bluuebunny/crossref_metadata_2025_split huggingface dataset:
Physical Modeling of Solvent-Assisted SAGD
Authors: Khaledi Rahman , Beckman Mark , Pustanyk Karl , Mohan Aruna , Wattenbarger Chick , Dickson Jasper , Boone Thomas 
Published: June 2012

Abstract
Physical modeling of heavy oil recovery processes is a critical step in evaluating their technical feasibility. Results from physical modeling studies, in conjunction with simulation and analytical modeling, are key to technically justifying field trials and pilots. Proper scaling of reservoir model dimensions, reservoir properties and energy boundary conditions, operating condition monitoring and control, and production data analysis are very important aspects of physical model design and operation for evaluating the performance of a heavy oil recovery process. This paper describes physical modeling and performance evaluation of the Solvent-Assisted SAGD (SA-SAGD) process applied to Athabasca oil sand reservoirs with focus on process optimization under low operating pressure condition. The paper presents the design features of the physical model used for testing that ensures reliability and reproducibility of the experimental results. The results of laboratory testing are shown with emphasis on demonstrating the reliability and reproducibility of the test results.
Experimental Investigation of HLP Nanofluid Potential to Enhance Oil Recovery: A Mechanistic Approach
Authors: Shahrabadi Abbas , Bagherzadeh Hadi , Roustaei Abbas , Golghanddashti Hassan 
Published: June 2012

Abstract
Regarding the most reservoirs around the world are experiencing their second half of life, the need for an appropriate EOR method utilizing efficient new technologies gets more important. Nanotechnology is an advanced technology finding its place in EOR processes as it provides a high potential for oil and gas recovery.
In this study, a special type of polysilicon nanoparticle (HLP, Hydrophobic and Lipophilic Polysilicon) is investigated as an EOR agent during different water injection scenarios. The water-wet sandstone core samples are employed. Injection of HLP nanoparticle dispersed in a carrier fluid can improve oil recovery through two mechanisms: reduction of interfacial tension and wettability alteration. Reduction of interfacial tension improves pore-scale displacement efficiency. In addition, wettability alteration towards less water-wet condition provides an ideal wetting state increasing oil recovery. Three scenarios of HLP nanofluid injections are applied. First, the nanofluid is injected after waterflooding at ultimate oil saturation. Second, 3 porevolume water injection is applied after the sequence of water and HLP nanofluid injections. Third, HLP nanofluid is injected from beginning. HLP nanofluid application lowers the oil-water interfacial tension by a factor of ten as well as changing the contact angle from 123° to 99°indicating less water wet condition. The experienced oil recoveries and pressure drops during the experiments are reported for each scenario. In all scenarios, the most of oil recovered through the first injected pore volume. According to oil recoveries, nanofluid injection from the beginning can enhance oil production considerably in compare to the other ones. Moreover, pressure drop data indicate severe permeability impairment after three pore-volume injection of nanofluids. Experimentally, nanotechnology has proved its potential to enhance oil recovery however many aspects are still in progress to be known.
Influence of Nanomaterials in Oilwell Cement Hydration and Mechanical Properties
Authors: Santra Ashok , Boul Peter J. , Pang Xueyu 
Published: June 2012

Abstract
Nanotechnology encompasses a wide scope of disciplines and nanomaterials are now being used as commercially viable solutions to technical challenges in industries ranging from electronics to bio-medicine. Recently, the application of nanomaterials to solve problems in oilwell cementing has begun to be investigated by several different research groups in the oil and gas industry. The following uses of nanomaterials have been presented by several independent laboratories as possibilities in the oilwell cementing industry: (1) nanosilica and nanoalumina as potential accelerators; (2) nanomaterials including carbon nanotubes (CNTs) with high aspect ratio to enhance mechanical properties; (3) nanomaterials to reduce permeability/porosity; and (4) nanomaterials to increase thermal and/or electrical conductivity.
In this paper, a review of the aforementioned application concepts is presented with a focus on understanding the role of multiwall CNTs (MWNTs), nanosilica, and nanoalumina in oilwell cement hydration chemistry. The influence of the integration of MWNTs into oilwell cement on the physical properties of cement is discussed. Results from an isothermal microcalorimetric study are presented to help understand the difference between the mode of acceleration of a typical cement accelerator, like CaCl2, compared to nanosilica and/or nanoalumina.
The Viscosity of Silica Nanoparticle Dispersions in Permeable Media
Authors: Metin Cigdem Omurlu , Bonnecaze Roger T. , Nguyen Quoc P. 
Published: June 2012

Abstract
The potential application of nanoparticle dispersions as formation stimulation agents, contrast agents or simply as tracers in upstream oil and gas industry requires knowledge of the flow properties of these nanoparticles. The modeling of nanoparticle transport in hydrocarbon reservoirs requires a comprehensive understanding of the rheological behavior of these nanofluids. Silica nanoparticles have been commonly used because of their low-cost fabrication and cost-effective surface modification. The aqueous silica nanoparticle dispersions show Newtonian behavior under steady shear measurements controlled by a rheometer as discussed by Metin et al. [1]. The viscosity of nanoparticle dispersions depends strongly on the particle concentration and that this correlation can be depicted by a unified rheological model [1]. In addition, during flow in permeable media, the variation of shear associated with complex pore morphology and the interactions between the nanoparticles and tortuous flow channels can affect the viscosity of nanoparticle dispersion. The latter is particularly important where the concentration of nanoparticles in dispersion may change because of nanoparticle adsorption on mineral/fluid and oil/water interfaces or by mechanical trapping of nanoparticles. In this paper, the flow of silica nanoparticle dispersions through different permeable media is investigated. The rheological behaviors of the dispersions are compared with those determined using a rheometer. We established a correlation between the nanoparticle concentration and dispersion viscosity in porous media for various nanoparticle sizes. The effects of pore structure and shear rate are also studied. We have confirmed that the concept of effective maximum packing fraction can be applied to describe the viscosity of aqueous nanoparticle dispersions in both bulk flow and flow in porous media with high permeability and regular pore structures but not at low permeability because of mechanical trapping. Our work provides new insight to engineering nanoparticle rheology for subsurface applications.
High Strength Nanostructured Materials and Their Oil Field Applications
Authors: Zhang Zhihui , Xu Zhiyue , Salinas Bobby 
Published: June 2012

Abstract
High strength Al nanostructured materials have attracted increasing attention for weight critical and high reliability completion tools applications in the oil and gas industry. The novel nanostructured materials have demonstrated ultrahigh specific strength (i.e. ∼3 times of steel), enhanced specific stiffness, and great potential in tailoring the desirable dynamic and corrosion properties.
Traditional light weight material for ball or plug applications are prone to early yielding or shape changes. The yield strength of conventional aluminum alloys is usually less than 400 MPa. Nanotechnology can be effectively employed to enhance the mechanical properties and other desirable properties through engineering the material microstructure. Mechanical milling is used as approach for synthesis of nanostructured powders by conducting severe cyclic plastic deformation in powders and thereby promoting the formation of nanostructures. Our results showed that ultrahigh strength up to 1000 MPa can be achieved for Al-based nano-composites by controlling the distribution of the micro-and nanoparticles in the matrix. And corrosion behavior of the material can be controlled by tuning the matrix grain size from 100 to 500 nm depending on the processing parameters. The nanostructured materials also demonstrated excellent high strain rate ductility while maintaining its high strength. Examples of oil field applications of the nanostructured materials will be presented.
Lessons Learned from Using New Chemical Recipe for Acid Stimulation in Water Disposal Wells (Al-Khafji Field)
Authors: Al-Dhafeeri Abdullah M. , Al-Dhaferi Yousef R. , Ahmed Al-Sadah Ahmed Alawi 
Published: June 2012

Abstract
Acid treatments for dolomite formation with low permeability differ from that applied for calcite rock. Unlike limestone acidizing where HCl reacts with limestone in rapid reaction rate to generate reaction products soluble in water. In Some cases, injectivity well can not effectively improve in dolomite formation with low permeability using conventional 15 wt% HCl acid. In addition, formation damage due to drilling or workover operations can not be removed. Therefore, the process of treating dolomite for injectivitiy improvement may consider a serious issue for acid stimulation. The challenges of dolomite acidizing are to optimize damage removal while maximizing rock permeability with wormhole occurrences.
Well DW-4 drilled and completed as horizontal open hole wastewater disposal wells for excess water production from offshore oil wells in Al-Khafji Field. This well is used to dispose the un-wanted co-produced water which shows injectivity decline with time due to sand plugging and oil content droplet.
Several acid stimulation treatments were conducted on subject well with low rate of success due to not considering the dolomite reaction rate and the chemical volume to be used. A simple previous treatment review was conducted to select the best chemical recipe and treatment volume for injectivity improvement. As a result of conducting new chemicals recipe with optimum treatment volume, a major improvement in well injectivity with formation damage removal was obtained. This paper demonstrated new design methodology with extensive field study to address the challenges and the best future operation practices for acid stimulation. It included a pre-flush of mutual solvents, then bullheading stage of 20 wt% HCl with intensifier to accelerate the chemical reaction with dolomite rock.
A carefully designed train of treatment fluids was applied to remove formation damage induced by drilling and injection fluids. Injectivity tests before and after each step of the treatment was recorded and evaluated. Proper design and execution of the stimulation treatment almost doubled the well injectivity index. Challenges, fluid selection, design criteria, field treatment, lessons learned, and results of the acid treatments were discussed in this paper.
Downhole Heavy Oil Characterization Using 3D NMR and Modern Dielectric Logs
Authors: Al-Yaarubi Azzan H. , Al-Bulushi Nabil , Al-Mjeni Rifaat A. 
Published: June 2012

Abstract
Due to a surge in oil demand over the past years and its impact on prices, major heavy oil accumulations are gaining special attention in the Middle East. Knowledge of the fluid characteristics is critical to determine a suitable recovery process for heavy oil reservoirs. Oil viscosity is the property that most affects producibility and ultimate recovery in these settings, but it is the most difficult property to determine. This is due to the challenges associated with obtaining representative oil samples in increasingly heavy oil reservoirs. Additionally, the oil viscosities in these reservoirs exhibit large variations within the same formation. Hence, downhole in-situ measurements are key in establishing viscosities and their variation within the reservoir.
Current practice in heavy oil accumulation is to extract oil samples through crushing of cores at surface, or sampling through changing the temperature of the near wellbore in the hope that the fluid will flow. These techniques provide viscosity ranges that help in uncertainty testing of various recovery processes but are only point-data measurements. Nuclear magnetic resonance (NMR) logging is also used to determine in-situ oil viscosity accurately in conventional light oil reservoirs. However, this technique has limitations in heavy oil settings because the extremely fast relaxivity of the heavy oil components results in very short transverse or relaxation time (T2) values that are not detectable by the NMR tool. The short T2 time also means that the heavy oil and bound-water signals, overlap resulting in an ambiguous oil signal.
A novel technique combines data from 3D NMR and dielectric dispersion tools to determine in-situ oil viscosity. This was based on recently published NMR viscosity correlations. The primary output from the dielectric tool is the total water volume. Using this output combined with the 3D NMR data makes it possible to accurately derive bound-water, free-water, and oil volumes. These are necessary inputs into NMR-based viscosity correlations. This technique yielded continuous logs of heavy oil viscosities within the same viscosity range as measurements obtained from the core data.
Single-Well SAGD Field Installation and Functionality Trials
Authors: Hocking Grant , Cavender Travis , Person John , Hunter Tim 
Published: June 2012

Abstract
A vertical single-well steam-assisted gravity drainage (SAGD) injector/producer is proposed that consists of six vertical propped planes installed at varying azimuths throughout the pay thickness to minimize geological heterogeneities on system performance. Steam is injected at the top of the pay and liquids are extracted at the bottom. The well operates immediately in SAGD mode and is highly efficient because of the immediate drainage available from the propped vertical planes, the full gravity drainage height at startup, and a favorable steam pressure gradient. A field trial is presented of the installation of multi-azimuth vertical propped planes from two expanded split-casing sections in a sandy silt formation. Each casing section contained six vertical propped planes at multiple azimuths that were coalesced by pore-pressure relief between the casing sections. Downhole expansion and splitting of the 9 5/8-in. casing and cement quantified formation stiffness and strength, while downhole photographs and packer impressions showed the split casing in the locked-open position. Each wing was stimulated independently of the other wings with 12/20-mesh proppant injected using a highly crosslinked gel through a specialized treatment tool. Real-time active resistivity monitoring quantified the injected plane geometry from both subsurface and surface resistivity receivers. Hydraulic pulse interference tests quantified the hydraulic vertical connectivity of the vertical propped planes. The field trials showed conclusively that multiple vertical propped planes on various azimuths can be constructed from a single wellbore and the planes coalesced between casing sections spaced along the wellbore. The field trials demonstrated the functionality of the expanded casing and stimulation tools and showed that the vertical permeable propped planes could be constructed on azimuth with high in-placed permeability. The geometry of the injected planes was recorded in real-time using the active resistivity method. Following completion of the stimulations, surface excavations showed two of the vertical planes on azimuth with the multi-azimuth casing dilation planes. Following this successful field trial, heavy-oil and bitumen steaming trials are planned.
Field Scale Simulation of Cyclic Solvent Injection (CSI)
Authors: Chang Jeannine , Ivory John 
Published: June 2012

Abstract
Only 5 – 10% of the oil in Lloydminster heavy oil reservoirs is recovered during cold production with sand (CHOPS). Cyclic solvent injection (CSI) is the most promising post-CHOPS follow-up process. In CSI, a solvent mixture (e.g. methane-propane) is injected and allowed to soak into the reservoir before production begins (Figure 1). CSI has been focused on heavy oil recovery from post-CHOPS reservoirs that are too thin for an economic steam-based process. It has been piloted by NEXEN and by Husky and was a fundamental part of the $40 million Joint Implementation of Vapour Extraction (JIVE) solvent pilot program that ran from 2006–2010.
This paper describes field scale simulations of CSI performed with a comprehensive numerical model that uses "mass transfer" rate equations to represent non-equilibrium solvent solubility behaviour i.e. there is a delay before the solvent reaches its equilibrium solubility in oil. The model contains mechanisms to consider foaming or to ignore it depending on the field behaviour. It has been used to match laboratory experiments, design CSI operating strategies, and to interpret CSI field pilot results.
The paper summarizes the impact on simulation predictions of post-CHOPS reservoir characterizations where the wormhole region was represented by one of the following five configurations: (1) an effective high permeability zone, (2) a dual permeability zone, (3) a dilated zone around the well, (4) wormholes (20 cm diameter spokes) extending from the well without branching, (5) wormholes extending from the well with branching from the main wormholes,. The different post-CHOPS configurations lead to dramatically different reservoir access for solvent and to different predictions of CSI performance.
The impacts of grid size, upscaling, well inflow parameter, solvent dissolution and exsolution rate constants, and injection strategy were examined. The assumption of instant equilibrium solubility resulted in a 23% reduction in oil production compared to when a delay in solvent dissolution and exsolution was allowed for. Increasing the grid block size by a factor of 9 reduced the predicted oil production five-fold. Assuming isothermal behaviour in the simulations decreased predicted oil production by 17%.
Application of Droplet Flow in Alkaline Flooding to Improve Sweep Efficiency in Heavy Oil Reservoirs
Authors: Pei H. H. , Zhang G. C. , Ge J. J. , Ding L. , Ma C. , Shen J. W. 
Published: June 2012

Abstract
This study presented the results of a laboratory study to investigating a method to improve sweep efficiency by application of droplet flow in alkaline flooding in heavy oil reservoirs. This included micromodel flooding tests, sandpack flooding experiments and 3D physical model study. The glass-etching micromodel tests show that the injected alkaline solution can penetrate into the oil phase and create some discontinuous water droplet inside the oil phase, and finally forms droplet flow phenomenon. Depending on the high viscosity and Jamin effect, the droplet flow tends to lower the mobility of the injected water and lead to the improvement of sweep efficiency. Droplet flow phenomenon is more obvious with the alkaline concentration increasing, and resulting in a greater improvement in sweep efficiency. A series of sandpack floods were conducted using 325 mPa·s, 2000 mPa·s, and 3950 mPa·s heavy oils to assess the effectiveness of droplet flow in alkaline flooding for enhanced heavy oil recovery. The sandpack flood results demonstrate the considerable potential for improved heavy oil recovery by alkaline flooding, and moreover, the incremental oil recovery and pressure drop have been found to increase as the alkaline concentration increases. The result obtained in 3D physical model study indicates that the sweep area can be greatly improved by the formation of droplet flow in alkaline flooding. The above results demonstrate the mechanism of droplet flow in alkaline flooding to improve sweep efficiency is the dominant mechanism for enhanced heavy oil recovery.
Determination of Limits to Production in THAI
Authors: Greaves M. , Dong L. L. , Rigby S. P. 
Published: June 2012

Abstract
The operational production period in Toe-to-Heel Air Injection (THAI) has been investigated via numerical simulation of a field scale section of the Conklin THAI pilot in the Athabasca Oil Sands. THAI is an advanced horizontal well development of the in situ combustion process for heavy oil recovery. It operates as a ‘short-distance’ displacement process, and is being applied to bitumen and heavy oil reservoirs.
Breakthrough of oxygen into the production well is predicted to occur after 10.8 years of oil production. This occurs during the declining oil rate period, which follows a sustained period of constant rate production. Prior to oil rate decline, the oil recovery factor was 63 %. High combustion temperatures aid continued expansion of the steam bank, maximizing oil recovery. Economic and also safety factors determine the ultimate decision point, concerning termination of operations. On the one hand, maximum oil recovery is determined by longer operation time, but this is also influenced by safety considerations, principally, the approach to oxygen breakthrough. Terminating the process early maximises the financial rate of return, but at the expense of total oil recovery. Reduction in the oil price is probably the most significant factor affecting profitability, but this also depends on timing and degree of financial risk.
Wellbore Bitumen Treatment: Mitigation of the Adhesive Properties of Oil Sands during Drilling Operations – Development and Field Trial
Authors: Livanec Philip W. , Perez Greg P. 
Published: June 2012

Abstract
Mitigation of bitumen and asphaltene accretion to the drillstring and other drilling components has become an important task due to the increasing production of oil sands and heavy oil deposits. When drilling through oil sands or encountering a bituminous zone, numerous problems can occur due to the extreme adhesive nature of the bitumen. Drillstrings and other tubulars can become coated, causing stuck pipe and undesired nonproductive time (NPT). Surface equipment such as shaker screens, can become fouled, resulting in poor drilling fluid properties. Common methods to counter the adhesive nature of bitumen have involved solvation of the bitumen into the drilling fluid. However, these methods not only contaminate the drilling fluid (resulting in disposal concerns), but can also negatively affect the fluid's properties, such as rheology.
This field trial utilizes a water-based mud and examines the effectiveness of a new polymer additive to mitigate the adhesive nature of bitumen, thereby preventing the occurrence of wellbore accretion. The bituminous cuttings are rendered non-adhesive, transported by the drilling fluid to the surface, and separated by conventional solids control equipment. In this fashion, the drilling fluid properties are not altered, and the water-based mud can be disposed of without the environmental issues of a contaminated fluid. Field trials and lab results have shown that small additions of this bitumen stabilization polymer to water-based drilling fluid renders the bitumen non-adhesive. Field trials have been completed in northern Canada and show extremely positive results with this polymer additive. It was shown that when the tar sands interact with the polymer additive, the tar becomes non-adhesive, and remains non-adhesive following contact with aqueous solutions. By preventing the bitumen from solvating or dispersing into the drilling fluid, the bituminous cuttings can easily be surface-separated. Torque and drag issues commonly seen while drilling through oil sands were also alleviated with use of this polymer additive.