bluuebunny/crossref_metadata_2025_split huggingface dataset:
Electron-Induced Chain Reactions of Heavy Petroleum Fluids—Dominant Process Variables
Authors: Alfi Masoud , Da Silva Paulo F. , Barrufet Maria A. , Moreira Rosana G. 
Published: June 2012

Abstract
Ionizing electron particles were used as an efficient means of delivering energy to heavy hydrocarbon molecules. Although heavy oil reserves are known as rich sources of energy, their contribution to the energy market has been impacted by the fact that the conventional thermal or catalytic upgrading and visbreaking methods always demand a considerable energy and money investment. Therefore, application of potential alternatives with lower operating costs and higher process throughput appears to be extremely crucial in such a competitive market. In this research, high-energy electron processing technology was offered as a remedy to reduce the viscosity of heavy petroleum samples. Irradiated fluids exhibited lower viscosities than thermally cracked samples. Moreover, reaction temperature was observed to have a substantial influence on radiolysis process. At relatively low temperatures, radiation-induced upgrading stays inactive without any contribution to the viscosity reduction process. However, as the temperature exceeds a specific threshold, radiation-induced chain reactions become activated, decreasing the viscosity of irradiated samples. At the end, we have investigated the effect of different additives upon radiolysis of hydrocarbon molecules. Interestingly, radiolytic reactions were completely suppressed by some of these additives.
Sub-Cool, Fluid Productivity, and Liquid Level above a SAGD Producer
Authors: Yuan Jian-Yang , Nugent Daniel 
Published: June 2012

Abstract
Thermodynamic steam trap, or sub-cool control, in a typical SAGD production is essential to the stability and longevity of the operation. It is commonly achieved through the control of fluid production. The goal of such control is to maintain a steady and healthy liquid production without allowing bypassing of steam from the injector to the producer. Therefore, it is effectively a control of the liquid level above the producer. Unfortunately, it is not practical to monitor this liquid level. A rule of thumb sub-cool estimation of 10°C/m of liquid level is popularized in the industry, however, does not prove to hold in many situations.
This paper presents a study of the dynamics of SAGD production control with a resulting algebraic equation that relates sub-cool, fluid productivity and wellbore draw down to the liquid level above a producer. The main conclusions of this study include: There is no minimum sub-cool value for a pure gravity drainage scenario; however, as the wellbore draw down is considered there is minimum sub-cool value in order to maintain the stability of fluid flow.For a given productivity, the liquid level increases as sub-cool increases or as wellbore draw down decreases.For each set of parameters, there exists a minimum productivity below which SAGD operation would halt.Before the steam chamber reaches the top of the reservoir, the production rate is limited by the vertical distance between the injector and the producer, the larger the distance the higher the production rate can be.
A verification of this analysis was conducted via a series of numerical reservoir simulations. Although limited to 2D, we believe this analysis captures the main physics amid the dynamic complexity of SAGD production control. The resulting algebraic equation can be used for better understanding the dynamics of sub-cool control and determining operation strategies.
Foamy Oil Behaviour in Solvent Based Production Processes
Authors: Bjorndalen N. , Jossy W. E. , Alvarez J. M. 
Published: June 2012

Abstract
Foamy oils, generated during cold production, have also been detected in solvent based recovery processes. Understanding the foamy oil mechanism is key to determining how oil is produced in processes such as Cyclic Solvent Injection (CSI). Visual observations of solvent exsolving from solution during depressurization were performed to gain a better understanding of these processes.
Heavy oil saturated with CO2, CH4, C3H8 and a combination of CO2 and C3H8 are examined in an etched glass micromodel. Three different expansion rates are examined. The results indicate that CO2 and CH4 show an extreme supersaturation. CO2 saturated oil produces more nucleation sites than CH4, C3H8 and a mixture of CO2 and C3H8. Approximately 8 times more nucleation sites were produced with CO2 than with CH4. With more nucleation sites, there is a greater potential for oil recovery with solution gas drive.
The experiments conducted here provide a qualitative understanding of the foamy oil process and aid in the understanding of solvent based enhanced oil recovery mechanisms such as Cyclic Solvent Injection (CSI).
A Non-thermal Surfactant-Polymer Based Technology for Enhanced Heavy Oil Recovery in Oil Sand and Ultra Shallow Reservoirs
Authors: Wu Yongfu , Mahmoudkhani Amir , Watson Philip , Fenderson Thomas , Kolla Harsha , Nair Mohan 
Published: June 2012

Abstract
Current technologies for in-situ heavy oil recovery involve either heating the reservoirs to liquefy the hydrocarbons or attacking the deposits with solvents. This is usually accomplished by providing a source of external energy such as using natural gas to heat the oil or subjecting it to mechanical stimulation. However, a challenging case is in ultra-shallow reservoirs where the recovery is limited only to matrix oil drainage by gravity. In these cases, many heavy oil reservoirs are too thin to use thermal processes for enhanced heavy oil recovery due to the heat losses to overburden and underburden. In this paper, a study to develop a new technology to increase heavy oil recovery using alkali, surfactant and polymer is presented. It has been found that novel surfactants can create a stable emulsion for heavy oil and formation brine, by which viscosity of heavy oil can be reduced significantly. At 25 °C, the viscosity of heavy oil is 15,785 cP. But when the heavy oil and synthetic brine are emulsified with some new surfactants, the viscosity reduces about 2.88 to 3.46 cP. Therefore, the mobility of heavy oil is improved significantly.
In order to analyze the contribution of the various components to viscosity, a heavy oil sample was separated with a silica gel column. It was found that asphaltenes and resins, the two heaviest and most polar components in the heavy oil, exert the largest influence on the viscosity of heavy oils. Viscosity decreases as temperature increases, which is leveraged by thermal technology for heavy oil recovery. The decrease in viscosity is most pronounced, however, at temperatures below 60 °C. The high viscosity of heavy oil can be dramatically reduced further by emulsification with proper surfactants and alkali, which is the principle behind non-thermal technology for heavy oil recovery.
In this research, emulsions created by the surfactants B and E are stable at 25 °C, and their performance in non-thermal heavy oil recovery was evaluated using sand pack flooding test. 23% of heavy oil recovery was achieved by injection of surfactant B and polymer Superfloc® A-110 HMW. It has also been found that injection of 1.0 PV of surfactant solution followed by injection of 1.0 PV of polymer solution to be the optimum methods for both surfactants B and E. In most cases, Superfloc® A-110 HMW polymer seems to be slightly better than Superfloc® A-120 V for enhanced heavy oil recovery.
Caprock Integrity Case Study for Non-thermal Polymer Flooding Project Using 4D Reservoir Coupled Geomechanical Simulation
Authors: Ansari S. , Haigh R. , Khosravi N. , Khan S. , Han H. , Vishteh M. 
Published: June 2012

Abstract
Maintaining an effective caprock seal is of prime importance in any enhanced oil recovery (EOR) stimulation involving subsurface injection of fluid. Hydraulic or mechanical breaching of the caprock may entail leakage of injected fluids and/or hydrocarbons into shallower formations, or even to the surface, with the potential for adverse environmental impact. Determining a safe optimal injection pressure which minimizes the likelihood of such an occurrence is a challenging problem. For example, assessing caprock integrity with the static stress measurement alone at the virgin state of reservoir without considering dynamic stress changes is likely to be both unreliable and inadequate.
In this paper, we present a case study of hydraulic and mechanical integrity of Wabiskaw caprock at multiple injection scenarios under dynamic conditions. In this study a multi-disciplinary approach was used which integrates geology, petrophysics, reservoir engineering and geomechanics followed by a finite element coupled reservoir-geomechanics simulation. A 3-D mechanical earth model (MEM) was constructed utilizing advanced azimuthal shear anisotropic sonic log and core based mechanical properties. All the available LOT mini-frac as well as MDT micro-frac tests data were assessed and used to calibrate the anisotropic stresses at initialization step in addition to assessing the lateral variability of the vertical stress. Several tight streaks expected to provide additional abutment to the primary caprock were honored in the model. The 3-D MEM was extended to the surface and embedded with the sideburden and underburden layers incorporating adjacent injectors and producers to minimize the boundary effects.
This study evaluated tensile and shear failures within the reservoir and the caprock at several injection scenarios for a period of 30yrs with injection bottomhole pressures of 116 and 155bar at the rate of 150 m3/day. No shear failure or tensile failures were predicted by the coupled geomechanical simulator in the caprock for all the injection scenarios. This model also predicted the vertical displacement within the reservoir, caprock and at the surface. The amount of heave at the ground surface was negligible.
Associative Polymers Outperform Regular Polymers Displacing Heavy Oil in Heterogeneous Systems
Authors: Wassmuth Fred , Green Ken , Bai Jen 
Published: June 2012

Abstract
The use of polymer floods to efficiently displace heavy oils with viscosities up to 10,000 mPa.s has be tested successfully in laboratory scale evaluations; commercial success on the field scale has been achieved with oil viscosities up to 2000 mPa.s in Western Canada1 and other parts of the world1. Since it has been established that the polymer flood technology can be successful at displacing heavy oils on a field scale, it is timely to improve the efficiency of this technology. Researchers have shown that heterogeneities are more detrimental when waterflooding heavy oils than experience obtained from conventional waterfloods3, 4. Hence, it is essential to understand the polymer flood displacement of heavy oil in the presence of heterogeneities. In addition, it was beneficial to conform the impact of large scale heterogeneities with judicious use of associative polymers.
Building a high and low permeability layer into a cylindrical sandpack allowed for demonstrating the impact of heterogeneities on a waterflood and polymer flood displacing heavy oils; the high permeability layer had a permeability 10 times greater than the low permeability layer. The reduced oil recovery in the heterogeneous, dual permeability core can be modeled correctly using a reservoir simulator if a capillary pressure difference curve is introduced during the simulations. The capillary pressure difference curve controls the degree of cross-flow from the high permeability layer to the low permeability layer and corrects the sweep efficiency.
Salinity and hardness tolerant associative polymers suitable for injection into reservoir core have been screened and developed for heavy oil displacement processes. These specialty polymers generate a higher in situ apparent viscosity by forming large hydrodynamic radii through association between polymer molecules. In reservoir applications, these associative polymers may generate tremendous resistance factors in high permeability streaks. The dual permeability corefloods demonstrated that associative polymers outperformed the regular partially hydrolyzed polyacrylamides in two aspects: (1) the associating polymer generated incremental oil recovery after HPAM recovery and (2) the mobility reduction (or resistance factor) of the associative polymers was significantly higher than HPAM. Hence associative polymers can be used for blocking and diverting purposes in high permeability layers where regular polymers may not be as effective.
Challenges While Performing Infill Cementing Amongst Existing SAGD Wells
Authors: Schneider Jason , Sylvestre Chuck 
Published: June 2012

Abstract
The drilling and completing of Infill wells (wells drilled amongst existing SAGD wells) is becoming common practice with many operators in North Eastern Alberta. These Infill wells pose numerous challenges that may not exist in the drilling and completing of a conventional SAGD well. In addition to conventional challenges such as lost circulation that need to be safely managed to have a successful completion strategy, the Infill wellbore has elevated temperatures and heat transfer rates due to contact with or close proximity to a steam chamber. There is no single, universal strategy used by operators to address and control these challenges, which require robust cementing solutions.
Many clients are completing Infill cementing with expected bottom hole circulating temperatures (BHCT) ranging from 35°C to 100°C. This variation in clients’ BHCT results is due in part to the drilling, and more specifically, the circulation strategy used. Static periods of only a few hours can bring the effective temperature to that of the reservoir. As a conventional SADG strategy cannot be used for all wells, a specific blend design utilizing different technologies must be investigated. The large variations in bottom hole static temperature (BHST) and BHCT require complete understanding of the cement blend performance and its specific application. Cement blend designs that are applicable and can perform over a range of temperatures reduce the impact of these challenges.
With the frequency of Infill cementing expected to increase, a greater understanding of the effective wellbore temperatures and the subsequent effective applicable temperature range of cement blends is needed.
Real Time Optimization of SAGD Wells
Authors: Gonzalez Luis E. , Ficocelli Peter , Bostick Tad 
Published: June 2012

Abstract
The SAGD process has been utilized for the past 15 years and an efficient steam utilization process provides the best solution to reducing the variable production costs and to increasing the recovery rate. The use of real time downhole monitoring is an effective approach to achieve this optimization. The main objective of steam injection is to decrease the oil viscosity, so it can flow through the horizontal and the vertical sections.
The emergence of downhole distributed sensing (DTS) and array temperature sensing with fiber optics technology has led to instrumented wells allowing operators to access data on a real time basis leading to a better control of the operations and the ability to optimize the steam process. Additionally, fiber optics technology allows for the measurement of pressure and temperature on same fiber and in close proximity along the wellbore. In the ultra-high temperature environment the amount of pressure monitoring points are limited and many SAGD operators are asking for at least 3 pressure in-conjunction with the distributed temperature points.
The SAGD process has a number of different variables that are dynamic and complex and changing with time. The most important variables of the process include the steam injection rates, subcool and downhole pressure and temperature. One of the key objectives when using the SAGD process is to reduce the SOR to lower the high cost of steam generation. The optimization of the SOR is a process of reducing the steam injection rate and/or increasing the oil production. Since SAGD is a dynamic process this can only be achieved through the use of Real Time Optimization.
Once the steam reduces the viscosity and mobility of the oil is achieved, the SAGD well production can be optimize using the nodal analysis technique meaning that an Inflow (very dependent with temperature & viscosity) will be calculated and optimized but it is also necessary at same time to calculate the outflow which is dependent on the type and optimization of artificial lift system that is used. The integration of different measured points of pressure and temperature (40 points of temperature and 2 pressure points) using fiber optic technology along the horizontal section of the producer well with other parameters like wellhead pressures, temperatures and mainly production rates will allow for the optimization of the SAGD Process and better management of the well.
This paper will describe in detail the processes that are required to be controlled and the main variables that are needed to be measured and calculate to optimize the oil production on a SAGD well.
Numerical Simulation Studies on Development of an Offshore Heavy Oil Field by Early-stage Chemical Flooding
Authors: Sun F. , Zhang X. , Kang X. , Gong B. , Liu W. , Qin G. , Xu J. 
Published: June 2012

Abstract
As one of the major enhanced oil recovery mechanisms, chemical flooding procedure has been widely and successfully used in matured fields and the overall sweep efficiency has been improved between 5–12% due to various chemical flooding treatments. China National Offshore Oil Company (Cnooc) started its pilot offshore chemical flooding projects to evaluate the chemical flooding opportunities at early development phase. In this paper, we present numerical simulation studies on overall evaluation of a Cnooc’s offshore heavy oil chemical flooding project using chemical flooding simulator.
In the numerical simulation studies, we have developed a numerical model with the focus on various complex chemical flooding procedures. Moreover, we have also developed a dynamic well model that is capable of modeling multi-phase flow inside complex multi-lateral wellbores. An algebraic multi-grid linear solver has been developed and implemented into the simulator. As the simulator has been developed following the advanced software architecture design and it can be easily expanded other field applications.
The targeted field in this paper is an offshore heavy-oil field with hundreds of wells and a complex fault system. The production started in 1999, and waterflooding in 2000. In 2007, all water injectors have been switched to polymer injection for better conformance control. In this field-scale reservoir simulation study, the polymer solution, reservoir brine and the injected water are represented as miscible components of the aqueous phase. Key factors such as inaccessible pore volume, polymer shear thinning effect, polymer adsorption, and relative permeability reduction factors have been taken into account for the construction of the mathematical model. Simulations have been run for evaluation on optimal polymer injection timing, amount and pattern.
Prediction of Bitumen and Solvent Mixture Viscosity Using Cubic-Plus-Association Equation of State
Authors: Zirrahi Mohsen , Hassanzadeh Hassan , Abedi Jalal 
Published: June 2012

Abstract
Viscosity is an important transport property for engineering design and simulation of bitumen production and transportation. During the production of bitumen with solvent injection, steam-assisted gravity drainage (SAGD) or expanding solvent steam-assisted gravity drainage (ES-SAGD), the produced fluid is faced with various temperature, pressure and composition conditions. Therefore, a model is necessary to predict the viscosity of the mixture of bitumen and solvent in wide ranges of temperatures, pressures and compositions (T-P-x).
In this work, we propose a semi-theoretical viscosity model based on the Arrhenius mixing rule and considering the effect of association between the molecules of the solvent and the bitumen. To achieve this purpose, thermodynamic perturbation theory (TPT) is used. The association part of the cubic-plus-association (CPA) equation of state (EoS) is applied to calculate the fraction of bonding solvent molecules. We calculate the viscosity of the solvent in wide temperature and pressure ranges using the modified Enskog theory (MET).
Results show an acceptable agreement between the results of this model and experimental viscosity data of saturated bitumen with different solvents (CH4, N2, CO2, and C2H) at various T-P-x ranges. These experimental data cover the typical T-P-x ranges of oil recovery methods.
Forecasting SAGD Process under Geological Uncertainties Using Data-Driven Proxy Model
Authors: Fedutenko E. , Yang C. , Card C. , Nghiem L. 
Published: June 2012

Abstract
Resevoir simulations are routinely employed in the prediction of the performance of SAGD (Steam Assisted Gravity Drainage) process under different operating scenarios. They have been shown to have a significant potential to predict the future performance of SAGD operations. Due to the inherent uncertainty of petroleum reservoir data, the prediction needs to take into account the geological uncertainties associated with a particular reservoir. Usually, this is achieved by obtaining a history-matched model, conditioned to production field data. The model is then used to forecast future production profiles. Since the history match is time restricted to the previous production period, this is essentially an extrapolation problem with respect to time. Hence, such forecasts may not be very accurate. In addition, the simulation time is quite substantial for field studies with a large number of gridblocks. Therefore, forecasting workflows that reduce the number of necessary simulations while providing an accurate prediction are highly beneficial.
This paper presents a new approach for predicting production performance during SAGD process based on the results of SAGD simulations for a case with 3 well pairs. The approach utilizes the following workflow. Firstly, the field data were obtained, which consist of production outputs (particularly - cumulative Oil and cumulative SOR) for a typical time horizon of 5 years and the corresponding operating conditions. Secondly, a number of equiprobable geological realizations was generated using geostatistical methods to describe the permeability and porosity uncertainties of the reservoirs. Thirdly, direct numerical simulations of all realizations were conducted under a production operating scenario for a 10-year period. Then the data-driven proxy model is built that fits the actual field data to a linear, non-local function of the simulation data. The non-locality means that all the 10-year simulation results are considered in the match of the 5-year production data. After that the proxy is used to predict the production field data for the next five years. In this work, since the actual full 10 years of data are known, the predicted data are compared with the actual production data for the same period to evaluate the prediction quality.
This workflow is applied to a synthetic 3-Well-Pair SAGD model. It is shown that the proposed approach provides a highly reliable forecasting procedure for the reservoir considered. The difference between the predicted and actual field data lies within few percents, while the computational cost remains quite low. The use of the proposed approach in the prediction of uncertain reservoir performance under different operating scenarios during the SAGD process is also discussed.