bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of MgO Nanofluid Injection into Water Sensitive Formation to Prevent the Water Shock Permeability Impairment
Authors: Habibi Ali , Heidari Mohammad A. , Al-Hadrami Hamoud , Al-Ajmi Adel , Al-Wahaibi Yahya , Ayatollahi Shahab 
Published: June 2012

AbstractFines migration is the major reason for productivity decline known as formation damage in oil reservoirs. Sandstone formations are sensitive to brine salinity alteration which disturbs equilibrium condition in porous media. Because of nonequilibrium condition fines migration occurs during various operations. Nanoparticles seem to be good candidates to strengthen the attractive forces between fines and pore wall due to very small size, high specific surface area and electrical surface charge.In this experimental study, several tests were performed using Berea sandstone (8 wt% clays) cores (3 in. length and 1.5 in. diameter). MgO nanoparticles were stabilized in the water uniformly using surface active agent and ultrasonication. Total dimensionless energy of interaction between nano particles in the suspensions was calculated based on the DLVO theory. Various core flooding tests were conducted to determine the effect of MgO nanofluid injection as clay stabilizer at different brine salinities on the cores with the permeability from 600-100 md. The pressure drop across the core was measured.The results indicated that the MgO nanofluid could fix fines effectively where brine salinity became lower than CSC. Besides, measured zeta potential and total energy of interaction calculation confirmed that repulsive force became dominant at the specific concentration of the complex nanofluid which ensures its stability for long time during core flooding tests. Thus, MgO nanofluid significantly prevented water shock problem. Also, no significant reduction in permeability was noticed in any of core flood tests.
Enhancing Flow Assurance Using Co-Ni Nanoparticles For Dewaxing Of Production Tubing
Authors: Haindade Zishaan , Bihani Abhishek D. , Javeri Saket , Jere Chaitanya 
Published: June 2012

Abstract
The most frequent problem encountered in day to day oil well production is the deposition of paraffin or wax inside the production tubing. The solution to this problem is frequent scraping and hot oil operation with help of Coiled Tubing Unit (CTU) thereby increasing the non productive time. The following paper proposes an alternative technique for dewaxing of production tubing.
The technique involves the use of Co-Ni nanoparticles along with an exclusive polymer to be pumped inside the annulus between production tubing and casing at the time of well commissioning. The nanoparticles remain suspended in the polymer filled inside the annulus throughout the life of the well. The application of magnetic field across the casing causes the nanoparticles to vibrate and get heated. This increase in temperature is transferred to the tubing by convection. The increase in temperature causes the wax to melt and is produced along with the oil stream.
This technique will make the frequent scraping and hot oil jobs obsolete thereby saving time and money. The technique eliminates flow assurance problems encountered due to paraffin deposition inside the production tubing.
Evaluation on the EOR Potential Capacity of the Synthesized Composite Silica-Core/ Polymer-Shell Nanoparticles Blended with Surfactant Systems for the HPHT Offshore Reservoir Conditions
Authors: Nguyen Phuong-Tung , Do Bao-Phuong Huu , Pham Duy-Khanh , Nguyen Hai-An , Dao Duy-Quang Pham , Nguyen Ba-Dung 
Published: June 2012

Abstract
The authors introduce the synthetic process and the evaluation results for surfactant/polymer inorganic nanocomposite specially designed for the enhanced oil recovery (EOR) process in the high temperature and high brine-hardness offshore reservoirs. The SiO2 nanoparticles (NPs) were introduced to the polymer matrix through the core-shell encapsulation-polymerization. New core-shell NPs were blended with surfactants in different ratios. The monodisperse particles, with the size of 50nm to 100nm identified by transmission electron microscopy (TEM), were investigated on their properties and morphology by IR spectroscopy, and thermal degradation (TGA). The blends of NPs and surfactants in brine were aged in one month in Dragon Southeast reservoir conditions to evaluate on the capacity as EOR agent. The results show that the nanocomposites produced IFT reduction and viscosity enhancement at critical concentration, high thermostability and salt-tolerance. These improved properties of core/shell NPs were suitable for producing high sweep volume and increasing crude oil displacement efficiency. The core flooding experiment was performed at 92°C on the fractured-granite core model and brine blend of 800 ppm of surfactants and 200 ppm of core-shell NPs was injected in 0.25 PV. After water flooding, the oil saturation was reduced into 30% and by the core-shell NPs injection, the oil was displaced in 6.2% additionally. The obtained results shown the capacity of using the core-shell NPs as a really good EOR agent for HTHP offshore reservoirs.
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Nano-Enhancement of Barrier Coatings for Improved Downhole Performance of Oilfield Materials
Authors: Welch John C. , Newman Caleb , Gerrard David , Mazyar Oleg A. , Mathur Vipul 
Published: June 2012

Abstract
The oil and gas industry is continuously looking for robust material and tool designs that provide greater operational flexibility in aggressive environments. Coating systems, engineered at the nanometer scale, exhibit enhancements that can address these needs.
Our study of nano-engineered coatings started with simple polymer-polymer self-assembled systems, to which was added nano-sized clay or one of several carbon-based nano materials. We evaluated application of different cross linker treatments. To evaluate the variables involved in preparation of the coating systems we quantified thickness and contact angle, and we performed micrographic and scanning electron microscope analysis of standard coated substrates. When applied to copper coupons we determined a 91% reduction of corrosion after four hours, 60% after 24 hours, and 13% after ninety hours in a hydrogen sulfide gas blend. Nano-engineered coatings applied to common oilfield elastomeric materials produce a 40x delay in swelling and decrease in transmission of carbon dioxide gas by 73%. All of the above are lab results, and the comparisons were made to baseline commercially available rubber compounds without nano-enhancement.
Our results demonstrated that nanotechnology can be very effectively used to significantly modify properties of commonly used oilfield materials. Reduced corrosion can extend the life of downhole electronics and motors. The oil swelling rate can be drastically reduced to give operators a greater flexibility in setting the packers and reducing intervention. These findings can be used to design new packers, sealing elements and other elastomeric components used in downhole environment. This paper will present our recent lab results along with a postulated mechanism on how nanotechnologies can impact material performance in downhole applications.
Rapid Estimation of Heavy Oil Viscosities Using a Novel Predictive Tool Approach
Authors: Bahadori A. , Nouri A. 
Published: June 2012

Abstract
The viscosity of heavy oils is a critical property in predicting oil recovery. Viscosity plays an important role in reservoir simulations as well as in predicting the easiness of fluid flow, selecting a production approach, and predicting oil recovery. In this work a simple-to-use predictive tool has been developed to predict the viscosity of heavy oil as a function of temperature as well as a simple correlating parameter that can be used for heavy oil characterization. The reported results are the product of analysis of many heavy oils data collected from the open literature for various heavy oil fields around the world. The tool developed in this study can be of immense practical value for petroleum engineers to have a quick check on the viscosity of heavy oil without opting for any experimental trials. In particular, petroleum and production engineers would find the proposed correlation to be user-friendly with transparent calculations involving no complex expressions.
Enhancement of Well Productivity Using a Technique of High-Frequency Induction Treatment
Authors: Valiullin Rim , Sharafutdinov Ramil , Ramazanov Ajrat , Shilov Aleksandr 
Published: June 2012

Abstract
One of the principal challenges of enhancing efficiency of production and injection wells is improving permeability of collector formations. The main changes of collection properties take place in the bore zone of the formation and are connected with the well construction and operation, which brings about a reduction in recipience of injection wells and flow of production ones. The oil production industry of the recent years has seen employment of various techniques of heat treating the bore zone of the formation to boost oil recovery. One of such techniques involves a high-frequency induction exposure. However, theoretical fundamentals of the application of the induction impact are practically non-existent at present, and no assessments of the induction heating efficiency have been made to compare it to other kinds of heat applications. The paper presents the results of mathematically modeling the process of an induction impact upon the formation. It investigates regularities of the formation of a resulting thermal field. Also presented in the paper is the efficiency of the induction heating of the formation versus heating using electric (resistance) heaters. It has been demonstrated that the use of an induction heater brings about an increase in the heating depth and a reduction of the duration of bore zone treatment by the factor of five or six if compared with using an electric resistance heater. The paper exhibits some results of experimental and methodological works on the use of induction treatment, as well as some examples of a geophysical support of the process of treating the formation bore zone.
Perforation Optimization for Regulating Production Profile of Horizontal Wells in Heterogeneous Reservoirs
Authors: Wang Haijing , Li Xiaoqing , Xue Shifeng 
Published: June 2012

Abstract
Horizontal wells which are characterized by large drainage area, small pressure drawdown and high production rate are more influenced by reservoir heterogeneity and wellbore pressure loss than vertical wells. These factors may lead to unequilibrium development and premature water breakthrough, resulting in shortened production period, reduced production and ultimate recovery. Perforated completion is a widely used completion technology of horizontal wells. As the only flow channel between the formation and the wellbore, perforation plays an important role on the inflow performance. This paper aims to develop a perforation optimization method for regulating production profile of horizontal wells in heterogeneous reservoirs.
Based on an improved evaluation approach of permeability heterogeneity, a reservoir/wellore coupling model of perforated horizontal wells in heterogeneous, anisotropic parallelepiped reservoirs is presented, and hence a perforation density optimization method aiming at regulating production profile is proposed. The example optimization shows that, the lower perforation density has a wider pressure regulating range. With the increase of perforation length, both the converged pressure drop and pressure regulating range decrease. To obtain an ideal production profile, the perforation density in low-permeability region should be higher than that in high-permeability region. The stronger the near-well permeability variability, the greater the density range and the proportion of low density are. The smaller the density, the greater the impact of rounding error is, and hence the less satisfactory the regulating effect is. This study provides a theoretical basis for the perforated completion design of horizontal wells in heterogeneous, anisotropic reservoirs.
Phase Behaviour of C3H8-n-C4H10-Heavy Oil Systems at High Pressures and Elevated Temperatures
Authors: Li Huazhou , Yang Daoyong 
Published: June 2012

Abstract
Phase behaviour of C3H8-n-C4H10-heavy oil systems at high pressures and elevated temperatures has been experimentally and theoretically investigated. Experimentally, a versatile pressure-volume-temperature (PVT) system is utilized to determine the liquid-vapour phase boundary (i.e., saturation pressure lines) and swelling factors of C3H8-n-C/H10-heavy oil systems with varying compositions at high pressures up to 5030 kPa and elevated temperatures up to 396.15 K. The viscosities of the corresponding solvent(s)-saturated heavy oil systems are measured by using a customized-capillary viscometer at 298.85 K. Theoretically, the volume-translated Peng-Robinson equation of state (PR EOS) with a modified alpha function is used to model the experimental phase behaviour of C3H8-n-C/H10-heavy oil systems. Two binary interaction coefficient (BIP) correlations, respectively developed for the C3H8-heavy oil system and n-C4H10-heavy oil system, are incorporated into the volume-translated PR EOS model. The two BIP correlations together with the volume-translated PR EOS are found to be capable of predicting the phase behaviour of the C3H8-n-C4H10-heavy oil systems with a good accuracy. In addition, comparison of five commonly used mixing rules indicates that the Lobe’s mixing rule is the most appropriate to predict the viscosity of heavy oil diluted by C3H8 and/or n-C4H10.
A Mechanism of Gas Production in SAGD
Authors: Canas Christian 
Published: June 2012

Abstract
The dissolution of gas in both water and bitumen as a mechanism contributing to gas production in SAGD is studied. The contribution of this mechanism to the production of gas in SAGD is evaluated through the implementation of appropriate thermodynamic models into a series of numerical simulations in order to more accurately represent the physics of gas behavior inside the SAGD chamber. Methane, carbon dioxide and hydrogen sulphide are considered.
It is observed from the numerical simulation results that the production of a gas in SAGD is directly proportional to the solubility of that gas in the liquid phases being produced. Additionally, these results lead to the conclusion that gas dissolution is an important mechanism in gas production.
Results from this study also confirm the findings observed by other researchers that gas will accumulate at the front and top of the SAGD chamber, thus reducing SOR and oil production rates. The degree of such accumulation of gas depends, among other operational and reservoir conditions, on the solubility of that gas in the liquid phases under the temperature and pressure conditions inside the steam chamber.
Reducing the CO2 Footprint: Employing Cogeneration to Improve the Energy Efficiency of Thermal Oil Recovery Projects
Authors: Welch Mike 
Published: June 2012

Abstract
Thermal recovery technologies such as Cyclic Steam Stimulation, Steam Assisted Gravity Drainage and Steam Flood are extremely energy intensive, requiring the combustion of fossil fuels to produce the steam and resulting in emissions of carbon dioxide and other pollutants. Newer technologies such as Solvent Extraction may also require the injected medium to be heated to maximise oil recovery from the reservoir.
Thermal projects often generate the heat and power required in separate facilities, with the electricity often being supplied from remote central generation facilities. In many cases it may be possible to integrate a cogeneration plant into the process. Using a single, suitably sized on-site Cogeneration facility, a locally available fuel can reliably provide both the power and heat required for the project, achieving overall energy efficiency to levels in excess of 75%, while helping to reduce the global CO2 footprint of the Oil & Gas industry and reducing reliance on imported electrical power. The design of Cogeneration plant can also help ensure maximum availability and uptime of production facilities.
In most cases the heat produced by a Cogeneration plant is a by-product of electricity production, but it is also possible to utilise waste heat from some processes to produce useful energy. Waste gases from processes are also potential fuels for a Cogeneration plant, helping to reduce or eliminate gas flaring, and improve environmental performance across the whole oil production chain.
There are numerous different ways to configure a Cogeneration plant depending on the type of fuel available and the ratio between power and heat required by the project. This paper will examine some of the different Cogeneration plant configurations and fuel options using Gas or Steam Turbines, or a combination of both, that could be applied to a thermal recovery project to maximise energy efficiency and plant availability.
Reservoir Identification and Hydrocarbon Classification with Logging Data in Bituminous Sandstone in Tarim Basin
Authors: Jun Zhao , Xinzhong Qi , Bin Yu , Weizhong Chen 
Published: June 2012

Abstract
Because of the complicated pore structure and complex relation of oil and water, especially owing to the existence of high-viscosity oil and bitumen in the formation it makes the resistivity difference between oil and water zones very low. So it is very difficulty to identify the oil and water with logging data. By applying the capillary pressure curves, lithological- electrical experiments and relative permeability curves the Silurian reservoir classification was studied in combination with the reservoir fractal characteristic and a classification model was established by using non-linear method to identify the reservoir types. On the basis of classifying reservoir types a improved normal distribution method was presented to distinguish oil and water zones. Then with core data the different parameter interpretation models concerning to varying reservoir types were founded. By used in practice it was proved to be effective to improve the veracity of log interpretation for bituminous reservoir in Tarim basin.
The Well-Wormhole Model of CHOPS: History Match and Validation
Authors: Istchenko C. M. , Gates I. D. 
Published: June 2012

Abstract
Cold Heavy Oil Production with Sand (CHOPS) is a non-thermal heavy oil recovery technique used primarily in the heavy oil belt in western Alberta and eastern Saskatchewan. Under CHOPS, typical recovery factors are between 5 and 15% with average ~10%. This leaves ~90% of the oil in the ground after the process becomes uneconomic. CHOPS exhibits an enhancement in production rates compared to conventional primary production, which is explained by formation of high permeability channels known as wormholes. The formation of wormholes has been demonstrated to occur in both laboratory experiments and field tracer studies. The ability to model growth of wormholes does not currently exist in commercial reservoir simulators. Here, wormholes are modelled as multi-lateral wells, which grow dynamically in the reservoir, using existing wellbore features. A module was coupled to CMG STARS™ to dynamically grow wormholes in the reservoir taking foamy oil flow, sand failure, and sand production into account. Here, we present on the results of history matches against field data to tune model parameters. The history-matched model reasonably predicts production trends of field CHOPS operations. The results provide a methodology to model CHOPS and predict under uncertainty where the wormholes will tend to grow into the reservoir. This provides a tool for placing new wells in the reservoir that will most likely not be in direct contact with existing wormholes. Multiple realizations of the reservoir can be used to mark the region of the reservoir that undergoes wormhole formation. The model can then be used for follow-up EOR processes such as cycle solvent injection as well as field scale optimization.
Suffield Area, Alberta, Canada – Caen Polymer Flood Pilot Project
Authors: Liu Jenny (Zhengyu) , Adegbesan Kenny , Bai Jiang (Jen) 
Published: June 2012

Abstract
The Suffield Caen reservoir contains 17°API heavy oil and the pool has been under waterflooding since 1996 with water cut of 96%. Primary and secondary oil recovery is 15 – 20% of OOIP. A major problem encountered in waterflood was poor sweep efficiency and high water cut caused by high water/oil mobility ratio, as water quickly broke through the reservoir owing to fingering effects. It is known that sweep efficiency during waterflood can be improved significantly by increasing the viscosity of injected water by use of polymer solution, thus generating a more favorable mobility ratio and enhancing oil recovery. The results of reservoir simulation studies suggested that polymer flood would achieve incremental recovery factor of 7 – 12%, and coreflood results indicated that 29 –32% of incremental recovery is achievable by 0.5 pore volume (PV) of polymer injection.
Core floods including polymer, surfactant/polymer(S/P) and alkali/surfactant/polymer (A/S/P) were conducted through lab experiments and eventually polymer flood was selected as a pilot project to improve oil recovery for the Caen reservoir on the basis of polymer, S/P and A/S/P core flood results and project economic evaluation.
Polymer injection started in the reservoir 15 months ago and a very positive response has been seen as oil cut has increased to 10% from 5% and oil production rose to 600 bbl/d from 400 bbl/d. Therefore, the polymer flood pilot project is continually implemented and the polymer flood is planned to extend to similar reservoirs in the Suffield area.
There is a large amount of conventional heavy oil resaves in the West Canada Basin, so far the primary recovery factor is only 10%, there is a big potential to enhance oil recovery by polymer flood. This polymer flood pilot project provides valuable experiences and guidance to field application.
Experimental Evaluation of Heated Vapex Process
Authors: Haghighat Parnian , Maini Brij B. 
Published: June 2012

Abstract
Incorporating some heat injection along with the solvent injection appears to be the most viable option for improving the oil drainage rate of Vapex in extra-heavy oil formations. This study was aimed at quantifying the potential increase in Vapex drainage rate that can be obtained by increasing the formation temperature.
The experimental phase of this study involved conducting Vapex experiments in a large high-pressure physical model, packed with 250 Darcy sand, using propane as the solvent. The physical model was warmed up to 40, 50 and 60 °C and propane was injected at the same test temperature but different injection pressures to observe how injection pressure affects oil drainage rate at elevated temperatures.
In the experiments at elevated temperatures but without increasing the injection pressure, higher rate of oil production was achieved in the early stages of the process. However, stabilized rate of oil production did not show pronounced improvement due to lower solubility of propane in the oil at higher temperatures. Increasing injection pressure along with increasing the test temperatures was successful in accelerating the oil production.
The oil, used in these experiments, was found to become mobile with the increase in temperature even without solvent dissolution. As a result, the total rate of oil production appeared to be controlled by two mechanisms. First, by solvent dissolution and oil mobilization at the boundaries of the vapor chamber and second by pure free fall gravity drainage beyond the vapor chamber wherever gravity head was sufficient to push the mobile oil toward the production well.
The results of this these tests define the upper limit of oil rates achievable with heated solvent injection. They can also be used to assess the applicability of Vapex to naturally warm reservoirs such as in Venezuela and reservoirs with mobile oil in place.