bluuebunny/crossref_metadata_2025_split huggingface dataset:
Research and Application of Nano Polymer Microspheres Diversion Technique of Deep Fluid
Authors: Tian Yuqin , Wang Lushan , Tang Yanyan , Liu Chengjie , Ma Chao , Wang Tao 
Published: June 2012

Abstract
Nano polymer microspheres are a new oil profile control system, which can be adjusted according to the formation pore throat. After hydration and swelling, the microspheres would reach the designed size and have relatively strong intensity. When the size of the microspheres is bigger than that of the formation pore throat or bridged blockage is formed, reliable blockage can be formed. The microspheres are elastic, which can deform and move forward under certain pressure, so that fluid diversion can be realized step by step and the request of movable agent is satisfied. The microspheres can resist high temperature to 110°C and high salinity to 200000mg/L (Ca2++Mg2+=3000 mg/L). To test its effect, this polymer microspheres technology is used at a serious heterogeneous and high temperature reservoir. The temperature of the test block is 98°C, and the salinity of injection water is 16380mg/L. The average permeability is 932×10‒3μm2, and the permeability contrast is obvious (high permeability is 4μm2, low permeability is 0.8μm2). Therefore, two sizes of microspheres are designed. The combination system of polymer microspheres and surfactant are injected, and the system is divided into five slugs. Double tubes physical modeling experiments are done, and the results show that the block off capacity of this design is competent, increasing oil recovery dramatically. Thanks to the accordant microspheres design and the rational injection design, this polymer microspheres technology has become the effective method for profile control and water plugging to serious heterogeneous and high temperature reservoirs.
Fluorescent Nanobeads: a First Step Toward Intelligent Water Tracers
Authors: Agenet Nicolas , Perriat Pascal , Brichart Thomas , Crowther Nicolas , Martini Matteo , Tillement Olivier 
Published: June 2012

Abstract
Reservoir monitoring is an essential tool to optimize oil production. Among other techniques, water tracers are very useful to understand flow patterns between wells (i) during regular waterflood operations, (ii) for EOR pilot or (iii) field development. This paper focuses on the elaboration of a new family of tracers based on fluorescent silica colloids for in situ real-time optical detection. Indeed, these architectures of nanometric size (nanoparticle diameter controllable between 30-100 nm) permit (i) the encapsulation of fluorescent dyes (the intrinsic signal of tracers) and (ii) a tailored interface with the environment (by specific surface functionalization). Dyes, such as organic molecules and/or rare-earth complexes could be quantified by conventional fluorescence apparatus. The smart incorporation of specific fluorophores of different nature within nanobeads allows multi-coding signal of tracers and therefore the possibility to supervise the properties of reservoir. We demonstrate that silica nanobeads could act as sensitive probes of physicochemical conditions of reservoir (volume, pH, temperature, oil ratio, salt content…), because of (i) their specific fluorescence coding, (ii) the long-term colloidal stability in seawater conditions, and (ii) the adaptable real-time monitoring detection setup. Actually, by the procedure described in this work, we are able to produce theoretically dozens of fluorescence tagging combinations based nanoparticles with suitable surface properties. The possible future utilization of fluorescent nanobeads as traces in well exploitation is also demonstrated by core-flood experiments.
Nanoparticle Transport through Porous Media: Screening Tools for Mobility Prediction
Authors: Zies Camila C. , Zhu Huigang , Avendano Carolina , Colvin Vicki 
Published: June 2012

Abstract
Crude oil production has distinct phases of recovery: primary, secondary, and tertiary. After primary and secondary recovery, up to 60% of the hydrocarbon can still remain in the reservoir, needing more advanced recovery techniques. Nanoparticles and their unique size dependent properties can be engineered in a number of high end technologies for enhanced oil recovery (EOR) applications. Naturally, as the average reservoir depth can go anywhere from 35 meters up to 12 km, it is necessary that the nanoparticles present a reasonable mobility, otherwise, without reaching the area of interest, i.e., oil/ water interface, their use would not be feasible. This work aims to study the interaction of different nanoparticles synthesized by our group with a silica substrate, so as to screen the mobility of the particles. This investigation was done using a Quartz Crystal Microbalance with Dissipation (QCM-D) and an Atomic Force Microscope (AFM), with nanoparticles of varying compositions over a wide range of salinity concentrations, and pHs to understand the role these parameters play in the nanoparticle-surface interaction.
Study of Surfactant-Polymer Flooding in Heavy Oil Reservoirs
Authors: Feng Anzhou , Zhang Guicai , Ge Jijiang , Jiang Ping , Pei Haihua , Zhang Jianqiang , Li Ruidong 
Published: June 2012

Abstract
As the alkali in alkaline-surfactant-polymer (ASP) flooding often causes the difficult problems of scaling and emulsification, surfactant-polymer (SP) flooding was proposed for enhancing heavy oil recovery in China. However, it is difficult to reduce the interfacial tension (IFT) to an ultra-low value without alkali for the traditional chemical system. This paper presents a type of betaine surfactant which has an excellent ability to reduce oil/water IFT at low concentration without alkali, and alkali lignin with low-price was compounded as a sacrificial agent to reduce the adsorption. Finally, sandpack flooding tests were conducted to examine the effectiveness of enhanced oil recovery by compound chemical system containing polymer, betaine and alkali lignin.
The results showed that the IFT reduced to 0.001 mN/m or less at a betaine concentration range of 0.01wt% to 0.1wt% without alkali, meeting the requirements of SP flooding; the dynamic adsorption test showed that of the adsorption amount reduced approximately 40% when the mass-ratio of alkali lignin and betaine was 1 to 7.5; moreover, the polymer added into compound surfactant system accelerated the reduction of the oil/water IFT. Sandpack flooding tests indicated that the injected chemical system containing polymer, betaine and alkali lignin after water flooding could enhance oil recovery by 13%~20%, which was significantly higher than that of polymer flooding under the same conditions.
Pressure Maintenance and Improving Oil Recovery via Water-Alternating-CO2 Process in Thin Heavy Oil Reservoirs
Authors: Zheng Sixu , Yang Daoyong 
Published: June 2012

Abstract
Techniques have been developed to experimentally and numerically evaluate performance of water-alternating-CO2 processes in thin heavy oil reservoirs for the purpose of pressure maintenance and improving oil recovery. Experimentally, a three-dimensional (3D) physical model consisting of three horizontal wells and five vertical wells is used to evaluate the performance of water-alternating-CO2 processes. Two well configurations have been designed to examine their effects on heavy oil recovery. The corresponding initial oil saturation, oil production rate, water cut, oil recovery and residual oil saturation distribution are examined under various operating conditions. Subsequently, numerical simulation is performed to match the experimental measurements and optimize the operating parameters (e.g., slug size and water-CO2 ratio). It has been shown that water-alternating-CO2 processes implemented with horizontal wells can be optimized to significantly improve performance of pressure maintenance and improving oil recovery in thin heavy oil reservoirs. The incremental oil recovery of 12.4% and 8.9% through three water-alternating-CO2 cycles are experimentally achieved for the aforementioned two well configurations, respectively. The excellent agreement between the measured and simulated cumulative oil production indicates that the displacement mechanisms governed water-alternating-CO2 processes have been numerically simulated and matched. The WAG ratios of 0.75 and 1.00 are found to be the optimum values for Scenarios #1 and #2, respectively.
Viscosifying Surfactant Technology for Heavy Oil Reservoirs
Authors: Morvan M. , Degré G. , Beaumont J. , Colin A. , Dupuis G. , Zaitoun A. , Al-Maamari R. S. , Al-Hasmi A. R. , Al-Sharji H. H. 
Published: June 2012

Abstract
Injections of polymer solutions have been used to improve oil recovery in heavy oil reservoirs (Zaitoun et al. 1998). Most of those polymer flood experiences refer to conditions where the polymer solution propagates through the porous media under low shear rate and exhibits mostly a Newtonian behaviour. On the other hand recent publications indicate injection of polymer solutions at concentration larger than conventional polymer flooding can result in higher recovery at field scale. Typically oil recovery of more than 20% OOIP compared to waterflooding has been reported for light oil (Wang et al; 2011). However injectivity issues have to be considered when injecting concentrated polymer solutions. This study examines whether non polymeric elastic fluids derived from surfactant solutions can represent an alternative approach to elastic polymer floods. The technology we have developed matches the rheological properties of polymer solutions in a broad range of reservoir conditions (temperature & salinity).
Bulk flow properties as well as rheology in a confined geometry have been used to compare flow properties of surfactant and high molecular weight polymer solutions. The elastic properties of both fluids have been characterized in terms of Weissenberg numbers. The data indicate the surfactant solution as opposed to the polymer one is highly elastic at low shear rates even in the presence of brine. Those results are confirmed by comparative experiments made using a Particle Image Velocimetry (PIV) technique. Injectivity of concentrated surfactant solutions has been tested in single-phase conditions and indicated a good in depth propagation of the fluid. A series of core-flood experiments has been performed using heavy oil reservoir cores. The surfactant slug has been combined with a conventional low-concentration polymer flooding to benefit from surfactant elasticity and improve oil recovery.
A Novel Methodology for Simultaneous Estimation of Gas Diffusivity and Solubility in Bitumens and Heavy Oils
Authors: Saboorian-Jooybari Hadi 
Published: June 2012

Abstract
The most important parameters in the calculation of the rate and extent of gas dissolution during solvent-based heavy oil recovery processes are diffusion coefficient and solubility. However, there is a lack of sufficient experimental data on these parameters. Further, significant differences associated with reported values of diffusivities because of various nonphysical approximations made in development of the models used for calculation of this coefficient from the pressure-decay tests.
This paper presents an inverse solution technique for determining solubility, diffusion coefficient and interface mass transfer coefficient of gases in liquids (bitumens) using pressure-decay data. The approach, which is based on modeling the rate of pressure decline in response to gas diffusion, couples gas mass balance equation with the diffusion equation. Analytical solution for the forward problem is obtained by assigning physically meaningful initial and boundary conditions. Then, the forward solution is utilized to develop an interpretation technique for simultaneous determination of the equilibrium solubility, diffusivity and interface mass transfer coefficient of gas into oil. To evaluate the validity of the proposed technique, literature pressure-decay data of CH4 and CO2 dissolution in Athabasca bitumen at two different temperatures (50 and 90 °C) and initial pressure of 8 MPa were used. The simultaneous estimation of the three mass transfer parameters is the main advantage of the new methodology over the existing ones. Additionally, the calculation method doesn’t depend on empirically-defined unknowns such as Henry’s constant, density of solvent-bitumen mixture and etc. Eventually, the effect of neglecting gas-bitumen interface resistance on the predicted values of gas solubility and diffusivity was investigated.
Gel Treatments Pilot Test in Conventional Heavy Oil Reservoirs of China Offshore Oil Field
Authors: Su Yanchun , Li Yanlai , Tian Lixin , Ma Kuiqian , Wang Lilei 
Published: June 2012

Abstract
More than 80% oil resources were heavy oil in Bohai Bay of China. Generally, we used water flooding in the reservoirs with the viscosity less than 400cp. But there were many challenges during water injection in conventional heavy oil reservoirs because high oil-water viscosity ratio lead quick breakthrough of injecting water. And with the oil-water viscosity ratio increasing, the breakthrough of injecting water became more serious. In order to solve these problems, the gel treatments on the injection wells pilot test were conducted in x oilfield during the year 2009 to 2011. Before pilot test, laboratory study under field conditions was conducted to determine the chemical parameters of the gel. We also did numerical simulation study with CMG. A range of variation of critical parameters was evaluated in the simulation for understanding the gelation process undergroud. The model was used to predict the reservoir response under different chemical parameters. Results from simulation showed that water cut reduction ranged from 15.9 to 36.6% which matched the trends observed in wells. On the other hand, dynamic method was also used to evaluate the gel pilot test. The Hall curve analysis was used to evaluate the effectiveness of the injection well and to calculate the resistance factor (RF) & residual resistance factor (RRF) (RF from 1.82 to 6.88, and RRF from 1.29 to 7.97). The decline curve analysis was used to obtain net incremental oil by gel injection treatment. Results from two well patterns conducted gel pilot test in 2009 indicated that water cut reduction ranged from 3.2 to 36.8% and average oil production increases 15.7m3/d. Based on results, another two wells in 2010 and two wells in 2011 were conducted, and we received good effectiveness by gel treatments.
The pilot test & evaluation technology provide the foundation for promoting application of techniques to stabilize oil rate and control water production in conventional heavy oil reservoirs of China offshore oilfield
The Effect of Bottom Water Coning and Its Monitoring for Optimization in SAGD
Authors: Shahbaz Masih , Kevin Ma , Sanchez Julio , Patino Fabian , Boida Lindsey 
Published: June 2012

Abstract
The performance of steam assisted gravity drainage (SAGD) depends, mainly, upon reservoir characteristics e.g. porosity, permeability and heterogeneity, well bore hydraulics e.g. steam quality, the length and size of wellbores and operational parameters e.g. reservoir and wellbore subcools. However, in reservoirs with underlying bottom water, the performance of SAGD depends on vertical offset between bottom water and producer and pressure differential between bottom water pressure and bottom hole flowing pressure of the producer. Bottom water can act as a heat sink is a known fact, therefore, it can affect project oil rate, steam rate, steam oil ratio (SOR) and, ultimately, the economics of the project. Bottom water can affect heat transfer within reservoir by the injected steam in case of water coning or steam loss to the bottom water. Produced water chlorides concentration (PPM) is an important indication of bottom water coning because of difference in the chemistry of injected steam and bottom water. The chlorides material balance depends upon water saturation in bitumen zone (connate water), formation water chlorides concentration, produced water chlorides concentration and water cut. This study will shed light on significant impact of bottom water coning on SAGD performance through reservoir simulations. It will, also, describe contribution of each of the aforementioned parameters (water saturation in bitumen zone, formation water chlorides concentration, water cut and produced water chlorides concentration), which is very significant, on chlorides PPM material balance for bottom water coning analysis. And it will, also, describe how the safe limit of produced water chlorides PPM (produced water chlorides PPM at which no bottom water is produced) is affected by each of these parameters.
Study of Solvent Injection Strategy in ES-SAGD Process
Authors: Jiang H. , Deng X. , Huang H. , Beaulieu G. , Heck G. , Akinlade O. G. , Nasr T. N. 
Published: June 2012

Abstract
This paper presents a simulation study on the operational parameters of the ES-SAGD process based on an ES-SAGD lab experiment. A numerical model that incorporated the measured data on key physical properties was validated by detailed history matching of the ES-SAGD lab experiment with n-hexane as the solvent. This numerical model was used to evaluate the performance of ES-SAGD with different operating strategies. The simulation results indicate that oil rate lifting from hexane injection is significant in the early stage of the ES-SAGD process but becomes less effective in the later stage of the process. Improved solvent efficiency can be achieved by adjusting operating parameters such as the start time for steam-solvent co-injection, the duration of the steam-solvent co-injection period and the solvent concentration in the steam-solvent injectant. Results from this study could provide a guideline for the design of a solvent injection strategy for field application of ES-SAGD process.
In Situ Combustion as a Followup Process to CHOPS
Authors: Chen Joyce , Coates Roy , Oldakowski Kaz , Wiwchar Brian 
Published: June 2012

Abstract
There are a large and growing number of Western Canadian heavy oil deposits that have been depleted using primary cold production (CHOPS) methods. At their economic limit these methods leave behind 85 % to 90 % of the OOIP while significantly altering the reservoir conditions from their initial state. The oil remaining is a significant target for a follow up process; however, presently there is no demonstrated EOR process that can economically recover additional oil from these deposits in their current condition.
The application of in situ combustion in a reservoir that has under gone CHOPS has several attractive features. The wormhole network created during primary production provides the injectivity required to initiate and sustain high temperature combustion. The interconnected wormhole channels between adjacent wells supplies a conduit for mobilized oil to flow to production well thus minimizing liquid blockage and ineffective conformance.
To assess the potential of in situ combustion as a post CHOPS process a laboratory study was carried out examining the behavior of in situ combustion under conditions representative of the reservoir at the end of CHOPS. A total of seven physical simulation experiments were carried out in the Heavy Oil and Oil Sands laboratory of the Alberta Research Council (now part of Alberta Innovates – Technology Future). Test conditions of these experiments included high permeability channel vs. no high permeability zone, partially filled high permeability channel vs. completely open channel, dead oil vs. live oil dry combustion vs. wet combustion, and normal air vs. enriched air injection,.
Results of the experiments are encouraging for the application of in situ combustion in CHOPS reservoirs. The high permeability wormhole channels provided injectivity to initiate and sustain combustion and the presence of the channel lead to improved conformance with no gravity overriding of the combustion front. Localized coke plugging of the channel prevented the combustion front from prematurely breaking through to the production well, even with a completely open wormhole channel.
Feasibility Study of Hot Waterflooding Technique to Enhance Heavy Oil Recovery: Investigation of the Effect of Well Spacing, Horizontal Well Configuration and Injection Parameters
Authors: Torabi F. , Qazvini Firouz A. , Crockett M. , Emmons S. 
Published: June 2012

Abstract
Among several oil recovery techniques, hot waterflooding through thermal displacement processes could potentially increase oil recovery by decreasing oil viscosity, thus decreasing the mobility ratio at a relatively low cost compared to other thermal methods such as SAGD or in-situ combustion. These methods can also be applied in specific in-situ conditions such as formation sensitivity to fresh water. This paper examines the performance and feasibility of hot waterflooding and compares the performance with a conventional recovery scheme of a heavy oil reservoir with an oil gravity of 10.6 °API and viscosity of 13,400 mPa‧s (at 22 °C) from the Lloydminster area (Canada); the approach includes numerical thermal simulation and economical analysis of each process. First, the performance of a hot waterflood on a generic model consisting of a 5-spot injection pattern was investigated. Then four field designs were recognized from several previously analyzed patterns. The effect of well spacing, horizontal well configuration, injection parameters, as well as the impact of incremental temperature adjustment of waterflood on heavy oil recovery were studied. More than 220 models were built on the final patterns and the most economic configuration was found to have four horizontal producers and four horizontal injectors with a well spacing of 67 m. This arrangement resulted in a recovery factor of more than 30 % of the oil originally in place (OOIP). The most economic injection rate was determined to be 400 m3/day of water at optimum injection temperature of 80 °C. It was also observed that by increasing the temperature of the injected water, the oil viscosity could be reduced to less than 100 mPa‧s. This improved the oil recovery and production rate, delayed injection breakthrough, and reduced water cut. From the results, the highest injection temperature of 100 °C could be recommended; however, the incremental oil versus the amount of heat and facilities required would not be justifiable from an economic point of view.