bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mechanics of Heavy Oil and Bitumen Recovery by Hot Solvent Injection
Authors: Pathak V. , Babadagli T. , Edmunds N. R. 
Published: May 2011

Abstract
In our earlier works (Pathak et al., 2010; 2011), we presented the initial results for heavy oil and bitumen recovery using heated solvent vapours. The heavy oil and bitumen saturated sand pack samples of different heights were exposed to heated vapours of butane or propane at a constant temperature and pressure for an extended duration of time. The produced oil was analyzed for recovery, asphaltene content, viscosity, composition and refractive index. Recovery was found to be very sensitive to temperature and pressure.
The current work was undertaken to better understand the physics of the process and to explain the observations of the earlier experiments using additional experiments on tighter samples of different sizes, numerical simulation and visualization experiments. The effects of temperature and pressure on the recovery were studied using a commercial reservoir simulator. Propane and butane were used as solvents. Asphaltene precipitation was also modeled. A qualitative history match with the experiments on different porous media types was achieved by mainly considering the permeability reduction due to asphaltene precipitation, pore plugging, the extent of interaction between solvent and oil phase, and the parameters like model height, vertical permeability and gravity.
To investigate the phenomenon further, visualization experiments were performed. 2-D Hele-Shaw models were constructed by joining two plexiglass sheets from three sides, leaving some space in between to accommodate oil. The models were saturated with heavy-oil and left open from one side and were exposed to different types of solvents from this side. The setup was continuously monitored to observe fluid fronts and asphaltene precipitation.
Using this analysis, the mechanics of the process was clarified from the effect of solvent type on the recovery process. The optimum operating temperature for the hot solvent process and the dominant mechanisms were identified.
Field Scale Modeling of Tracer Injection in Naturally Fractured Reservoirs using the Random-Walk Simulation
Authors: Stalgorova E. , Babadagli T. 
Published: May 2011

Abstract
Modeling complex transport processes in naturally fractured reservoirs (NFRs) using classical continuum models may not be practically possible, because using classical algorithms for the detailed structure of fracture-matrix system requires unreasonable computational time. Also, fractured reservoirs are highly heterogeneous, and finite-difference calculations for such models often cause convergence problems. In addition to these, an exact representation of a complex fracture network in classical continuum modeling algorithms is highly difficult. An alternative is to use a non-classical technique known as the Random Walk Particle Tracking (RWPT) algorithm.
We showed earlier (Stalgorova and Babadagli, 2009) that the random walk (RW) technique can be adapted to model miscible flooding in a fractured porous medium at the lab scale. The unknown parameters used to match the model results were only diffusion coefficients for oil and solvent, as the diffusive/dispersive transport (effective if fracture and matrix) was coupled with viscous (effective in fracture) and gravity (effective in fracture and matrix) displacement. Advantages of this method over classical simulation are: (1) shorter computational time, which allows avoidance of simplifications, and (2) the ability to model the matrix-fracture diffusion process without any transfer function.
In the present paper, we modified this lab scale RW model for field scale applications. For validation, a series of tracer test results from the Midale field in Canada was used. Fracture network model was constructed based on geological data, and then we used the RWPT model to calibrate the fracture network against tracer test results.
We performed a sensitivity analysis to identify the importance of different parameters for the simulation results. The new model and observations can be used to validate and calibrate stochastically generated fracture network models and to estimate the EOR performance of NFRs.
Experimental Investigation and Numerical Simulation of Steam Flooding in Heavy Oil Fractured Reservoir
Authors: Souraki Yaser , Ashrafi Mohammad , Karimaie Hassan , Torsæter Ole 
Published: May 2011

Abstract
Nowadays, the most promising methods for recovery of heavy oil and bitumen are thermal recovery processes and among these processes, steam flooding is one of the most important methods. Naturally fractured reservoirs hold over 20 billion barrels of heavy oil which necessitates improvement in understanding of the physical processes that takes place between matrix and fracture during steam injection.
This paper addresses experimental and numerical simulation of steam injection in fractured rock. The purpose of the work was to investigate the efficiency and feasibility of steam injection in a core sample which is surrounded by fracture. Athabasca heavy crude oil was used in this study and some PVT properties of the oil was measured experimentally at different temperatures up to 200°C prior to simulation studies. Simulation studies were then conducted on a 20cm long cylindrical sandstone core with a permeability of 640mD. The core was saturated with Athabasca heavy crude oil and is radialy surrounded by a fracture.
The results show that steam injection process has great performance and efficiency in fractured systems. However, steam processes are not recommended in very high permeable fractured reservoirs due to high steam oil ratio (SOR).
Sensitivity analyses were performed on permeability of the fracture and injection rate. High fracture permeability is effective when the steam injection rate is low but it may have negative effect at earlier times for high injection rates. The effect of different injection rates on recovery performance of the system was investigated using the numerical model. Faster oil recovery and higher SOR was observed with increasing injection rates, eventhough the same ultimate recovery was obtained.
Experimental Study of Hot Fluid Injection into Athabasca Oil Sand Reservoir
Authors: Hashemi R. , Pereira P. 
Published: May 2011

Abstract
With more than 170 billion barrels of estimated oil sands, Canada has the second largest oil reserve in the world. 80 percent of these reserves are deep underground and can not be accessed by surface mining. Many In-Situ methods have been developed to extract heavy oil and bitumen from deep reservoirs. Once produced, bitumen is transferred to upgraders converting low quality oil to synthetic crude oil. Transportation of bitumen to a location for upgrading is a challenging aspect of bitumen production. In addition to processing costs, the level of contaminants in bitumen (sulphur, metal and nitrogen) requires special equipments, and has also environmental repercussions.
The "Underground Refinery" using nano-size Ultra-Dispersed (UD) catalyst is one of the alternatives to surface upgrading that may become the "next generation" of oil sands industry improvement. In order to perform a successful downhole upgrading process several steps should be implemented: catalyst placement (or presence) in an appropriate zone; reactants and co-reactant interaction, including heavy oil, catalyst and hydrogen; and creation of necessary reaction condition to obtain higher quality products, such as pressure and temperature.
This paper will present results of hot fluid injection in an elemental experimental model. Sets of experiments in various temperatures have been conducted to investigate effect of hot fluid on recovery enhancement. Results of each experiment compared with base SAGD process. Temperature profile distribution has been performed for each scenario. Results show that mixed hot fluid injection increased original oil recovery of bitumen up to 39% which shows (5–10 percent) recovery enhancement compared to pure hot fluid injection.
Polymer Screening Criteria for EOR Application - A Rheological Characterization Approach
Authors: Veerabhadrappa Santhosh K , Urbissinova Tolkynay S. , Trivedi Japan J , Kuru Ergun 
Published: May 2011

Abstract
Polymer flooding has been the most widely used enhanced oil recovery technique in both sandstone and carbonate reservoirs. Ample polymer flooding projects have been conducted with different level of success ever since the technique was introduced 50 years ago. It is a usual practice to select a polymer based on viscosity range, concentration and molecular weight without getting into rheological characterization and its effect on oil recovery. However, in recent times the application of polymer flood has gained critical mechanistic insight with advancement in understanding the role of elasticity on sweep efficiency. Therefore, selecting the type of polymer and understanding how its fluid rheology affects oil recovery are probably among the most critical factors involved in designing a successful polymer flood job.
To deal with this, a systematic approach for screening a polymer based on rheological characterization was adapted. Three different polymers, partially hydrolyzed polyacrylamide (HPAM) and Polyoxyethylene (PEO) were first used for fluid rheology study using a cone and plate rheometer and then for oil recovery through a special core holder designed to simulate radial flow through a sand pack – saturated with mineral oil.
Effects of various rheological parameters such as; a) Newtonian vs. non-Newtonian rheology (constant shear viscosity vs. shear thinning), b) shear viscosity vs. elasticity, and c) average molecular weight vs. molecular weight distribution (polydispersivity) on oil recovery were investigated. Finally, a parametric characterization study was performed to develop a screening criteria and to correlate oil recovery prediction. The approach could lead to a successful screening process of polymer based on various characteristic parameters such as average molecular weight, polydispersity and Trouton ratio.
Use of Phase Streamlines for Covariance Localization in Ensemble Kalman Filter for Three-Phase History Matching
Authors: Watanabe Shingo , Datta-Gupta Akhil 
Published: May 2011

Abstract
Ensemble Kalman Filter (EnKF) has gained increased popularity for history matching and continuous reservoir model updating. It is a sequential Monte-Carlo approach that works with an ensemble of reservoir models. Specifically, the method utilizes cross-covariance between measurements and model parameters estimated from the ensemble. For practical field applications, the ensemble size needs to be kept small for computational efficiency. However, this leads to poor approximations of the cross-covariance and can cause loss of geologic realism from unrealistic model updates outside the region of the data influence and/or loss of variance leading to ensemble collapse. A common approach to remedy the situation is through covariance localization to limit the influence of the data.
In this paper, we show that for three phase flow conditions, the region of covariance localization strongly depends on the underlying flow dynamics and also, on the particular data type that is being assimilated viz. water-cut or gas-oil ratio. This makes the traditional distance-based localizations sub-optimal and often, ineffective. Instead, we propose the use of water and gas phase streamlines as a means for covariance localization for water-cut and GOR data assimilation. The phase streamlines can be computed based on individual phase velocities which are readily available after flow simulation. Unlike the total streamlines, phase streamlines can be discontinuous. We show that the discontinuities in water phase and gas phase streamlines naturally define the region of influence for water-cut and GOR data and provide a flow-relevant covariance localization during EnKF updating.
We first demonstrate the validity of the proposed localization approach using a waterflood example in a quarter five-spot pattern. Specifically, we compare the phase streamline trajectories with cross-covariance maps computed using ensemble size of 2000 for both water-cut and GOR data. The results show a close correspondence between the time evolution of phase streamlines and the cross-covariance maps of water-cut and GOR data. a small-size industrial reservoir engineering PUNQ-S3 model application shows that our proposed localization outperforms distance-based localization method. The updated models show improved forecasts while preserving geological realism.
A Semi-Analytic Method for History Matching Fractured Shale Gas Reservoirs
Authors: Samandarli Orkhan , Al-Ahmadi Hasan A. , Wattenbarger Robert A. 
Published: May 2011

Abstract
This paper presents a semi-analytic method to estimate reservoir parameters by history matching the production data of hydraulically fractured shale gas wells. The method is based on the analytical solutions to dual-porosity reservoir models.
Algebraic equations developed by Bello and Wattenbarger (2010) for transient flow regimes which can occur in linear dual porosity model were used in this analysis. As far as practical values of reservoir parameters are involved, only two of the transient flow regimes would be seen in the field – bilinear and late linear. If matrix permeability is known, effective fracture permeability is estimated by doing regression on bilinear flow. Once bilinear flow is matched, linear flow part is also matched by regressing on fracture half length. Semi-analytic solutions are checked with actual data by making correction for gas properties change and desorption of gas at low pressures. When a satisfactory match of field data is obtained, reservoir parameters such as effective fracture and matrix permeability and OGIP can be estimated. Moreover, a future production of gas can be forecasted with estimated reservoir parameters for given economic constraints.
The method was applied on hydraulically fractured shale gas wells from Barnett play. It gives good results in history matching and estimation of reservoir parameters. Considering the recent interests in development of unconventional reservoirs, this method is future promising technique in better understanding those types of reservoirs.
Experimental Study of Co-Injection of Potential Solvents with Steam to Enhance SAGD Process
Authors: Ardali M. , Mamora D. D. , Barrufet M. 
Published: May 2011

Abstract
Steam-Assisted Gravity Drainage (SAGD) is the preferred in-situ technology to recover heavy oil and bitumen from Canadian reservoirs. It is commercially proven, delivers high oil rates and high ultimate recoveries. Given the large energy requirement and the volume of emitted greenhouse gases from SAGD process, there is a strong motivation to develop enhanced oil recovery processes with lower energy and emission intensities. Addition of potential alkane solvents to steam in processes such as ES-SAGD can reduce the high use of energy and green-house emissions in SAGD. Potential hydrocarbon additives provide an additional means to raise oil phase mobility beyond that achieved by heat.
Numerous simulation studies are published on the effect of hydrocarbon additives on SAGD process but few experimental results exist in public domain. Often, Conflicting results exist both in simulation studies and even field tests. In addition, numerical simulations are unable to fully capture the mechanism of hybrid steam solvent processes.
This paper summarizes experimental results of addition of potential solvents to steam in SAGD process. N-hexane was selected as the preferred additive to be co-injected with the steam and the experimental result are compared with pure steam injection process. Experiments were conducted using a scaled two dimensional cylindrical model. Peace River Bitumen samples were used to conduct the experiments at 80 psia.
Experimental results were analyzed to determine the key parameters involved in solvent assisted SAGD processes. Experimental results confirmed the effectiveness of hydrocarbon additives to enhance SAGD process. Co-injection of potential solvents led to accelerated oil production rate, higher oil recovery and lower energy to oil ratio.
A Combined Experimental and Simulation Workflow to Improve Predictability of In Situ Combustion
Authors: Bazargan M. , Chen B. , Cinar M. , Glatz G. , Lapene A. , Zhu Z. , Castanier L. , Gerritsen M. , Kovscek A. R. 
Published: May 2011

Abstract
In-situ Combustion (ISC) is widely accepted as an enhanced oil recovery method that is applicable to various oil-reservoir types. Prediction of the likelihood of a successful ISC project from first principles, however, is still unclear. Conventionally, combustion tube tests of a crude-oil and rock are used to infer whether one expects that ISC works at reservoir scale and the oxygen requirements. Combustion tube test results may lead to field-scale simulation on a coarse grid with Arrhenius reaction kinetics. If ISC is unsuccessful at field scale whereas tube tests are positive, the reservoir geological heterogeneity or operational problems are generally blamed. As an alternative, this paper suggests a comprehensive workflow to predict the likelihood of a successful combustion at the reservoir scale, based on both experimental laboratory data and simulation models at all scales. In our workflow, a sample of crushed reservoir rock or an equivalent synthetic sample is mixed with water/brine and the crude-oil sample. The mixture is placed in a kinetics cell reactor and oxidized at different heating rates. An isoconversional method is used to obtain an estimate of kinetic parameters versus temperature and combustion characteristics of the sample. Results from the isoconversional interpretation also provide a first screen of the likelihood that a combustion front can be propagated successfully. Then, a full-physics simulation model of the kinetics cell experiment is used to simulate the flue gas production. The model combines a detailed PVT of the multiphase system and a multistep reaction model. A genetic algorithm is used to estimate reaction parameters and thereby match oxygen consumption and gas production. A mixture identical to that tested in the kinetics cell is also burned in a combustion tube experiment. Temperature profiles along the tube and also the flue gas compositions are measured during the experiment. A high-resolution simulation model of the combustion tube test is developed and validated. This simulation uses the reaction model we have obtained from the genetic algorithm and/or isoconversional analysis. Finally, the high-resolution model is used as a basis for upscaling the reaction model to field dimensions employing nonArrhenius kinetics.
Application of Potential Theory to Modeling of ECBM Recovery
Authors: Shojaei Hasan , Jessen Kristian 
Published: May 2011

Abstract
In recent years, coalbed methane has become an important source of energy in the United States. Since primary production techniques typically recover less than half of the methane in a coalbed, enhanced coalbed methane (ECBM) recovery processes are needed in which N2 and/or CO2 are injected into the coalbed to recover more CH4. CO2 injection into coalbeds also provides additional benefit of sequestering carbon in the subsurface.
One of the main mechanisms that govern the dynamics of ECBM recovery processes is the sorption of gases onto the coal surfaces. Despite the well-documented complexity of multicomponent sorption phenomena, adsorption and desorption of CH4/CO2/N2 mixtures in the porous coal is commonly modeled with the extended Langmuir model. The extended Langmuir model has been proven unable to accurately describe the multicomponent sorption that is central to ECBM recovery processes and, therefore, more sophisticated sorption models are needed.
In this paper we apply potential theory to describe the multicomponent sorption of relevance to ECBM processes. In this approach for modeling multicomponent sorption, each component is assumed to be affected by a characteristic potential field emitted by the coal surface. We discuss the implementation of potential theory with emphasis on the simulation of ECBM processes where computational efficiency and accuracy must be balanced. The model must be solved by an iterative scheme, and is hence more computationally expensive than the extended Langmuir approach. The results and analysis presented in this paper demonstrate that the application of potential theory of sorption to modeling of ECBM recovery processes can improve the accuracy of calculations. However, the additional complexity of the model and the associated increase in the computational efforts may not balance the gain in accuracy sufficiently to warrant application in general purpose reservoir simulation.
The presented algorithms and modeling results are directly applicable in the development and utilization of coalbed methane resources.
Clinical Efficacy and Cost-Effectiveness of Lanthanum Carbonate as Second-Line Therapy in Hemodialysis Patients in Japan
Authors: Goto Shunsuke , Komaba Hirotaka , Moriwaki Kensuke , Fujimori Akira , Shibuya Koji , Nishioka Masato , Kim Jong-Il , Yoshiya Kunihiko , Shin Jeongsoo , Hasegawa Hirohito , Taniguchi Masatomo , Fujii Hideki , Nishi Shinichi , Kamae Isao , Fukagawa Masafumi 
Published: May 2011

Summary

Background and objectives
Lanthanum carbonate (LC) is a nonaluminum, noncalcium phosphate binder that is effective for hyperphosphatemia in dialysis patients. However, its efficacy and cost-effectiveness as second-line therapy have not been fully examined.

Design, setting, participants, & measurements
We first conducted a multicenter, open-label, 16-week clinical trial to examine the effect of additive LC in 116 hemodialysis patients who had uncontrolled hyperphosphatemia with conventional phosphorus-lowering therapy alone. Based on these clinical data, a state transition model was developed to evaluate the benefits and costs associated with LC as second-line therapy. Reduced risks for cardiovascular morbidity and mortality among patients treated with LC arise through more of the population achieving the target phosphorus levels. Uncertainty was explored through sensitivity analysis.

Results
After 16 weeks of additive LC treatment, mean serum phosphorus levels decreased from 7.30 ± 0.90 to 5.71 ± 1.32 mg/dl, without significant changes in serum calcium or intact parathyroid hormone levels. A subsequent cost-effectiveness analysis showed that compared with conventional treatment, additive LC incurred an average additional lifetime cost of $22,054 per person and conferred an additional 0.632 quality-adjusted life years (QALYs). This resulted in an incremental cost-effectiveness ratio of $34,896 per QALY gained. Applying a cost-effectiveness threshold of $50,000 per QALY, a probabilistic sensitivity analysis showed that additive LC had a 97.4% probability of being cost-effective compared with conventional treatment.

Conclusions
Our results indicate that the use of LC as second-line therapy would be cost-effective among hemodialysis patients with uncontrolled hyperphosphatemia in Japan.