bluuebunny/crossref_metadata_2025_split huggingface dataset:
Study on Enhanced Oil Recovery of Water-Based Nanofluid with Functional Silica Nanoparticles
Authors: Yuyang Li , Caili Dai , Xinke Wang , Wenjiao Lv , Hongda Zhou , Mingwei Zhao 
Published: October 2017

Abstract
Although application of nanofluids in enhanced oil recovery has been reported, the dispersibility of nanoparticles in water is one of the most difficult problems to overcome in the process of application. In this research, (3-mercaptopropyl) trimethoxysilane and sodium p-styrene sulfonate were alternatively assembled on the surface of silica nanoparticles. Fourier transform infrared spectroscopy was used to identify the surface components of functional silica nanoparticles. Transmission electron microscopy was employed for observing the shape and the size of functional silica nanoparticles. The water-based nanofluid with functional silica nanoparticles was stable at pH 9. Particle size distribution of nanofluid (with a mean diameter of 20±8 nm) was investigated by dynamic light scattering. Imbibition tests of water-based nanofluid, alkaline aqueous solution (pH value equality with the water-based nanofluid) and brine into oil presaturated ultra-low permeability sandstone cores were completed. As expected, the oil recovery of the core immersed in nanofluid was significantly higher than cores immersed in alkaline water (pH 9) and 3 wt% NaCl solution. To reveal the mechanism responsible for enhanced oil recovery, contact angle measurements were performed on the oil-wet surface before and after treatment with the nanofluid. The results showed that the wettability of the oil-wet surface changed from oil-wet to water-wet after treatment with nanofluid. The crude oil displacement from anoil-wet glass surface innanofluid was also studied. The nanofluidexhibitedan excellent capability that makesoil displace from an oil-wet surface. These results aid our understanding of the role of the nanofluid in displacing crude oil from the rock. The essential results from our experiments showed that nanoparticles can be stably dispersed in water by surface-functionalized and nanofluid have more potential in enhanced oil recovery.
Implementation of a Drilling Microchip for Downhole Data Acquisition
Authors: Li Bodong , Gooneratne Chinthaka P , Badran Mohammed S , Shi Zhaorui 
Published: October 2017

Abstract
First and secondgeneration drilling microchipsare compared side by side on design architecture, system components, sensors, output signal, build materials etc. Temperature microchips were field tested in an on-shore well. From the 20 deployed microchips, 6 passed through the bit nozzles and survived the drilling process without causing any downtime to the operation. The data recorded by different microchips showed excellent consistency over the downhole part of the trip, from inside of the drill pipe up the annulus to the surface. This is the first time that a drilling microchip was successfully deployed while drilling, and a complete set of data recorded throughout the entire trip from drill pipe, to the annulus, all the way to the flow line and shale shaker. The consistent results from the microchip provide valuable information for a wide range of drilling activities.
Experimental Analysis of Discontinuities in Single Phase Flow - Vibration and Pressure Fluctuation Measurements
Authors: Karim Hafiz , Ancian Loïc 
Published: October 2017

Abstract
Current know-how in the field of piping system analysis remains incomplete with room for progress. Indeed, piping vibration can come from several sources: direct or indirect machine excitations, cavitation and acoustic excitation due to differential pressure devices or excitations due to fluid flow. This last topic has long been identified as essential and the Energy Institute (EI) Guidelines for the Avoidance of Fatigue Failure that are more and more often applied in both design and operation confirm the importance of this subject.
The use of such guidelines presents certain technical shortcomings: to date, there is limited information available for predicting vibration levels caused by turbulent flow. If piping responses are known, their excitation sources remain unknown, leading to suggesting solutions that tend to be more complex, potentially over-dimensioned and less cost-efficient than truly required.
The aim of this paper is to present FIV sources for several discontinuities that are present in piping systems.
In order to better understand the parameters that govern turbulent excitations, a series of measurements (pressure and vibration) was performed in the vicinity of several singularities.
Three common potential irregularities usually met in pipelines were selected for the study. Only restricted orifices (RO) are presented in this paper.
Two different test loops which have different characteristics in terms of size and flow were used for the measurements, making it possible to validate dimensionless analyses in order to compare results obtained from both loops.
The characteristics of the two loops place the acoustic modes of their systems in the frequency range of interest. Considering that the turbulent phenomenon is coherent on small distances whereas acoustic plane waves are coherent over long distances, coherence was used to separate the acoustic part from the total measured signals.
A dimensionless analysis was then performed, enabling the comparison of measurements from both test loops, determining if specific behavior was associated with an acoustic or a turbulent phenomenon and validating the hypotheses such as the homogeneity of the turbulent flow.
These results on a straight pipe (similar for different rates and pipe sizes) demonstrate the consistence of the dimensionless analysis and were used as a reference pressure level for further comparisons with levels obtained in the presence of a singularity.
The evolution of pressure fluctuations in function of the distance was extracted in this new configuration. Location and amplitude of these fluctuations were compared for different sizes.
The measurements and techniques used during this study make it possible to predict the amplitude and location of maximum of pressure fluctuations downstream of most common piping discontinuities such as restricted orifices.
Review of Coal Bed Methane Prospect in Indonesia
Authors: Irawan C. , Nurcahyanto D. , Azmy I. F , Paju J. A. , Ernata W. M. 
Published: October 2017

Abstract
Indonesia has began the unconventional operation since 2003, VICO and MEDCO as a pioneer in Coal Bed Methane (CBM) working Area. Since 2005, two (2) big company has begun study and survey seismic operation for Kutai Basin (VICO Indonesia) and South Sumatera Basin (MEDCO E&P). The results are neededmore survey seismic and massive drilling well, which the needs of study and evaluation to get more comprehensive calculation on gas methane reserves and the strategy of Exploration and Development phase on each basin
The success ratio by numbers of drilling operation of CBM wells in Kutai Basin and Sumatera Basin were not significantly good as early prediction. This condition made some CBM contractors working areas has to leave and do farm out from the area. Nowadays, by counting the total of Unconventional Working Area in Indonesia, the active operation area are around 40 places in Sumatera and Kalimantan.
The slow down activities of CBM operation are caused by the minimum number of success ratio to discovery and to produce Methane Gas; challenge for the contractors to fullfill the commitment which where list stated on Production Sharing Contract (PSC). Other obstacles are the permits, where contractors get more difficulties to do all the activities, such as land acquisition permit (IPPKH if needed), environment permit (UKL/UPL), Rig License permit, procurement process and else.
Nowadays, Government of Indonesia has given more simplication for contractors in Regulatory area, Procurement Policy and Operating Procedure Guideline to do CBM activitiesin Indonesia.
With several breakthroughs have been taken by the Government of Indonesia, in future prospect CBM activities will be expected back to normal with more efficient by collaboration of government and contractor for technical and technology in exploration and drilling activities. By the results of Methane Gas discovery increased the Total Reserves and Energy Resilience of Gas in Indonesia.
Investigation and Application of Reciprocating Direct-Drive Electric Submersible Plunger Pump Lifting Technology
Authors: Guoxing Zheng , Weishan Du , Qi Wang , Lin Wang , Fengshan Wang , Yanan Sun , Guoqing Wang , Weike Wang , Yang Gao 
Published: October 2017

Abstract
Aiming at the poor applicability, high unproductive energy consumption and the serious wear of the sucker and tube during the application of oil pumping units, screw pumps and electric submersible pumps in low-production and low-permeability wells, directional wells and exceptional wells, a new reciprocating direct-drive electric submersible plunger pump has been developed.
For reciprocating direct-drive electric submersible plunger-pump lifting technology, the rotor of submersible linear motor is connected with the plunger of oil-well pump; cable is applied to supply electric energy for the downhole submersible linear motor; and the rotor of motor directly drives the plunger pump to reciprocate and finally realizes the lifting of the produced liquid.
For this new-type lifting technology, downhole direct-drive rodless lifting mode is applied, which successfully prevents the wear of the sucker and tube and avoids the unproductive energy consumption that is caused by the movement of sucker rod string when oil pumping units, screw pumps and other rod lifting methods are adopted. Compared to the oil pumping unit with the same displacement, the application of the reciprocating direct-drive electric submersible plunger pump can reduce electric power consumption by more than 40%. Moreover, this new-style reciprocating direct-drive electric submersible plunger pump has no surface movable component, and the well head is sealed. Therefore, it is safe, environmental friendly and easy to maintain.
Numerical Simulation Method and Laboratory Experiments of Starting Pressure Gradient in Tight Sandstone Oil Reservoirs
Authors: Wang Shuai , Tan Xianhong , Zhang Shaohui , Jiang Haimei , Jiang Donglei , Ruan Hongjiang , Zhang Xiaoxia 
Published: October 2017

Abstract
In the process of the tight oilfields development, it is difficult to establish an effective system of injection-production displacement because of the high seepage resistance. The seepage does not follow the linear Darcy's law. However, the reservoir simulation software has not considered this phenomenon, which leads to the numerical simulation prediction results better than actual production data. Therefore, it is necessary to establish an effective method to calculate the low velocity non-Darcy flow in tight sandstone oil reservoirs numerical simulation.
This paper introduced a factor called starting pressure gradient (SPG), which can be used to describe non-Darcy seepage phenomenon. First of all, laboratory experiments of differential pressure flow method were carried out to get the relationship between core permeability and the SPG. In addition, according to the reservoir heterogeneity and exploitation degree, three methods were put forward for characterization the SPG in tight sandstone oil reservoirs numerical simulation. Finally, this numerical simulation method was used in the X tight sandstone oil reservoir history matching process to verify its accuracy.
The results of the laboratory experiments showed that, SPG exists in tight sandstone oil reservoirs. Liquid starts to flow when the production pressure gradient is greater than the SPG. SPG is an additional pressure resistance for each flow unit, the existence of SPG has intensified the degree of pressure drop. Analysis of the experimental data gave a power series relationship between the SPG and the permeability. And the SPG increases with the decreases of core permeability.
Reservoir heterogeneity criterion was established by introducing R and C factors. The greater R value and C values are, the higher the heterogeneity is. When the reservoir heterogeneity is weak (0&lt; R≤0.3), we set SPG for each layer. When the reservoir heterogeneity is strong (0.3 &lt; R≤ 1 or 0 &lt; C≤1), we set SPG for each rock type. When the reservoir with intense heterogeneity (1&lt;C&lt;2), we set SPG for each gird.
After considering SPG, single well history matching coincidence rate improves from 64% to 87%, and every layer oil production prediction has high coincidence with the actual production data. Therefore, SPG cannot be ignored in tight sandstone oil reservoirs numerical simulation.
This paper provides a new method to describe the low velocity non-Darcy flow in tight sandstone oil reservoirs numerical simulation, and can guide the tight sandstone oil reservoirs development effectively. This method can also be applied in heavy oil reservoirs and tight gas reservoirs numerical simulation.
Fit-for-Purpose Chemical EOR ASP Modeling Strategy to Guide Pilot Development Decisions for a Giant Reservoir in North Kuwait
Authors: Al-Dhuwaihi A. S. , AlAbdullah M. B. , Tiwari S. , Al-Murayri M. T. , Al-Mayyan H. , Shahin G. T. , Shukla S. 
Published: October 2017

Abstract
This paper focuses on a chemical EOR feasibility study for Raudhatain Zubair (RAZU) reservoir in North Kuwait. The study describes a methodical approach to enable pilot location selection, and a fit-for-purpose modeling strategy to guide the Alkaline Surfactant Polymer (ASP) pilot design decisions. The objective of the pilot is to test in the field that ASP chemicals could mobilize remaining oil and drive it to the producers, where it is captured, produced and separated at the surface.
A detailed study was conducted that focused first on mapping out the distribution of remaining oil in the Raudhatain Zubair (RAZU) sandstone reservoir, defining the subsurface uncertainties and identifying key decisions that needed to be addressed for the pilot design. Thereafter, a fit-for-purpose probabilistic dynamic model using a range of inputs based on available rock and fluid field data and ASP parameters from an in-house global Chemical EOR database was built. This model was used to predict the range of production outcomes and aid with pilot design decisions.
Based on the stated objective of the pilot, an inverted 5-spot pilot pattern was chosen and a representative area was identified that spanned a reasonable average of field properties. An uncertainty analysis on the pilot pattern revealed that the residual oil saturation to both water and chemical and the remaining oil saturation at the commencement of pilot are the largest uncertainties governing the incremental oil recovery from ASP over water flood. Another significant uncertainty was the presence of an aquifer and the influence of active injectors near the pilot area. Depending on the aquifer strength and heterogeneity of the reservoir, fluid drift and can sweep the chemical slug away from the intended target region of the 5 spot pattern. On the design side, the chosen surfactant concentration in ASP slug, which affects the residual oil saturation to chemical, can result in lower than optimal oil recovery if surfactant losses (via adsorption or chemical consumption) are not adequately managed. Other important decisions are injection rate and pattern size since they affect the incremental recovery due to different swept pore volumes in the pilot pattern. Moreover, the model helped in steering important decisions for the pilot – e.g optimum time to switch to ASP injection after water flood.
ASP sector models frequently suffer from being overly complex since they are not tailored to address practical questions that drive key pilot decisions in a timely manner. The unique practical modeling approach presented here focuses on identifying critical uncertainties and pilot design parameters while circumventing the need of detailed laboratory data and a full field model history match.
Improving Parameter Uncertainty Constraints for Coal Seam Gas Reservoir Simulation using Single Well Models with Particular Emphasis on Relative Permeabilty Assumptions
Authors: Furniss J. P. , Hodgkinson J. , Bottomley W. , Luo Y. 
Published: October 2017

Abstract
This paper presents elements of an extensive single well modelling (SWM) programme to improve confidence in the parameters used to condition the full-field reservoir simulation model. The impacts of local grid refinement (LGR), fine vs upscaled layering, and a range of static and dynamic properties have been investigated.
Values for some fundamental input parameters for coal seam gas (CSG) reservoir simulation, such as coal fracture porosity and relative permeability, are extremely difficult to constrain by laboratory test results and are typically derived from history matching studies. Also, the stress and shrinkage dependent permeability effects exhibited by many coal cleat systems can be very difficult to characterise and other parameter variations could be invoked to produce similar trends in simulated water and gas production and flowing bottom-hole pressure (FBHP) behaviour. Many of QGC's CSG well production histories exhibit some very large pressure drawdowns, and obtaining a good history match to water and gas production histories in addition to shut-in bottom hole pressure (SIBHP) and flowing bottom hole pressure can be problematic for many of these wells. Simulation input parameters such as permeability, porosity and cell to cell transmissibility have been investigated using a wide range of values. Up to now, it has generally been possible to match water and gas rates and either SIBHP or FBHP, but not both pressures.
Relative permeability and coal gas saturation have been the most effective parameters used to obtain an acceptable history match (HM) in recent modelling efforts. The full-field modelling assumptions for these parameters have now been validated and informed by the SWM work reported in this paper, and the range of uncertainty narrowed for these critical parameters. For the wells exhibiting the highest drawdowns, initially a very good match was obtained using a very ‘aggressive’ suite of relative permeability parameters and an irreducible water saturation of around 90%. This relies on an assumption of very low or zero critical gas saturation and extremely rapid reductions in water relative permeability as gas begins to desorb from the coal matrix and enter the coal fractures. The validity of these assumptions has been tested by considering wellbore modelling effects, to reducethe reliance on aggressive relative permeability parameters to achieve a history match. The full-field model (FFM) gridding assumptions have also been validated by this work.
Research of Floor Horizontal Well Staged Fracturing Technology
Authors: Cao L. , Yang X. , Zhang S. , Wang H. , Wang K. , Liu J. , Zhao J. 
Published: October 2017

Abstract
Since the coal seam is soft with low permeability in China, the stimulation effect of vertical well hydraulic fracturing technology is limited while horizontal well fracturing has instable wellbore leading to wellbore collapsing. Therefore, floor horizontal well hydraulic fracturing technology is proposed, that is drilling in the floor sandstone and connecting the coal seam by hydraulic fractures. A test area has been undertaken in 3# coal seam, southern Qinshui Basin, to demonstrate this technology. Through optimizing the well path, borehole structure, fracturing designs, and fracture propagation performance, a set of treatments were developed and applied successfully. The result shows that drilling floor horizontal well along with minimum horizontal principle stress, applying U-type well structure, and designing fractures with 3 stages, 130m half fracture length and 30D·cm flow conductivity achieves better production performance.
Integrated Waterflood Connectivity Analysis in Compartmentalised Reservoir of Windri Area, Asri Basin, Indonesia
Authors: Widiatmo R. , Gunawan H. , Afi F. N. , Waskito L. B. , Nugroho P. , Sunarta J. 
Published: October 2017

Abstract
This paper describes an efficient approach to evaluate waterflood connectivity performance in complex compartmentalized reservoir, the objectives are to increase the oil production performance and manage mature fields effectively, and also to enhance ultimate recovery in the long run. It is also very useful to get better understanding of detail reservoir characterization, reservoir internal architecture, reservoir distribution, pressure monitoring and subsequent water flood sweep pattern efficiency. Multi-disciplinary methods applied to maximizing all of data and create strong analysis. The first phase is deep sub-surface analysis in property distribution, simultaneous inversion, 4D time lapse seismic and sweep pattern analysis, those analysis have been done to get comprehensive interpretation of reservoir characterization and waterflood monitoring. The second phase is tracer injection, we implement tracer in several wells to ensure connectivity from injector to several producers are efficient and optimal. These methods were performed for several regions of this area which contains a large number of well, nearly 200 wells consist of vertical, deviated and horizontal wells. Reservoir distribution in Windri area interpreted as stacking channel with high sinuosity geometry. This reservoir consists of predominantly of marginal marine claystone interbedded with deltaic sandstones, thin limestone and coal. Bio-stratigraphic analysis from cores shows that the reservoir was deposited in estuarine setting, interrupted by a brief shallow marine incursion. Seismic amplitude mapping at the upper base Gita horizon reveals a system of meandering channels. Compartmentalised reservoir in Windri area divided into 5 sweep pattern to make analysis more detail and accurate. Each of compartment have different characteristic, this is the challenging part in Windri area. East of windri area channel divided into 4 channels and it shows the evolution and movement of the channel that can control the property distribution and reservoir connectivity. Group two shows good result from tracer injection and it is supporting the interpretation of reservoir distribution and characterization within the area. Integrated 4D time lapse seismic generate pressure monitoring movement from each of waterflood phase. The results of this integrated study implementation are excellent, the ineffective water injection pattern now become effective, there is no unavailing injection well, every pattern is connected and link to each other, so that we can achieve our goal to enhanced recovery factor from 16% to 20%. Reservoir characterization using multi-discipline method reduce uncertainty of heteroginity sand and fluid prediction. Integrated waterflood analysis has been implemented for prospect generation, production optimization and overcome pressure degredation in this area.