bluuebunny/crossref_metadata_2025_split huggingface dataset:
ANALISIS DISKRIMINAN UNTUK VALIDASI CLUSTER PADA STUDI KASUS PENGELOMPOKAN KECAMATAN DI KABUPATEN JEMBER BERDASARKAN STATUS KEMISKINAN
Authors: Istiqomah Fikriana Nur , Tirta I Made , Anggraeni Dian 
Published: August 2020

. Cluster validation is a procedure to evaluate the results of cluster analysis quantitatively and objectively on a data. The validation process is very important to get the results of a good and appropriate grouping. In the validation process, the author uses internal validation, stability, and discriminant analysis test. This study aims to obtain validation results from the hierarchy and kmeans method. This data grouping uses “iris” simulation data, which results from the grouping method used can be applied to the original data to see which validation method is used for all data and produce an optimal grouping. The result of the study show that in the “iris” data, a single linkage link is an appropriate grouping method because the result of the grouping are optimal for all validations and classification of group members whose groups are significant. In Sub-district poverty data in Jember district with a single linkage link optimal grouping was obtained and complete linkage links were also used as a method that resulted in optimal grouping for all validation. Cluster validation using discriminant analysis test is appropriate for various types of data in general and shows that single linkage methods are better than other methods for grouping and validation methods for “iris” data and Sub-district data in Jember district based on variables of poverty status.
Keywords: Cluster Analysis, Diskriminant Analysis, Multivariate Analysis, Validation Cluster
KAJIAN FRAKTAL i-FIBONACCI WORD GENERALISASI GANJIL DENGAN MENGGUNAKAN L-SYSTEM
Authors: Umami Riza , Purnomo Kosala Dwija , Ubaidillah Firdaus 
Published: August 2020

The i-Fibonacci Words are words over {0,1}. The i-Fibonacci Word can be associated with a fractal curve by using odd-even drawing rule and L-System methods, then also known as an i-Fibonacci Word fractal. L-System is one of methods that is used to create objects with repetitive self-similiarity. Framework of L-System consists of axiom and rules. L-System is a parallel rewriting system with existing rules. The purpose of this research is to look for the LSystem rules of i-Fibonacci Word special for odd i, then look how its characteristics. The LSystem rules for i-Fibonacci Word odd i are divided into two types, the rules for i=1 and the others odd i. The characteristic of i-Fibonacci Word fractal is the more generation and i value of fractal, then the more segments and archs of fractal curve. Next, the words of i-Fibonacci Word fractal segments number is a subwords of the i-Fibonacci Word digit numbers. It is also known that the fractal curve will be stretched as the decreased angle.
Keywords: Fractal, i-Fibonacci Word, L-System
The Life of a Fracture: Biologic Progression, Healing Gone Awry, and Evaluation of Union
Authors: Hellwinkel Justin E. , Miclau Theodore , Provencher Matthew T. , Bahney Chelsea S. , Working Zachary M. 
Published: August 2020

» New knowledge about the molecular biology of fracture-healing provides opportunities for intervention and reduction of risk for specific phases that are affected by disease and medications.» Modifiable and nonmodifiable risk factors can prolong healing, and the informed clinician should optimize each patient to provide the best chance for union.» Techniques to monitor progression of fracture-healing have not changed substantially over time; new objective modalities are needed.
Efficacy of Home Prophylactic Benzoyl Peroxide and Chlorhexidine in Shoulder Surgery
Authors: Nhan Derek T. , Woodhead Benjamin M. , Gilotra Mohit N. , Matsen Frederick A. , Hsu Jason E. 
Published: August 2020

» Two predominant prophylactic home skin-disinfection regimens exist in shoulder surgery, benzoyl peroxide and chlorhexidine.» Of these 2 regimens, benzoyl peroxide gel is more effective than chlorhexidine in reducing the rate of positive Cutibacterium cultures on the skin surface.» At present, there are no studies that assess the impact of these home prophylactic measures on clinical infection rates.
Molecular Signatures of Solvent Injection in Shale Organic Nanopores
Authors: Perez Felipe , Devegowda Deepak 
Published: August 2020

Abstract
In this study, we investigate the mixing process of an organic solvent with reservoir fluids in organic nanopores. Using molecular dynamics (MD) simulations, we create a molecular model of mature kerogen saturated with a black oil and systematically investigate the physical mechanisms by which the mixing process occurs. The in-situ hydrocarbon mixture in organic pores partitions because of preferential adsorption of the longer alkane chains and aromatic molecules onto the pore surface and differential mixing with the solvent. Under primary production, the produced oil composition is always lighter than the in-situ fluid. Injection of a solvent promotes mobilization of intermediate and heavy components demonstrating the promise of miscible enhanced oil recovery (EOR) in shales. We also show that solvent penetration is rather limited even with extended periods of soaking which highlights the importance of surface area to the success of EOR.
Miscible Gas EOR in a Supergiant Oil Rim Reservoir
Authors: Penigin Artem , McGuire Patrick , Glavnov Nikolay , Vershinina Maya , Mukhametzyanov Iskander , Garipov Ilnar 
Published: August 2020

Abstract
The paper describes the development of an EOR project for a supergiant oil rim field, and how the optimal injected gas composition was determined. This includes the laboratory tests to develop a miscible gas equation of state (EOS), cryogenic plant design considerations, and the evaluation of gas EOR development strategies for the different Novoportovskoye reservoirs.
Facilities models were built to evaluate options to increase extraction of C2-C4 components from produced gas. This rich gas can then be mixed with lean gas to create miscible injectant (MI) for EOR. Because the gas caps are so lean (90+% methane), the best options were to chill the produced gas to either −55°C or −80°C with a turbo-expander unit. The lower temperature option requires special metallurgy, but it boosted extraction by 35%.
The first EOR PVT model was designed from the limited compositional data available. MI compositions for each reservoir were developed. A laboratory experimental program was undertaken to calibrate the EOS for Novoportovskoye EOR. The new EOS was used to determine the optimal composition of the MI. According to slimtube tests and simulation studies, the optimal composition of miscible injectant is 62-67% methane, with the rest being C2-C4.
The currently planned waterflood patterns and gravity drainage/gas cap expansion areas were studied to determine the best areal and cross-sectional location of the MI injectors. An integrated model was built to account for injected and produced gas volumes and compositions. This allowed the analysis of bottle-necks in the production network, cryogenic plant, and gas facilities.
WAG in most areas performed better in terms of gas utilization, which leads to increased incremental oil given the same amount of MI available. By choosing the most efficient patterns in terms of gas utilization it is possible to increase oil recovery in these areas by 10-15% OOIP.
Evaluation of an Amphoteric Surfactant for CO2 Foam Applications: A Comparative Study
Authors: Zhou Jimin , Srivastava Mayank , Hahn Ruth , Inouye Art , Dwarakanath Varadarajan 
Published: August 2020

Abstract
In a surfactant-alternating-gas (SAG) injection, stable foams form viscous barriers and divert fluids, thereby providing conformance for enhanced oil recovery (EOR). Once foam decays, injected gas resumes preferential flow through thief zones, demonstrating the need for higher foam stability. Thus, longer foam half-lives or stability is one of the key factors determining the success of any foam-field application. The ability of surfactants to stabilize foam depends on the gas type. Many surfactants that form stable foam with nitrogen (N2) and hydrocarbon gas are not able to form a stable foam with carbon dioxide (CO2), which could be due to the presence of low pH environment in CO2 floods, relatively high solubility of CO2 in water, and CO2 permeability through liquid films. To improve the performance of CO2 floods, it is imperative to identify surfactants that can enhance the stability of CO2-foam.
This work investigates an amphoteric surfactant, which is commercially available and priced similarly to other commonly used EOR foamers, for its ability to stabilize CO2-foam. Static stability and dynamic coreflood tests were conducted at high pressure and high temperature conditions, where CO2 remained in the supercritical state. The performance of the amphoteric surfactant was compared with another good foamer on the basis of foam stability and strength, both in bulk and in porous media. Dynamic adsorption tests were conducted to compare the adsorption of amphoteric and anionic surfactants on both sandstone and carbonate rock surfaces. Ways to mitigate surfactant adsorption on rock surfaces were studied.
In terms of CO2-foam stability, the amphoteric surfactant performed much better than the anionic and nonionic surfactants evaluated in this study. In the presence of oil, foam stabilized by the amphoteric surfactant exhibited the longest half-life in static tests. However, the amphoteric surfactant performed similarly to other surfactants with nitrogen or hydrocarbon gas. Compared to other surfactants, foam stabilized by the amphoteric surfactant remained stable and exhibited higher apparent viscosity at high foam qualities. Foam stability at higher qualities improves the performance of SAG process as it can lengthen the gas cycle and reduce the amount of surfactant needed, a beneficial outcome when water supply is limited. We found the adsorption of amphoteric on carbonate rock to be much lower than on sandstone rock.
Compared to ionic and nonionic surfactants, amphoteric surfactants are usually avoided for oilfield applications due to potential for high retention. Based on systematic evaluation, our work demonstrates the unique ability of amphoteric surfactants to enhance the stability of CO2-foams at reservoir conditions.
Determination of Infill Drilling Time Window Based on Depletion-Induced Stress Evolution of Shale Reservoirs with Complex Natural Fractures
Authors: Pei Yanli , Yu Wei , Sepehrnoori Kamy 
Published: August 2020

Abstract
Infill drilling is a common technique to further develop the unstimulated region in-between parent wells for shale oil reservoirs. However, the potential of infill drilling to improve oil recovery depends heavily on the depletion-induced stress evolution at the selected infill locations. This work aims to model the spatial-temporal evolution of stress field for shale oil reservoirs in the Permian Basin and proposes the best timings for infill drilling to maximize the shale oil production. Based on history matching of an actual well, two types of fracture networks - with and without natural fractures (NFs) were generated for future production forecast. Our three-dimensional coupled geomechanics and compositional simulator with embedded discrete fracture model (EDFM) was used to simulate the pressure and stress redistribution associated with depletion in a highly fractured reservoir. A loosely coupled procedure is applied between fluid flow and geomechanics modeling to speed up the computation process while guaranteeing the simulation accuracy. The time window was determined by monitoring the orientation change of local maximum horizontal stress at the infill region, and the right timings for infill drilling were suggested accordingly. Field application in Permian basin indicates that the degree of stress reorientation at the infill region is closely related to the drainage area created by the complex fracture networks. When only hydraulic fractures present, the stress reversal in-between parent wells occurs after 0.8 year of production and gradually returns back to the original direction after 5 years; the critical time to perform infill drilling is recommended as before 0.8 year or after 5 years to ensure the child fractures propagating towards undepleted areas. When natural and hydraulic factures coexist, a similar phenomenon of stress reorientation is observed; the right timing for infill drilling in this case has been widened to before 1 year and after 3 years considering the higher conductivity introduced by complex natural fractures. Sensitivity analysis indicates that a smaller well distance and a higher bottomhole pressure will both help alleviate the stress reversal at the infill region, whereas a larger cluster spacing will narrow the available time window of infill drilling. The time-varying stress state at the infill region of shale oil reservoirs with complex fracture networks has been fully illustrated by our coupled geomechanics and multiphase compositional simulator. Based on the entire picture of stress reorientation process, this work suggests the best timings for infill drilling at the desired locations, which will significantly improve hydraulic fracturing performance and oil recovery in the Permian basin.
Assessment of Miscible WAG Injection Performance in a Giant Carbonate Reservoir using Analytical and Numerical Approaches
Authors: de Araujo Cavalcante Filho Jose Sergio , Santos Silva Vinicius Luis , de Sant'Anna Pizarro Jorge Oscar 
Published: August 2020

Abstract
Carbonate reservoirs from Pre-salt layer are responsible for a significant volume of Brazils total oil production. Recovery mechanisms applied are mostly water injection, aiming for pressure maintenance and oil recovery increase through macroscopic oil displacement, complemented by gas injection to dispose produced CO2 rich gas stream into the reservoir. Production strategies were originally built using producers combined with gas and water injectors. Later, based on a serious of technical studies, including the ones described here, most injection wells were converted to water alternating gas (WAG). In the literature, WAG injection is applied mostly to gas injection projects to increase oil recovery and provide mobility control; as a recovery mechanism the WAG process combines the increased microscopic sweep efficiency from the gas with the improved macroscopic sweep efficiency obtained from the water. In this work we perform the screening and evaluation of WAG injection as a recovery mechanism in a heterogeneous carbonate reservoir from the Brazilian pre-salt. For that purpose, we use both analytical and numerical methods, the later using a commercial compositional simulator. The screening indicates that this reservoir is a candidate for WAG injection. Lab data shows thermodynamic miscibility at initial pressure levels and phase behavior observed in experiments is matched to a Peng-Robinson equation of state (EoS). Results from numerical simulation have a good qualitative agreement with analytical results and data from the literature, indicating higher oil recovery for greater gas injection. The increase in oil recovery estimated by numerical simulation is compared with actual data from the literature using dimensionless variables where we observe good agreement of our expectations to previous field results. We conclude that the efficiency of WAG injection, in these reservoirs, relies on factors such as gas availability, miscibility development and flow pattern to be developed due to reservoir heterogeneities (channeling versus dispersive flow).
Scleroglucan Polymer Stability: Thermal, Chemical, and Microbial
Authors: Kozlowicz Briana , Jensen Tryg , Khambete Malhar , Kadhum Mohannad J. , Garshol Frøydis Kirsti , Vik Eilen Arctander , Tomczak-Wandzel Renata , Wever Diego A. , Lomans Bart P. , Ray Charles 
Published: August 2020

Abstract
Polymers for enhanced oil recovery (EOR) purposes are required to have long term mechanical, thermal, chemical, and biological stability across a wide variety of conditions throughout field deployment. In this work we expand upon initial studies of scleroglucan biopolymer stability and demonstrate that scleroglucan solutions retain a significant proportion of their initial viscosity over a large range of stresses. Thermal stability of the biopolymer, scleroglucan, was tested at temperatures of up to 115°C, wherein the samples retained &gt;95 % of the original viscosity over several months, and at 105 °C sclergolucan maintained &gt;95 % viscosity over the course of 720 days. Scleroglucan was found to be chemically compatible with formaldehyde, glutaraldehyde, tetrakis(hydroxymethyl)-phosphonium sulfate (THPS), and 1,3,4,6-tetrakis(hydroxymethyl)tetrahydroimidazo-[4,5-d]imidazole-2,5(1H,3H)-dione (TMAD) for six months at 37 °C, 85 °C, and 95 °C, indicating these biocides have the potential for use in microbial control during scleroglucan implementation under various conditions. Rheological studies indicate the viscosifying power of scleroglucan is largely unimpacted by common reservoir salts (including divalents and trivalents) even through 20 % (wt/wt) salt addition.
Microbial risks to polymer stability were also investigated. The susceptibility of scleroglucan to microbial degradation was assessed under reservoir relevant conditions using a bottle test system in which the polymer was incubated with active microbial cultures under various conditions that simulate reservoirs spanning 3.5 % to 17 % salinity and 30 °C to 90 °C. Our tests of microbial degradation found that anaerobic samples incubated with active microbial consortia under lower salinities and temperature lost viscosity with concomitant microbial growth indicating the presence of scleroglucan degrading organisms in the inoculum. However, anaerobic samples at temperatures above 60 °C and salinities greater than 7 % retained viscosity during the experiment illustrating polymer stability under conditions similar to those of harsh reservoirs. This study further refines the window of operation where scleroglucan maintains functional viscosity and may be employed for EOR use.
Quantifying Oil-Recovery Mechanisms During Natural-Gas Huff n Puff Experiments on Ultratight Core Plugs
Authors: Tran Son , Yassin Mahmood Reza , Eghbali Sara , Doranehgard Mohammad Hossein , Dehghanpour Hassan 
Published: August 2020

Abstract
Despite promising natural gas huff ‘n’ puff (HnP) field-pilot results, the dominant oil-recovery mechanisms during this process are poorly understood. We conduct systematic natural-gas (C1 and a mixture of C1/C2 with the molar ratio of 70/30) HnP experiments on an ultratight core plug collected from the Montney tight- oil Formation, under reservoir conditions (P = 137.9 bar and T = 50°C). We used a custom-designed visualization cell to experimentally evaluate mechanisms controlling (i) gas transport into the plug during injection and soaking phases, and (ii) oil recovery during the whole process. The tests also allow us to investigate effects of gas composition and initial differential pressure between injected gas and the plug (ΔPi = Pg – Po) on the gas-transport and oil-recovery mechanisms. Moreover, we performed a Péclet number (NPe) analysis to quantify the contribution of each transport mechanism during the soaking period.
We found that advective-dominated transport is the mechanism responsible for the transport of gas into the plug at early times of the soaking period (NPe= 1.58 to 3.03). When the soaking progresses, NPe ranges from 0.26 to 0.62, indicating the dominance of molecular diffusion. The advective flow caused by ΔPi during gas injection and soaking leads to improved gas transport into the plug. Total system compressibility, oil swelling, and vaporization of oil components into the gas phase are the recovery mechanisms observed during gas injection and soaking, while gas expansion is the main mechanism during depressurization phase. Overall, gas expansion is the dominant mechanism, followed by total system compressibility, oil swelling, and vaporization. During the ‘puff period, the expansion and flow of diffused gas drag the oil along its flowpaths, resulting in a significant flow of oil and gas observed on the surface of the plug. The enrichment of injected gas by 30 mol% C2 enhances the transport of gas into the plug and increases oil recovery compared to pure C1 cases.
The Past, Present, and Future of Chemical Enhanced Oil Recovery Methods in Yates Field Unit
Authors: Valdez Raul , Boring Pamela A. , Lewis Edward J. , Haymes Seth , Hernandez Gonzalo A. 
Published: August 2020

Abstract
Chemical Enhanced Oil Recovery (EOR) methods have been implemented in a West Texas fractured carbonate. Due to the partially oil-wet nature of Yates field and slightly viscous oil (5-7 cP), surfactant injection was implemented to alter wettability and polymer was injected in the waterflood area to improve displacement efficiency, respectively. Single well huff-n-puff (HnP) surfactant treatments (late 1980's-today) and well-to-well pilots (1990's-2000's) have increased incremental oil production relative to base decline. Optimum surfactant chemicals were chosen based on laboratory results, reservoir performance, and economic viability. Polymer injection was carried out over a 6 year span (1983-1989) in which 55+ million pounds of polymer was injected; however the interpretation and analysis was complicated due to concurrent drilling, workover activities, and no prior waterflood development.
Design parameters key to the surfactant implementation included: surfactant type and concentration, Critical Micelle Concentration (CMC), fluid saturations, oil composition, formation water salinity, fracture intensity, and treatment soak timing. Laboratory experiments included interfacial tension, contact angle, adsorption, fluid phase stability, Amott tests, and coreflooding. Numerical models were developed to help understand the sensitivity of each parameter on EOR performance and guide the design of treatments.
Field implementation of surfactant included different surfactant types: anionic, non-ionic, and cationic. HnP treatments were followed by a soak period before returning the well to production and conducting flow back water analysis. Overall, HnP treatments using cationic surfactant resulted in the highest efficiency in terms of barrels of oil per kilogram of surfactant. Well-to-well tests were only conducted with non-ionic surfactants and showed mixed results.
Design parameters for polymer injection such as fluid viscosity, concentration, adsorption and molecular weight were determined through coreflooding and fluid viscosity experiments. Two polymer types, high and low molecular weight, were studied and manufactured in-field and used in 200 or more injectors either continuously or alternating with produced water. Polymer injection was not effective in improving displacement efficiency in the water flood area of Yates reservoir and was suspended in 1989.
The scale of field implementation and analysis of the impact of chemical injection on oil production in a massive, densely fractured carbonate field has provided valuable insight and learnings for future development and will be discussed. Other chemical EOR methods currently under investigation such as foam and other wettability altering technologies will also be discussed.