bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Robust Algorithm for Multiphase Isenthalpic Flash
Authors: Zhu Di , Okuno Ryosuke 
Published: June 2014

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.