bluuebunny/crossref_metadata_2025_split huggingface dataset:
Optimized Surfactant–Polymer Flooding for Western Canadian Heavy Oils
Authors: Luo P. , Wu Y. , Huang S. 
Published: June 2013

Abstract
Chemical flooding for Western Canadian heavy oil reservoirs has gained popularity in recent years because of its satisfactory recovery efficiency and low facility cost. Formation brines in most of these reservoirs have extremely high salinity and hardness. Addition of alkali is prone to causing severe precipitation/scaling problems in both the injection/formation brinesand production facilities. As well, breaking of the emulsion generated during oil production is problematic in the presence of alkali. In order to overcome the operation/handling issues associated with alkali, an alkali-free surfactant–polymer (SP) flooding EOR method needs to be developed and evaluated.
In this work, several amphoteric surfactants, which exhibit higher salinity- and hardness-resistance than common anionic surfactants, were evaluated in combination with the polymer polyacrylamide. For the crude heavy oil and brine studied, a fairly low interfacial tension (IFT) of 0.012 dyne/cm was measured at 0.1 wt% of surfactant concentration. Emulsification tests showed that the surfactant could easily generate oil-in-water emulsion in the heavy oil–brine system, while it was more difficult to form emulsion with the SP system due to its higher viscosity. Addition of the surfactant helped to slightly increase the polymer solution's viscosity, since the surfactant itself is a viscoelastic fluid. The SP system exhibited long-term stability with consistent viscosity and IFT, whereas an alkaline–surfactant–polymer (ASP) system had increased viscosity for the first 15 days due to solids precipitation in the brine and possible polymer hydrolysis.
To compare the recovery efficiency by different chemical injectants, three coreflood tests were conducted using P, SP, or ASP systems. ASP flooding had the highest enhanced oil recovery (chemical injection + extended waterflood] of 25.17% original oil in place (OOIP), followed by SP flooding (24.38% OOIP) and P flooding (20.23% OOIP). However, the potential for operational problems evident with the use of alkali might restrict the application of ASP flooding. Varied oil recoveries at the chemical injection and EWF stages, as well as pressure drop variation (resistance factor), indicated that different recovery mechanisms were involved in each chemical flood. Given its satisfactory recovery results and potential to avoid operational problems, with careful optimization, SP flooding presents a promising method for heavy oil enhanced oil recovery, particularly for Western Canadian heavy oil reservoirs.
Method for Attenuation Calibration of Dual Wavelength Raman Distributed Temperature Sensing Systems
Authors: Mitchell Ian , Walsh Russ 
Published: June 2013

Abstract
In this paper we report on a novel technique of applying dual-wavelength Distributed Temperature Sensing (DTS) interrogators to auto-adjust for differential attenuation caused by macro-bending and scattering/absorption based losses. We present the results of a comparison between dual-wavelength technology and traditional single wavelength systems.
Streamline Based Coupled Geomechanics and Reservoir Simulation for Hydromechanical Modelling of CO2 Storage in Saline Aquifers
Authors: Hosseini Behrooz Koohmareh , Chalaturnyk Rick 
Published: June 2013

AbstractMost recent studies on hydro-mechanical simulation of underground CO2 storage in saline aquifers have been focused either on the early reservoir life and short term migration of CO2 plume, or on near field scenarios in the vicinity of injection well. The main reason is the crucial computational cost that current coupling schemes and simulators carry out. Particularly, realistic inclusion of geomechanics into fluid flow processes is a bottle neck in hydro-mechanical coupling of large heterogeneous models of stress sensitive reservoirs with complex fluid flow and geomechanical physics. This work introduces a new coupling scheme between fluid flow and rock deformation, for rapid hydro-mechanical simulation of large heterogeneous reservoirs with elastic geomechanical constitutive behaviors. The technique is mainly about using of streamline simulations for hydro-mechanical coupling purposes. To assess the efficiency of the technique in terms of speed and accuracy, a large reservoir-cap rock system with relatively large number of grid-blocks was made. The speed and robustness of streamline-based hydromechanical coupling was investigated versus finite volume based flow-geomechanical simulations for the same model with the same geometry and physics. The concept of effective stress was applied in characterizing the stress state. The governing geomechanical and fluid flow equations were implemented based on mass and momentum balance equation for linear elastic materials. Forward flow streamline simulation was performed with 3DSL, which is developed on the FORTRAN platform. This paper first investigated the feasibility of inclusion of geomechanics in streamline simulation, and in the next step compared the efficiency and accuracy of the developed scheme to one of the conventional finite-volume based fluid flow-geomechanical simulations. The FV-FEA tool was developed based on Box-method (subdomain collocated finite-volume finite-element technique) to couple fluid flow and geomechanics to be compared with the so called SL-based hydromechanical coupling. The simulation results and comparative studies between two appraoches, demonstrated that the introduced technique is robust and increases the model efficiency and decreases the computational costs significantly. The approach also demonstrated to be helpful in hydromechanical coupling of CO2 storage, particularly for large domains and during the injection period.
Wellbore Efficiency Model for CO2 Geological Storage Part I: Theory and Wellbore Element
Authors: Nabih Ahmad , Chalaturnyk Richard 
Published: June 2013

Abstract
Storing carbon dioxide (CO2) in deep geological formations is one part of the carbon capture and storage (CCS) process. The process of storing CO2 into deep geological formations is defined as geological CO2 sequestration or CO2 geo-sequestration. Injecting CO2 into a reservoir does not guarantee safe storage because CO2 could leak back to the surface and/or may contaminate specific strata where other energy, mineral and/or groundwater resources are present. Two mechanisms control assurance of storage integrity, which are containment within the geological structure and minimizing the potential for wellbore leakage (Espie, 2005).
This study is concerned with describing the wellbore leakage mechanism utilizing wellbore element, which will be extended to the whole wellbore system. To get a better chance of success in practice, successful CCS depends on the small-scale leakage problem associated with localized flow along wellbores. Our knowledge of wellbore performance for storage purposes is still weak.
The paper is the first of a series to model wellbore element analytically by introducing wellbore sealing efficiency index. Wellbore sealing efficiency can be used as a ranking criteria between different wellbore elements in the same well and/or different wells in the same locality. Moreover, safety performance of wellbore element can be assessed.
Consideration of Geomechanics for In-situ Bitumen Recovery in Xinjiang, China
Authors: Yuan Xinsheng , Dou Shenjun , Zhang Jing , Chen Sen , Xu Bin 
Published: June 2013

Abstract
This paper describes a geomechanical work program carried out in Karamay heavy oil field, Xinjiang Province, China. Three mini-frac tests were conducted to measure the in-situ minimum stresses in the reservoir sands, shale interbed and caprock shales. Geomechanical triaxial tests under room- and high-temperature were completed to investigate the geomechanical properties of the reservoir sands. These works were motivated by repeating the success experienced in Alberta oilsands reservoirs which proactively use geomechanics to enhance the in-situ thermal recovery. One particular technology, i.e. using geomechanical dilation mechanism for early SAGD start-up was successfully demonstrated on one SAGD well pair in the Karamay reservoir. The results from the mini-frac tests and laboratory tests are presented and compared with the oilsands reservoirs in Alberta, Canada. Differences were discovered. Petrophysical and mineralogical measurements were made and geological origins are sought to explain the difference. Furthermore, relevant results from the dilation start-up demonstration are also shared to the end of this paper. Such success has proven again that geomechanics is equally important in the optimization of in-situ thermal stimulation of the heavy oil reservoirs in Karamay heavy oil field.
A Transient Two-phase Fluid and Heat Flow Model for Gas-lift Assisted Waxy Crude Wells with Periodical Electric Heating
Authors: Han Guoqing , Zhang He , Ling Kegang 
Published: June 2013

Abstract
This paper presents innovative iteration algorithms for multi-interface heat transfer in pipe flow. To the best of our knowledge, this is the first approach derived from Drift-flux Model (DFM), which is more competent than mechanistic models for high slippage gas-liquid flow. Consequently, the temperature/pressure distribution profiles can be accurately captured under transient condition.
For waxy crude fields, it's critical to sustain the flowing temperature above the Wax Appearance Temperature (WAT). This is especially challenging for gas-lift assisted wells. The injected gas, commonly at relatively low temperature, leads this flow assurance problem sophisticated. An effective practice is to heat up the flowing fluid by installing an electrical cable in tubing. Such the heat exchange happens at three interfaces in the production system: between cable and flowing crude, flowing crude and injected gas, injected gas and formation. Therefore, it is challenging to model such a multiphase production system including an inner annulus inside tubing as the electrical able installed, and an outer annulus where the gas is injected. To optimize this production system, a rigorous transient multiphase and multi-interface heat transfer simulator has been demanded.
With explicitly integrating with the subsurface boundary condition, our new algorithms can optimize the cable length, heating period, supplied power, or gas injection rate for the aforementioned production system. This new method has been successfully applied for several gas-lift assisted wells in a waxy crude field located in north China. The power consumption has been noticeably decreased by 30% than the historical field performance. The delegated optimization scheme reduces the shut-in time in winters, which has promised a cost-saving development.
The presented model not only satisfies the exceptional modeling requirements for periodically-heating crude producers, but also it is appropriate for other heat transfer investigations under transient multi-interface and multiphase flow condition.
Rodless PCP Technology: From Theory to Reality; Analyzing One Year of Performance
Authors: Garcia Gilberto Jose 
Published: June 2013

Abstract
Oil producers have been utilizing Progressing Cavity Pumps (PCP) for decades, as it is the optimal method of artificial lift to effectively handle fluids with high solid content. These wells can be vertical, directional or horizontal, while the latter two optimize in-flow performance and maximize fluid rates. Conversely, these well-bore geometries create high contact loading between the rod and tubing, which ultimately leads to an increased and costly intervention frequency to repair failed rod and/or tubing. While there are several products that exist to prolong run-time in these environments (Endless Rod, Tubing Rotators, etc.), these failures cannot be entirely eliminated, and in some cases make these wells uneconomical to produce.
The oil industry has been looking for an alternative to effectively and economically produce these troublesome oil wells. Many producers have been on a crusade seeking an alternative to a conventional rod driven PC Pump. This crusade has led to the development of a Rod-less PCP system, allowing the full benefit of the pumps ability to handle solids, while eliminating the primary cause of failure: the rod string.
A major requirement to effectively operate a Rod-less PCP system is the ability to provide sufficient rotational torque. With this in mind, a team of industry professionals in their respective fields (Electrical Submersible Pumps, PCP, and Sensor-less Surface Control or SSC) began working cohesively to develop an all-inclusive system. The system provides full surface control and monitoring using the down-hole intake/discharge pressure gauges, a vibration sensor, and a motor winding thermocouple.
Shale Barrier Failure Strategies in Heterogeneous SAGD Reservoirs: A Case Study
Authors: Wu Yongbin , Jiang Youwei , He Wanjun , Guan Wenlong , Zhao Xin , Qi Shilong 
Published: June 2013

Abstract
In Xinjiang, China, a huge volume of heavy oil deposits is not commercially developed yet due to the high in-situ oil viscosity that is higher than 100,000 to 1,000,000+ cp and the strong reservoir heterogeneity. Two SAGD pilot tests with 11 wellpairs in total have been carried out since 2008 while the extensively distribution of shale barriers result in the poor SAGD steam chamber conformance, low production rate and high SOR.
This paper presents the workflow to break shale barriers to improve the steam chamber development along horizontal section, to reduce the SOR and to enhance the economic performance. The first step of the workflow is to select representative core and shale barrier samples and quantify the geomechanic data by high-pressure-high temperature dilation and shale barrier failure experiments. Meanwhile, the geologic model is built taking into account geological uncertainties of the reservoir and the core analysis results. And then, a small set of SAGD wellpair models are selected as the typical wellpair models by classifying different patterns of shale barriers distribution along horizontal section. Finally, the upscaled thermal reservoir models with geomechanics models using the data acquired by geomechanic experiments are investigated to model and optimize operation strategies for dynamic fracturing and shale barrier failure during SAGD phase.
The research reveals that the high-pressure CSS is an effective method to break the shale barrier distributed between the horizontal segments of the producer and the injector, which has been verified by field experience and the numerical simulation. It is forecasted that the case without HP-CSS will have the steam chamber growth at 50% percent of horizontal segment, which is 40% less than the case CSS. The ultimate oil recovery factor is 34.54%, which is 16.31% less than the case with HP-CSS; and the cumulative oil/steam ratio is 0.175,, which is 14.5% less than the case with HP-CSS, encouraging SAGD performance after HP-CSS shows a better economic performance, which is worthwhile to carry out and also has a significant guidance for the similar SAGD reservoirs to improve the performance.
Cold Heavy Oil Development: Learn from the Past, Plan for the Future
Authors: Tg. Othman Tg Rasidi , El Emam M Medhat , Tewari Raj Deo , Ramli Anis Salwa , Anasir Nadiah , A. Rahman M. Izzat , Sulleh Shahida , M. Ahmed Sameh 
Published: June 2013

Abstract
Worldwide energy demand is continuously increasing with the current pace of development and oil continues to play a crucial role in total energy mix. It is becoming difficult to meet the demand of crude oil with existing light and medium crude oilfields as production from these fields which are mostly in matured stage, are declining. This has necessitated more attention for increasing the exploitation of heavy and extra heavy oilfields.
Estimates of recovery factors contain inherent uncertainty especially more in early stage. The range of uncertainty in estimates of reserves depends mainly on the degree of geologic complexity, the maturity of the asset, the quality and quantity of geologic and engineering data and the operating environment. Therefore, it becomes critical to understand and determine reservoir parameters which are crucial in estimation and prediction of well and field performance in heavy oilfields. Well spacing, completion techniques, operating practices and regulations can have a significant influence on ultimate recovery.
Primary recoveries from heavy and extra heavy oil fields are very low in cold production mode. Therefore, application of thermal enhanced oil recovery becomes inevitable to improve the recovery from such reservoirs. However, cold production is still favorable at early stage due to low upfront investment.
This study has reviewed and analyzed the development and performance of large number of fields of various sizes under cold production spread over different parts of the globe and developed statistical relationships between geologic-engineering parameters and deliverables like recovery and production. These empirical relations can form basis and be used as guiding principles for heavy oil asset evaluation, initiating the early primary development and their benchmarking to the established industry practices in cold production.
How Heavy Gas Solvents Reduce Heavy Oil Viscosity?
Authors: Imai Motonao , Nishioka Ichiro , Nakano Masanori , Kaneko Fuminori 
Published: June 2013

Abstract
In the past decade, in-situ heavy oil recovery processes have been proposed and successfully applied to field operations. In conventional ways like cyclic steam stimulation (CSS) and steam assisted gravity drainage (SAGD), viscosity of heavy oil is reduced by steam injection. However, since the cost of steam generation remains high, solvent injection has been considered to decrease steam-oil ratio (SOR). In many cases, solvent means relatively heavy hydrocarbon gas components ranging from C3 to C6. In this paper, we discuss the effect of heavy gas solvents on viscosity reduction.
Our target reservoir is the Yufutsu oil field, Hokkaido, Japan. Its produced oil is highly viscous and we have to consider an enhanced oil recovery process. Viscosity and gravity of the Yufutsu fluid are 846 cP and 11°API respectively at stock tank condition. Since gas injection is one reasonable choice to reduce oil viscosity, we conducted swelling tests and viscosity measurements using two different gas samples. The first gas sample is a light gas mixture which is a main product of the facility and pipelined to the markets. The second one is a heavy gas mixture which is a subsidiary product of the manufacturing processes, and contains C2, C3 and C4 components significantly. According to our swelling tests, the heavy gas mixture achieved greater swelling factor and viscosity reduction than the other. In terms of viscosity reduction, the heavy gas achieved 94%, while the light gas achieved 88%.
Additionally, we conducted simulation studies to examine the effect of heavy gas solvent on viscosity reduction. We generated 2-dimentional preliminary heavy oil reservoir models. The results of simulation studies indicate that the injection of heavy gas solvent reduces oil viscosity, and increases oil recovery more than the light gas case.
In conclusion, according to our experiments and simulation analyses, the heavy gas solvent shows more oil viscosity reduction than the light gas solvent. This fact implies the heavy gas components, C2, C3 and C4, play important roles in oil viscosity reduction, and will help to decide an optimal composition of solvents in heavy oil production.
A State-of-the-Art Computational Fluid Dynamics Simulation for Erosion Rates Prediction in a Bottom Hole Electrical Submersible Pump
Authors: Marsis Emanuel , Russell Ronnie 
Published: June 2013

Abstract
Electrical submersible pumps (ESP) are used extensively in the production of oil and gas. A multi-vane pump is a special type of ESP designed to handle high gas volume fractions and eliminate gas lock. Erosion in ESP systems due to sand production is a major problem that can cause equipment failure. Extensive numerical study has been performed to simulate the flow of sand particles inside a multi-vane ESP pump.
This study utilizes two computational fluid dynamics (CFD) erosion models. The first CFD erosion calculation model, ERC-2003, was empirically developed in 2003 by Russell et al. (Russell 2004), and applied in this paper to predict erosion rates inside an ESP. The second CFD erosion model, ERC-2008, is a modification developed by Ronnie Russell in 2008 to broaden the accuracy range to low-velocity flow. A state-of-the-art erosion prediction technique is presented in this paper. The generalized CFD code utilized in the simulations in this paper was ANSYS Fluent for erosion prediction. Discrete phase models (DPM) and Eulerian-Eulerian granular models were compared, and the pump pressure head was used to validate the hydrodynamic models. Results show that the pump diffuser casing and impeller blades' pressure sides consistently have the highest erosion rates. In addition, the Eulerian-Eulerian granular model shows a more homogenous distribution of sand concentration in the pump compared to the DPM model. The main difference between the two models is that the Eulerian- Eulerian granular model considers the two phases and solves for each phase separately from the beginning of the simulation, while the DPM model stops the fluid iterations to carry out its discrete particle tracking iterations. Therefore, the Eulerian- Eulerian granular model can predict erosion in turbomachinery more accurately compared to the DPM model.