bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Integrated Sanding Study in an HP/HT Tight-Sandstone Gas Reservoir
Authors: Zhang Yang , Pan Yuanwei , Cui Xiaohu , Qiu Kaibin , Teng Qi , Huang Yongjie , Peng Fen 
Published: April 2019

Abstract
KS is a tight-sandstone and high-pressure-high-temperature (HPHT) gas reservoir in northwest China. It is characterized by a depth of more than 6000 m, temperature over 175°C, and pore pressure over 110 MPa. Despite the high unconfined compressive strength (UCS) of sandstone, almost half of the wells encountered sanding issues. The sanding wells exhibited low production rate, nozzle and pipeline erosion, sanding up, and even permanent closure. Investigating the sanding mechanism and developing solutions for sanding prevention are urgent needs due to the economic loss of low production.
An integrated sanding study was conducted to investigate the sanding mechanism. The entire sanding process was analyzed, including stress field alteration during production, rock failure, softening, and sand grain migration. First, wells with sanding issues were identified through production characteristics and field observation. After this, analysis of laboratory tests was performed to better understand the tight-sandstone properties, especially UCS, the softening parameter, and residual strength. Based on the tests, an elastoplastic damage model was proposed to delineate rock failure and sanding behavior. Then, a finite element model was built to simulate the damage of a perforation hole with field data, including hole diameter and length, rock stiffness and strength, drawdown, depletion, and so on. More simulation scenarios were performed to investigate the continuous sanding, transient sanding, and water hammer effect. Grain migration in perforation holes and in pipelines was also studied.
It was revealed that shear failure of perforation hole induced by drawdown and depletion was the root cause of sanding problem. Meanwhile, it was also confirmed that erosion and water hammer effect had very limited effect on sanding. Use of the elastoplastic damage model for the simulation of perforation hole failure enabled predicting the sand amount and determining the critical drawdown and depletion for sanding. In the end, an approach to identifying wells with high sanding risk and the key factors behind the sanding were provided, and sanding prevention suggestions were proposed.
The new elastoplastic damage model explains the sanding mechanism in a tight-sandstone reservoir and enables evaluating the sand volume, which has rarely been published previously. Laboratory tests, field observation, and numerical simulation were combined effectively to investigate the sanding issue. By utilizing the model, producers can find the key factors behind sanding issues, prevent sanding with a better production strategy, and avoid the economic loss, which are critical for the long-term exploration and production of this area.
Evaluation of Foam-Assisted Surfactant Flooding at Reservoir Conditions
Authors: Janssen Martijn , Mutawa Abdulaziz , Pilus Rashidah , Zitha Pacelli 
Published: April 2019

Abstract
Foam-Assisted Surfactant Flooding (FASF) is a novel enhanced oil recovery (EOR) method combining the reduction of oil-water (o/w) interfacial tension (IFT) to ultra-low values and foaming of a gas drive for mobility control. We present a detailed laboratory study on the FASF process at reservoir conditions. The stability of two specially selected surfactants in the vicinity of original injection water, i.e. sea water, at 90°C was assessed. The phase behaviour of the crude oil-surfactant-brine systems and the ability of the two selected surfactants to generate stable foam in bulk were studied in presence and in absence of crude oil. The phase behaviour and bulk tests resulted in the formulations of the surfactant slug and drive solutions. The slug solution aims for oil mobilisation by lowering of the o/w IFT and the drive formulation is required for gas foaming for mobility control. CT scanned core-flood experiments were conducted in Bentheimer sandstone cores initially brought to residual oil by water flooding. Oil mobilisation was obtained by injecting a surfactant slug at either under-optimum (o/w IFT of 10-2 mN/m) or optimum (o/w IFT of 10-3 mN/m) salinity conditions. At both salinities the injected surfactant slug yielded the formation of an unstable oil bank due to dominant gravitational forces. Optimum salinity surfactant slug was notably more effective at reducing residual oil to waterflood (81% reduction) compared to the under-optimum salinity slug (30% reduction). After oil mobilisation, drive foam was either generated in-situ by co-injection with nitrogen gas or was pre-generated ex-situ and then injected to displace mobilised oil. It was found that, at optimum salinity, FASF yielded an ultimate recovery factor of 40±5% of the oil in place (OIP) after water flooding whereas under-optimum salinity FASF showed a recovery of 35±7% of OIP after water flooding. Experiments have shown that the presence of crude oil is detrimental to in-situ foam generation and stability. Pre-generated drive foam increased its ultimate oil recovery by 13% of the OIP after water flooding compared to in-situ foam generation at optimum salinity.
An Investigation of the Performance of the Mimetic Finite Difference Scheme for Modelling Fluid Flow in Anisotropic Hydrocarbon Reservoirs
Authors: Hjeij Dawood , Abushaikha Ahmad 
Published: April 2019

Abstract
This paper investigates the performance of the mimetic finite difference (MFD) discretization scheme for modelling fluid flow in anisotropic porous media. We apply numerical benchmark studies on the MFD scheme to measure its accuracy when the horizontal permeability is much larger than the vertical one in a diagonal permeability tensor. We also run full-field simulations to investigate the modelling capability of this method and compare it to other advanced discretization schemes.
Multi-Scale Analysis of CO2 Injection as Improved Shale Gas Recovery Method
Authors: Kim Brice Y. , Olorode Olufemi , Akkutlu I. Yucel 
Published: April 2019

Abstract
This study is based on the premise that most of the trapped hydrocarbons can be produced, if we substitute them with another ‘acrificial’ fluid that has amplified interactions with organic pore walls, such as CO2. For the presented study, a downhole shale sample is analyzed in the laboratory to predict gas storage properties such as pore-volume, pore compressibility, and gas adsorption capacity. Then a series of pressure pulse decay measurements are performed to delineate transport mechanisms and predict stress-sensitive permeability. These coefficients are obtained as the calibration parameters of a simulation-based optimization for injection and production. Simulation model considers compositional gas flow in a deformable porous media and includes a multi-continuum porosity, with organic and inorganic pores, and micro-fractures. The experimental and simulation results show that most of the injected CO2 is adsorbed in the organic matrix and are not produced back. This is because CO2 molecules have significantly larger adsorption capacity when compared to methane. The strong adsorption of CO2 improves the release of natural gas from kerogen pores. This indicates that the separation of produced CO2 will be a minimal cost. Transport in kerogen has significant pore wall effects, and includes large mass fluxes of the adsorbed molecules by the walls due to surface diffusion. In essence, the adsorbed CO2 molecules significantly influence transport of methane. The results also show core-plug permeability is stress-sensitive due to presence of micro-fractures. Forward simulation results using optimum parameters indicate that closure stress developing near the fractures could significantly control the volume of CO2 injected. This raises operational issues on when to start injecting, and how to inject CO2. Using a simulation study of a production well with single-fracture, we show that fracture closure stress develops rapidly and production rate becomes a slave of the fracture geo-mechanics, e.g., strength of the proppants and the level of proppant embedment.
Impacts of Stress and Capillary End Effects on Relative Permeability of Shale Rocks
Authors: Nazari Moghaddam Rasoul , Jamiolahmady Mahmoud 
Published: April 2019

Abstract
Relative permeability (kr) functions are among the essential data required for the simulation of multiphase flow in hydrocarbon reservoirs. These functions can be measured in the laboratory using different techniques including the steady state displacement technique. However, relative permeability measurement of shale rocks is extremely difficult mainly because of the low/ultralow matrix permeability and porosity, dominant capillary pressure and stress-dependent permeability of these formations.
In this study, the impacts of stress and capillary end effects (CEE) on the measured relative permeability data were investigated. The steady state relative permeability (SS-kr) measurements were performed on Eagle Ford and Pierre shale samples. To overcome the difficulties regarding the kr measurements of shale rocks, a special setup equipped with a high-pressure visual separator (with an accuracy of 0.07 cc) was used. The kr data were measured at different total injection rates and liquid gas ratios (LGR). In addition, to evaluate the impacts of effective stress, the kr data of an Eagle Ford shale sample were measured at two different effective stresses of 1000 and 3000 psi.
From the experimental data, it was observed that the measured SS-kr data of the shale samples have been influenced by the capillary end effects as the data showed significant variation when measured at different injection rates (with the same LGR). This suggested that the liquid hold-up (i.e. capillary end effects) depends on the competition of capillary and viscous forces. In addition, it was shown that it is more necessary to correct the experimental kr data measured at the lower LGRs. Furthermore, different relative permeability curves were obtained when the kr data were measured at different effective stresses. This behavior was explained as the capillary pressure was expected to be more dominant at the higher effective stress.
The results from this study improve our understanding of unconventional mechanisms in shale reservoirs. It is evident that the behavior of unconventional reservoirs can be better predicted when more reliable and accurate relative permeability data are available. The outcomes of this study will be useful for accurate determination of such kr data.
Production Interference of Hydraulically Fractured Hydrocarbon Wells: New Tools for Optimization of Productivity and Economic Performance of Parent and Child Wells
Authors: Weijermars Ruud , Khanal Aadi 
Published: April 2019

Abstract
The present study provides a comprehensive set of new analytical expressions to help understand and quantify well interference due to competition for flow space between the hydraulic fractures of parent and child wells. Determination of the optimum fracture spacing is a key factor to improve the economic performance of unconventional oil and gas resources developed with multi-well pads. Analytical and numerical model results are combined in our study to identify, analyze, and visualize the streamline patterns near hydraulic fractures, using physical parameters that control the flow process, such as matrix permeability, hydraulic fracture dimensions and assuming infinite fracture conductivity. The algorithms provided can quantify the effect of changes in fracture spacing on the production performance of both parent and child wells. All results are based on benchmarked analytical methods which allow for fast computation, making use of Excel-based spreadsheets and Matlab-coded scripts. Such practical tools can support petroleum engineers in the planning of field development operations. The theory is presented with examples of its practical application using field data from parent and child wells in the Eagle Ford shale (Brazos County, East Texas). Based on our improved understanding of the mechanism and intensity of production interference, the fracture spacing (this study) and inter-well spacing (companion study) of multi-fractured horizontal laterals can be optimized to effectively stimulate the reservoir volume to increase the overall recovery factor and improve the economic performance of unconventional oil and gas properties.
Hydraulic Fractures Simulation and Stimulated Reservoir Volume Estimation for Shale Gas Fracturing
Authors: Lin Ran , Ren Lan , Zhao Jinzhou , Tao Yongfu , Tan Xiucheng , Zhao Jiangyu 
Published: April 2019

Abstract
Multi-stage & multi-cluster fracturing in horizontal well drilling is the core technology in for commercial exploitation of shale gas resevoir. According to vast field data, there is remarkable positive correlation relationship between stimulated reservoir volume (SRV) and shale gas production. Hence, estimating the SRV is essential for both pre-fracturing design and post-fracturing evaluation. However, the forming process of SRV involves with many complex mechanisms, making it is difficult to be simulated.
In this paper, we establish a mathematical model to estimate the SRV by simulating multiple hydraulic fractures propagate, formation stress change and reservoir pressure rise; consequently, the stress and pressure change might make natural fractures occur tensile failure or shear failure, generating a high-conductivity zone (i.e., SRV) in the shale reservoir.
To solve the model, displacement discontinuity method (DDM) is applied to simulate non-planar propagation of multiple hydraulic fractures and calculate formation stress change. Finite difference method (FDM) is used to compute reservoir pressure rise. The natural fractures failure state is determined by tensor formulae derived from Warpinski's failure theory. This SRV estimation method involves a variety of complex but crucial physical mechanisms during shale fracturing process which include unequal flow-rate distribution in different hydraulic fractures, non-planar hydraulic fractures propagation under stress interference, reservoir permeability increases with SRV expanding, two types of natural fracture failure and so on.
A field case study was performed to show the dynamic processes of hydraulic fractures propagation, reservoir permeability increase, and the SRV expansion during shale gas fracturing. Then we compared the simulation results with analytical solution, published papers and on-site microseismic monitoring data to verify our model. Finally, the influence of geological condition and engineering parameters on SRV was investigated by sensitivity analysis.
A Proper Data Comparison for Seismic History Matching Processes
Authors: Davolio Alessandra , Schiozer Denis José 
Published: April 2019

Abstract
Seismic data usually has lower vertical resolution than reservoir simulation models so it is a common practice to generate maps of 4D attributes to be used as the observed data to calibrate models. In such a case, simulation results are converted to seismic attributes and a map is generated by averaging the corresponding layers. Although this seems to be a fair practice, here we show that this procedure can present some drawbacks and propose a new approach to ensure a proper data comparison.
The first step of the proposed procedure follows the traditional sequence where seismic attributes are generated by running a petro-elastic model (PEM) with reservoir simulation data, at the simulation scale. Then, instead of averaging the simulation layers, we propose to resample the simulation grid to a seismic grid and filter the seismic impedances to the seismic frequency. Lastly, we extract the map from the regular grid to be compared with the observed 4D seismic. This procedure is performed in the depth domain and allows a straight and fair comparison of the two dataset.
A synthetic dataset based on a Brazilian field produced through water injection is used to validate this procedure. This dataset is composed by a synthetic 4D seismic data (observed data) generated by a consistent seismic modeling and inversion and a set of reservoir simulation models (to be matched). We computed seismic impedance for each simulation model by applying a PEM and two maps were generated for each model: (1) by averaging impedance values throughout the corresponding layers and (2) by applying the proposed procedure. When these maps are subtracted from the observed data (error maps), as would happen in a quantitative seismic history matching, we note a relevant differences. In the dataset used, we observed that if the vertical resolution issue is not considered (Case 1) the error map presents a strong bias that would erroneously force a decrease on the water saturation to match the observed data in a seismic history matching. While the map generated in Case 2 presents the errors better balanced and related to actual water movement differences rather than being a consequence of scale and resolution issues.
The novelty of this work is a quick way to bring simulation data to seismic resolution without going through all seismic modeling process ensuring a proper data comparison, which can be promptly added in seismic history matching process.
Mechanistic Simulation and History Matching of Alkaline-Surfactant-Polymer ASP Core Flooding Experiment at Optimum vs. Under-Optimum Salinity Conditions
Authors: Mirzaie Yegane Mohsen , Battistutta Elisa , Zitha Pacelli 
Published: April 2019

Abstract
Alkaline Surfactant Polymer (ASP) flooding is a chemical EOR method to increase oil recovery after water flooding through IFT reduction and increasing sweep efficiency. Previous studies have shown that maximal oil recovery is reached when ASP flooding is performed at optimum salinity conditions, i.e. Winsor type III micro-emulsion phase but a recently series of core-flood experiments indicated that comparable oil recovery could be obtained at under-optimum salinity conditions (Battistutta et al. 2015). Mechanistic simulation of ASP flooding considering phase behavior of water-oil-surfactant system, geochemical reactions and alkaline consumption is needed to validate the experimental data and provide a robust model for field scale studies. In this paper detailed history matching of series of core-flood experiments was attempted. Experiments were performed at different salinity conditions (optimum vs. under-optimum) and with different core types (Bentheimer and Berea) using a single olefin sulfonate (IOS) and crude oil with very low acid number (&lt;0.05 mg KOH/g oil). The numerical simulations were performed using UTCHEM, multiphase multi-component simulator along with EQBATCH module to model the geochemical reactions.
Neglecting the effect of in-situ surfactant (soap) generation, since the acid number of crude oil was low, modeling of the phase behavior showed an excellent match against experimental data and optimal salinity was observed at 2.0 wt% NaCl (+ 2.0 wt% Na2CO3).Using this and considering aqueous and cation exchange as the most important geochemical reactions in alkaline propagation, several ASP core-flood experiments at optimum vs. under-optimum salinity conditions were successfully modeled. An excellent matching of all the measured parameters including oil cut and recovery, pressure drop, pH and carbonate, alkali and surfactant concentration at effluent was also achieved. Modeling confirms the results obtained from experiment which regardless of core type, although minimum achieved IFT at optimum salinity conditions is lower than the one achieved at under-optimum conditions, comparable final oil recovery was observed for both cases. This emphasizes the importance of performing ASP flooding at under-optimum salinity conditions due to lower surfactant retention and reducing the likelihood of achieving over-optimum salinity conditions.
In this paper a robust model which is calibrated with experimental data is presented to simulate ASP flood process at various conditions and the basic model can be used to perform further simulations and can provide practical and convenient approach to model field applications of ASP flooding.
Effect of Simultaneous Snail Slime-aided Degradation and Yeast Fermentation on Terpenoid Composition of Plantain Pseudostem Waste
Authors: Uchenna Amadi P. , Charity Ogunka-Nnoka , Abbey Bene 
Published: April 2019

Background:
In this study, local sustainable enzyme sources involving excised digestive
juice of African land snail and yeast were utilized to achieve the simultaneous saccharification (SSF)
and fermentation (SSF) of plantain pseudostem (PPS) waste, and afterwards their effects on terpenoids
using gas chromatography coupled to a flame ionization detector (GC-FID), were examined.

Methods:
The most abundant terpenoids were found in the order α-pinene > borneol > camphor > humulene
> β-caryophellene, while the least in abundance were cis ocimene (8.78x10-6 mg/100g), and
cyperene (1.81x10-5 mg/100g). The application of exclusive fermentation and SSF respectively elevated
azuluene by 95.46 and 99.6%, while pinene-2-ol was elevated by 83.02 and 98.57%, respectively.

Results:
Both exclusive fermentation and SSF had no effect on myrcene, cyperene, ethyl cinnamate,
germacrene b, valencene, beta selinene, aromadendrene, and taraxerol, while the degree of degradation
of some of the terpenoids by both processes was respectively as follows; gama muurolene (100%),
β-caryophyllene (97.60 and 93.14%), α-terpinenyl acetate (91.95 and 83.16%), geranyl acetate (94.81
and 43.87%), and terpinen-4-ol (94.40 and 57.00%).

Conclusion:
The findings of this study encourage the imminent application of simultaneous saccharification
and fermentation for the enhancement of bioactivities of terpenoids.
Is Brain-Derived Neurotrophic Factor: A Common Link Between Neurodegenerative Disorders and Cancer?
Authors: Khosla Radhika , Banik Avijit , Kaushal Sushant , Battu Priya , Gupta Deepti , Anand Akshay 
Published: April 2019

Background:
Cancer is a common disease caused by the excessive proliferation of cells, and
neurodegenerative diseases are the disorders caused due to the degeneration of neurons. Both can be
considered as diseases caused by the dysregulation of cell cycle events. A recent data suggests that
there is a strong inverse association between cancer and neurodegenerative disorders. There is indirect
evidence to postulate Brain-derived Neurotrophic Factor (BDNF) as a potential molecular link in this
association.

Discussion:
The BDNF levels are found to be downregulated in many neurodegenerative disorders and
are found to be upregulated in various kinds of cancers. The lower level of BDNF in Alzheimer’s and
Parkinson’s disease has been found to be related to cognitive and other neuropsychological impairments,
whereas, its higher levels are associated with the tumour growth and metastasis and poor survival
rate in the cancer patients.

Conclusion:
In this review, we propose that variance in BDNF levels is critical in determining the
course of cellular pathophysiology and the development of cancer or neurodegenerative disorder. We
further propose that an alternative therapeutic strategy that can modulate BDNF expression, can rescue
or prevent above said pathophysiological course. Larger studies that examine this link through animal
studies are imperative to understand the putative biochemical and molecular link to wellness and disease.