artificial Neural Networks for SAGD Recovery Performance Prediction in Heterogeneous Reservoirs
Authors: Amirian Ehsan , Leung Juliana Y. , Zanon Stefan D. , Dzurman Peter J.
Published: June 2014

Evaluation of steam-assisted gravity drainage (SAGD) performance that involves detailed compositional simulations is usually deterministic, cumbersome, expensive (manpower and time consuming), and not quite suitable for practical decision making and forecasting, particularly when dealing with high-dimensional data space consisting of large number of operational and geological parameters. Data-driven modeling techniques, which entail comprehensive data analysis and implementation of machine learning methods for system forecast, provide an attractive alternative.

In this paper, artificial neural network (ANN) is employed to predict SAGD production in heterogeneous reservoirs, an important application that is lacking in existing literature. Numerical flow simulations are performed to construct a training data set consists of various attributes describing characteristics associated with reservoir heterogeneities and other relevant operating parameters. Empirical Arps decline parameters are tested successfully for parameterization of cumulative production profile and considered as outputs of the ANN models. Sensitivity studies on network configurations are also investigated. Principal components analysis (PCA) is performed to reduce the dimensionality of the input vector, improve prediction quality, and limit over-fitting. In a case study, reservoirs with distinct heterogeneity distributions are fed to the model. It is shown that robustness and accuracy of the prediction capability are greatly enhanced when cluster analysis are performed to identify internal data structures and groupings prior to ANN modeling. Both deterministic and fuzzy-based clustering techniques are compared, and separate ANN model is constructed for each cluster. The model is then verified using a testing data set (cases that have not been used during the training stage).

The proposed approach can be integrated directly into most existing reservoir management routines. In addition, incorporating techniques for dimensionality reduction and clustering with ANN demonstrates the viability of this approach for analyzing large field data set. Given that quantitative ranking of operating areas, robust forecasting, and optimization of heavy oil recovery processes are major challenges faced by the industry, the proposed research highlights the significant potential of applying effective data-driven modeling approaches in analyzing other solvent-additive steam injection projects.
On the Use of Particle Size Distribution Data for Permeability Modeling
Authors: Babak Olena , Resnick Jonah
Published: June 2014

Particle-size distribution (PSD) is a list of values that defines the relative amount of particles present according to the size in a sample. The PSD of the McMurray Formation sediments characterizes rock granulometry and is a fundamental indicator of sediment's nature. The size distribution of the component solid particles in the McMurray Formation sediments relates to their porosity, volume of water and bitumen contained within the pore space, and to depositional environment, including lithological association, stratigraphy, aerial distribution, and associated physical processes.

Particle size distribution is known to be a significant factor for evaluating bitumen recovery from an oil sands mine. This is because presence of fines (evaluated by PSD analysis) affects the hot water separation process, processing plant recovery prediction and provides grade control. Presence of more fines translates into lower recovery from commercial oil sands processing. In this paper we investigate whether the particle size distribution should be also considered a critical parameter for evaluation and estimation of permeability of an oil sands reservoir.

We show using the data from the Cenovus Energy's Telephone Lake lease that there is a strong relationship between permeability and particle size distribution data. We also show that the information provided by the PSDs for permeability prediction is more significant than the one inferred from a simple porosity-permeability relationship. Subsequently, we comment on permeability modeling using particle size distribution data and list the techniques available for cleaning and modeling of multivariate PSDs.

We document a methodology for accurate modeling of PSDs and provide a workflow for incorporating these data in improved understanding and modeling of permeability and its distribution.
Pressure Maintenance at post-CHOPS Cyclic Solvent Injection (CSI) Well Using Gas Injection at Offset Well
Authors: Chang Jeannine , Ivory John , Beaulieu Gilles
Published: June 2014

In the $40 million Joint Implementation of Vapor Extraction Program (JIVE), an experiment was performed to investigate CSI behaviour in the Lloydminster region under pressure support from CH4 injection at an offset well. The oil sand pack had high permeability (500 Darcy) and low permeability (3 Darcy) zones that represented regions with and without wormholes. Primary production was followed by two CSI cycles in which the solvent (60% CH4–40% C3H8) was injected at the high permeability end. CH4 offset gas was injected at the low permeability end during CSI production periods. Solvent recovery strategies were evaluated.

The primary production drawdown strategy (designed using numerical simulation) resulted in 10.0% oil recovery.

Production was only obtained after 6 hours due to a delay in gas exsolution and foamy oil drive. During CSI, a delay in oil recovery also occurred as the pressure-supporting offset gas required time to drive foamy oil generated in that region into the high permeability region. Cycle 1 oil recovery was 6.2%.

Cycle 2 had low oil recovery. Post-run gas saturations indicated gravity override occurred. Asphaltene precipitation/deposition occurred as seen from microscopic observation. The asphaltene content was reduced in the produced oil and increased in the post-run oil sand.

A rapid pressure drawdown after a third solvent injection period caused 1.7% oil recovery and foamy oil in the production line (Figure 1c). Additional oil recovery (4.5%) was obtained from offset CH4 injection, heating of the sand pack to ~60 °C, and 22 °C nitrogen offset gas injection.

Numerical simulations of primary production and CSI cycles showed: the best strategy is rapid well depressurization during productionhigh offset gas rate enhances gravity override and reduces oil production
Experimental Studies of Thermally Induced Deformation and Fracture Generation in Clay Shale
Authors: Li Biao , Diedro Franck , Wong Ron , Kryuchkov Sergey , Kantzas Apostolos
Published: June 2014

In thermal enhanced oil recovery process, the clay shale formations above the oil sands reservoirs may be subjected to high pressures up to 10MPa and high temperatures up to 300°C. The responses of the clay shale are very critical for designing or operations of thermal recovery processes. Maintaining wellbore and caprock integrities prevents incidents such as borehole collapse and leakage through caprock. Thermally induced deformation and fracturing in shale impacts on wellbore and caprock integrities. Most previous investigations focused on the mechanical properties of the clay shale. However, limited experimental work has been conducted to investigate the thermal response of clay shale under thermal operation conditions.

In this research, the thermal response of clay shale under different confining pressure conditions is investigated. Laboratory confined and unconfined tests were conducted on Colorado Shale cores which were retrieved from the overburden shale formation above the oil sands reservoirs in Cold Lake area, Alberta, Canada. The shale cores were heated at different heating rates and were subjected to different pressure conditions. The thermally induced deformation and fracturing responses in shale have been captured by X-ray computed tomography scanning (CT scan). The results show that under slow heating rates the shale sample maintains its integrity but display irreversible contraction after cooling to room temperature. Under high heating rates, the samples lose their integrity.
Numerical Study of the Effects of Lean Zones on SAGD Performance in Periodically Heterogeneous Media
Authors: Xu Jinze , Chen Zhangxin , Cao Jili , Li Ran
Published: June 2014

Highly permeable lean zones that halt the growth of steam chambers through lateral spreading significantly affect the performance of steam-assisted gravity drainage (SAGD). Nexen's Long Lake and Suncor's Firebag SAGD projects reported existence of intersecting lean zones that behave as thief zones, causing the operating pressure to be lower than the desirable value to reduce heat loss in the lean zones. Given a high steam-oil ratio, long and continuous lean zones located vertically above or near a wellbore pose a challenge. Log analyses and core experiments reveal that the distribution of lean zones is close to being periodic in the upper and middle parts of the McMurray Formation in Athabasca. A simulation model with periodic lean zones is established to analyze the effects of these lean zones on SAGD performance.

We investigate the effects of vertical distribution, horizontal spacing and sizes, and spatial relationship with SAGD horizontal wells. We classify the locations of lean zones as above an injector (AI), between an injector and a producer (BIP), and below a producer (BP). For each location, we assign different spacing for neighboring lean zones of different sizes. A lean zone must reach a critical size before this area can act as a thief zone, which is most significant in AI and BIP situations. In general, BP cases are hardly influenced by lean zones. We further control the vertical distribution of these zones using a triangular periodic function that depends on layer depth and connate water saturation. Changing the period of the dominant function yields different kinds of lean zone distribution patterns; we run simulations for each pattern. Results show that lean zones with small periods have significant effects on SAGD performance. We vary the injection pressure to obtain the highest net present value (NPV) based on the fact that more steam is released through the lean zones at a higher pressure.
Phase Behaviour Modeling of Complex Hydrocarbon Systems Applicable to Solvent Assisted Recovery Processes
Authors: Bayestehparvin Bita , Nourozieh Hossein , Kariznovi Mohammad , Abedi Jalal
Published: June 2014

Declining production from conventional resources in recent years has fueled increasing global interest in alternative resources, such as heavy oil and bitumen. The design and development of heavy oil and bitumen recovery processes, e.g. solvent-enhanced steam-assisted gravity drainage (ES-SAGD) and hybrid solvent, requires accurate predictions of phase equilibria and the mutual solubility of different solvents in bitumen. Despite the importance of accurate phase behaviour predictions, there is a lack of fundamental and mechanistic knowledge relevant to bitumen/solvent equilibrium properties.

This study provides a better understanding of the phase behaviour of bitumen/solvent systems. A phase behaviour model based on the Peng-Robinson equation of state was developed and validated with existing literature data. Then, available mixing rules for computing the co-volumes of polar and non-polar mixtures were incorporated into the developed model. In order to model the phase behaviour of bitumen/solvent mixtures, bitumen was first characterized to estimate its critical properties based on the boiling point distribution data. The boiling point distribution was modeled and extended using probability distribution functions. The phase behaviour of solvents (e.g. methane, ethane, and carbon dioxide) and Cold Lake bitumen systems were modeled using the developed model and the volume translation technique was applied to improve the saturated liquid densities.

The results show that the van der Waals mixing rule with two regression parameters successfully improves the accuracy of the solubility predictions to less than 4%. Incorporating the temperature dependency of the binary interaction coefficient makes the predictions even more accurate. A correlation incorporating the impact of temperature and component molecular weight on the calculation of saturated liquid densities was proposed for the translated volume values with a 0.6% deviation in density predictions.

The stepwise characterization scheme was developed in this study successfully define bitumen pseudo-components with least needed experimental data. The results also show the van der Waals mixing rule with two binary interaction coefficients predicts solvent solubility superior comparing to previous attempts.
Waterflooding Experiments with X-ray CT Imaging
Authors: London Mike , Cameron Shauna , Donald James , Wassmuth Fred
Published: June 2014

Three experiments have been performed, injecting brine and polymer into a sand pack saturated with heavy oil. Each experiment was imaged with time lapse X-ray CT. The first two experiments, conducted in a medical scanner with a resolution of 350 μm, suggested important features below the scale of spatial resolution. The last experiment, performed in a synchrotron beamline with a resolution of 4.3 μm, provided a view of oil/water interactions on the scale of individual pores.

Conventional theory holds that waterflooding is unstable with respect to the development of fingers, which push the oil ahead of them. "Sweep efficiency" can be improved by increasing the water viscosity with polymer, which reduces the mobility ratio and stabilizes the front. Waterflooding has been applied successfully to heavy oil, but the detailed mechanisms of recovery are not well understood. Breakthrough of water occurs quickly at the producer; most oil production occurs at high water cuts over a long period of time.

The most striking feature of the medical scans was the absence of distinct fingers of high water saturation. The only identifiable, compact "front" consisted of saturation changes of 20% or less. Moreover, breakthrough occurred long before the front reached the production end of the pack. More surprisingly, water saturation was observed to increase everywhere throughout each experiment. The inference was that fingering, if present, was occurring at a scale below that of the resolution. The synchrotron scans did not reveal the expected pore scale fingering, but instead showed evidence of water transport entirely in wetting films. Residual blobs of connate water were observed to grow throughout, but never linked up to form fully water-saturated paths.

The mechanism of oil mobilization was also quite different from the traditional picture. There was no scale at which oil was pushed ahead of a water front. Instead, isolated droplets of immobile water swelled, fed by films of water on the grain surfaces. These results do not rule out an eventual transition to a more conventional picture; only a few pore volumes were injected. But the path to that state may be different from what is usually assumed.