bluuebunny/crossref_metadata_2025_split huggingface dataset:
BACTERIAL AND SENSITIVITY PATTERN OF PATHOGENS CAUSING VENTILATOR-ASSOCIATED PNEUMONIA IN INTENSIVE CARE UNIT
Authors: Mustikaningtyas Marsheila Harvy , Semedi Bambang Pujo , Kuntaman Kuntaman 
Published: January 2022

Highlight:1. Antimicrobial resistance bacteria isolated from VAP patients are often associated with high mortality and length of hospital stay. 2. Mortality in VAP patients was 33.3% and the VAP group had a longer hospital stay compared to the non-VAP group. 3. The three most predominant bacteria that were found were A. baumannii, P. aeruginosa, K. pneumoniae. Cefoperazone-sulbactam, meropenem and amikacin were more than 70% sensitive against these bacteria.Abstract:Background: Ventilator-Associated Pneumonia (VAP) is the most common nosocomial infection in Intensive Care Unit (ICU). Antimicrobial resistant bacteria isolated from VAP patients are often associated with high mortality and length of hospital stay. Objective: This study aimed to analyze the pattern and sensitivity among pathogens that caused VAP in ICU. Materials and Methods: The study was conducted retrospectively by extracting the data of bacterial isolates from sputum specimens in the Laboratory of Clinical Microbiology, Dr. Soetomo General Academic Hospital, Surabaya, Indonesia and confirming the clinical data on patients suffering from VAP in ICU ward. The study started from January until December 2017. Results: The total 148 pathogens were isolated, 18 of them were diagnosed as VAP, and 130 were not VAP. The most predominant isolates in the VAP group were Acinetobacter baumannii as many as 38 (9%) followed by Pseudomonas aeruginosa 22 (2%), E. coli 16 (7%), and Klebsiella pneumoniae 11 (1%). The pathogens showed a sensitivity rate above 70% to cefoperazone-sulbactam (SCF), meropenem (MEM) and amikacin (AK). Mortality in VAP patients was 33.3% and the VAP group had a longer hospital stay compared to non-VAP group. Conclusion: The three most predominant bacteria that were found were A. baumannii, P. aeruginosa, K. pneumoniae. The pathogens had sensitivity rate above 70% to cefoperazone-sulbactam, meropenem, and amikacin.
SERUM AFP (ALPHA FETO PROTEIN) LEVELS PROFILE OF HEPATOCELLULAR CARCINOMA PATIENTS IN DR. SOETOMO GENERAL ACADEMIC HOSPITAL, SURABAYA, INDONESIA
Authors: Putri Dyeneka Rustanti Indreswara , Maimunah Ummi , Retnowati Endang 
Published: January 2022

Higlight:1. The USG results of AFP level can be used for early detection and therapy of hepatocellular carcinoma that can prevent metastasis, progressivity, and recurrence. 2. The most common patients with high AFP levels are those with hepatitis B depending on etiology, younger age, male, gender, high SGOT level and BCLC B patients.Abstract:Background: Hepatocellular carcinoma (HCC) accounts for more than 90% of liver cancer which is the second most common cause of cancer-related death worldwide. The incidence of HCC was 626.000 cases every year worldwide. Early detection and therapy can prevent metastasis, progressivity, and recurrence. AFP level ≥ 400 ng/ml and USG results can be used as a diagnosis parameter of hepatocellular carcinoma. Objective: To analyze the AFP level’s profile in hepatocellular carcinoma. Materials and Methods: Descriptive methods used in this study with data collected from medical records on patients that fulfilled the inclusion criteria in Dr. Soetomo General Academic Hospital, Surabaya, Indonesia during the periods of 1st January 2013- December 31st 2015. This study used various variables such as age, gender, etiology and size of the tumor, number of a nodule, hepatic function with child classification, staging BCLC, and AFP level. Results: This study found that the 98 patients with hepatocellular carcinoma with high AFP level or >400 ng/ml were dominated by younger patients with average age of 49.91 years, the most common etiology was hepatitis B (56.8%), poor results of laboratory tests (SGOT, SGPT), patients with all level of hepatic function based on Child-Pugh classification and staging B of the tumor (70.5%). Patients with normal AFP ≤20 ng/ml were dominated by female patients, with the most common etiology of fatty liver and others, and with BCLC A and C staging. Descriptively, there was no difference in AFP level based on the number of nodules and size of tumor. Conclusion: The most common patients with high AFP level are those who have hepatitis B as etiology, younger age, male gender, high SGOT level and BCLC B staging. Meanwhile, patients with normal AFP level dominated with female and non-hepatitis patients. In this research, we found no differences of AFP level based on number and size of tumor descriptively.
Gambaran Self-Care Guru Bimbingan dan Konseling di SMA Negeri Se-DKI Jakarta
Authors: Eka Wahyuni  , Rani Desinta  
Published: January 2022

Penelitian ini bertujuan untuk mendapatkan gambaran self-care guru Bimbingan dan Konseling di SMA Negeri se-DKI Jakarta. Sampel penelitian ini berjumlah 195 guru BK dengan menggunakan teknik convenience sampling. Metode yang digunakan adalah pendekatan kuantitatif dengan metode survey. Pengumpulan data dilakukan secara online dengan menggunakan instrumen Professional Self-Care Scale. Hasil penelitian menunjukan pada umumnya self-care guru BK di SMA Negeri se-DKI Jakarta berada pada kategori tinggi dengan rerata sebesar 123.14. Sebanyak 184 guru BK (94.36%) memiliki self-care tinggi, terdapat 11 guru BK (5.64%) memiliki self-care sedang, dan tidak ada satupun guru BK yang memiliki self-care rendah. Pengembangan profesional mendapat rerata paling tinggi sebesar 6.20, sedangkan keseimbangan harian mendapat rerata terendah dengan skor 5.10. Strategi kognitif mendapati rerata sebesar 6.10, dukungan profesional mendapat rerata sebesar 5.90, dan keseimbangan hidup mendapat rerata sebesar 5.80. Hasil ini menunjukan bahwa guru BK mampu mencari peluang untuk pertumbuhan profesional dan keterlibatan dalam kegiatan profesional yang menyenangkan, dapat memantau stres serta reaksi di tempat kerja, mampu menumbuhkan hubungan saling mendukung dengan rekan kerja, mampu membina hubungan dan kegiatan di luar pekerjaan, namun mereka masih membutuhkan pengembangan tentang mengelola tuntutan pekerjaan serta mengelola kegiatan sehari-hari.
Hydraulic Fracture Treatment and Landing Zone Interval Optimization: An Eagle Ford Case Study
Authors: Al Mulhim Abdulrahim K. , Miskimins Jennifer L. , Tura Ali 
Published: January 2022

Abstract
This paper focuses on optimizing future well landing zones and their corresponding hydraulic fracture treatments in the Eagle Ford shale play. The optimum landing zone and stimulation treatment were determined by analyzing multiple landing zone options, including the lower Austin Chalk, Eagle Ford, and Pepper Shale, with several hydraulic fracturing treatment possibilities. Fracturing fluids and their volume, proppant size, and cluster spacing were investigated to determine the optimum hydraulic fracturing treatment for the subject geologic area. Ranges of 75,000 to 300,000 gallons of pure gel, pure slickwater, and hybrid fracturing fluids along with 20/40, 30/50, 40/70, and 100 mesh proppant were tested. Cluster spacing of twenty feet to eighty feet were also sensitized in this study.
A fully three-dimensional hydraulic fracture modeling software was used to develop a geological and geomechanical model of the studied area. The generated model was calibrated with available field data to ensure that the model reflects the area's geological and geomechanical characteristics. The developed model was used to create fracture results for each sensitized parameter. Production analysis was performed for all fracture models to determine the optimum landing zone and fracturing treatment implications.
The study shows that the Eagle Ford had better production than the lower Austin Chalk in the subject area. The Pepper Shale had the highest potential hydrocarbon production, around 326 Mbbl cumulative, when fractured with a pure gel treatment. The analyses showed that a hybrid treatment with 70% gel and 30% slickwater yielded the optimum production due to the treatment economics even though the highest production was obtained using the pure gel. Treating the formation with larger proppant provided better production than smaller proppant due to conductivity concerns associated with damaging mechanisms in the studied area. Since increasing the volume above 175,000 gallons caused a negligible increase in the production, 175,000 gallons of fracturing fluid per stage appeared to be the optimum fracturing fluid volume. Thirty-foot cluster spacing was the optimum spacing in the study area. Overall, the study suggests that oil production can be improved in the Eagle Ford study area through a detailed workflow development and optimization process.
The hydraulic fracture treatment and landing zone optimization workflow ensures optimum hydrocarbon extraction from the study area. The developed workflow can be applied to new unconventional plays instead of using trial and error methods.
Casing Deformation Mitigation Achieved Through Ball Activated Sliding Fracturing Sleeves – An Alternative to Plug and Perf Fracturing Operations
Authors: Gandomkar Arjang , Katz David , Gomez Ricardo , Gundersen Anders , Khan Parvez 
Published: January 2022

Abstract
Casing Deformation has plagued numerous unconventional basins globally, in particular with plug-and-perforation (also known as plug-and-perf) operations. This infamous issue can greatly influence 20-30% of field productivity of horizontal wells in shale and tight oil fields (Jacobs, 2020). When a wellbore lies in a target zone and intersects many natural fractures, these fractures are perturbed by hydraulic stimulation. Therefore, rock or bedding slippage may occur, resulting in casing deformation. This phenomenon is escalated by active tectonics, high anisotropic in-situ stresses, and poor cement design.
This paper evaluates the mechanisms of casing deformation. It reviews how these conditions can be evaluated in the target zone. The mitigation procedures to reduce casing deformation through either well planning or completions design are discussed. Finally, an alternative completion method to plug-and-perf allowing limited entry completion technique in restricted casing with a field case study will be discussed.
Revision of Pressure Transient Analysis in Mature Condensate-Rich Tight Gas Fields in Sultanate of Oman
Authors: Hegazy Ahmed Elsayed , Rashdi Mohammed 
Published: January 2022

Abstract
Pressure transient analysis (PTA) has been used as one of the important reservoir surveillance tools for tight condensate-rich gas fields in Sultanate of Oman. The main objectives of PTA in those fields were to define the dynamic permeability of such tight formations, to define actual total Skin factors for such heavily fractured wells, and to assess impairment due to condensate banking around wellbores. After long production, more objectives became also necessary like assessing impairment due to poor clean-up of fractures placed in depleted layers, assessing newly proposed Massive fracturing strategy, assessing well-design and fracture strategies of newly drilled Horizontal wells, targeting the un-depleted tight layers, and impairment due to halite scaling. Therefore, the main objective of this paper is to address all the above complications to improve well and reservoir modeling for better development planning.
In order to realize most of the above objectives, about 21 PTA acquisitions have been done in one of the mature gas fields in Oman, developed by more than 200 fractured wells, and on production for 25 years. In this study, an extensive PTA revision was done to address main issues of this field. Most of the actual fracture dynamic parameters (i.e. frac half-length, frac width, frac conductivity, etc.) have been estimated and compared with designed parameters. In addition, overall wells fracturing responses have been defined, categorized into strong and weak frac performances, proposing suitable interpretation and modeling workflow for each case.
In this study, more reasonable permeability values have been estimated for individual layers, improving the dynamic modeling significantly. In addition, it is found that late hook-up of fractured wells leads to very poor fractures clean out in pressure-depleted layers, causing the weak frac performance. In addition, the actual frac parameters (i.e. frac-half-length) found to be much lower than designed/expected before implementation. This helped to improve well and fracturing design and implementation for next vertical and horizontal wells, improving their performances. All the observed PTA responses (fracturing, condensate-banking, Halite-scaling, wells interference) have been matched and proved using sophisticated single and sector numerical simulation models, which have been incorporated into full-field models, causing significant improvements in field production forecasts and field development planning (FDP).
Fracture Geometry Calibration Using Multiple Surveillance Techniques
Authors: Jaboob Musallam , Al Shueili Ahmed , Al Salmi Hussien , Al Hajri Salim , Merletti German , Kayumov Rifat , dwi Kurniadi Stevanus , Sebastian Trejo Ricardo 
Published: January 2022

Abstract
An accurate Mechanical Earth Model (MEM) is of vital importance in tight gas reservoirs where hydraulic fracturing is the only way to produce hydrocarbons economically. The Barik tight gas reservoir is the main target in Khazzan and Ghazeer Fields at the Sultanate of Oman (Rylance et al., 2011). This reservoir consists of multiple low-permeability sandstone layers interbedded with marine shales. A good understanding of the fracture propagation in such a reservoir has a major effect on completion and fracturing design. The MEM derived from sonic logs and calibrated with core data needs to be further validated by independent measurements of the fracturing geometry.
Multiple surveillance techniques have been implemented in the Barik reservoir to validate the MEM and to match observations from hydraulic fracturing operations. These techniques include closure interpretation using a wireline deployed formation testing assembly, the use of mini-frac injection tests with deployed bottomhole pressure gauges, execution of post injection time-lapse temperature logging, the injection of radioactive tracers, associated production logging, subsequent pressure transient analysis and other techniques.
A cross-disciplinary team worked with multiple sources of data to calibrate the MEM with the purpose of delivering a high-confidence prediction of the created fracture geometry, which honors all available surveillance data. In turn, this validation approach provided a solid basis for optimization of the completion and fracturing design, in order to optimally exploit this challenging reservoir and maximize the economic returns being delivered. For example, combination of stress testing with radioactive tracers provided confidence in stress barriers in this multilayered reservoir. Pressure transient analysis allowed to calibrate mechanical model to match fracturing half-length that is contributing to production.
This paper provides extensive surveillance examples and workflows for data analysis. Surveillance of this degree in the same well is uncommon because of the associated time and cost. However, it provides unique value for understanding the target reservoir. This paper demonstrates the Value Of Information (VOI) that can be associated with such surveillance and provides a concrete and practical example that can be used for the justification of future surveillance programs associated with the hydraulic fracturing operations.
Surfactant and Friction Reducer Interaction in High Salinity Slickwater Fracturing
Authors: Kotb Abdelrahman , Almubarak Tariq , Nasr-El-Din Hisham A. 
Published: January 2022

Abstract
Slickwater fracturing has been phenomenally successful in unconventional shale formations due to their unique geomechanical properties. Nevertheless, these treatments consume large volumes of water. On average, hydraulic fracturing treatments use up to 13,000,000 gallons of water in unconventional wells. In an effort to reduce the use of freshwater, research has focused on developing friction reducers (FR) that can be used in high salinity brines such as seawater and produced water. However, commonly used friction reducers precipitate in high salinity brine, lose their friction reduction properties, and cause severe formation damage to the proppant pack. Consequently, this work proposes the use of common surfactants to aid the FR system and achieve salt tolerance at water salinity up to 230,000 ppm. This paper will (a) evaluate five surfactants for use in high salinity FR systems, (b) evaluate the rheological properties of these systems, and (c) evaluate the damage generated from using these systems.
Four types of tests were conducted to analyze the performance of the new FR at high salinity brine. These are (a) rheology, (b) static proppant settling, (c) breakability, and (d) coreflood tests. Surfactants with ethylene oxide chain lengths ranging from 6 to 12 were incorporated in the tests. Rheology tests were done at temperatures up to 150°F to evaluate the FR at shear rates between 40-1000 s-1. Proppant settling tests were performed to investigate the proppant carrying capacity of the new FR system. Breakability and coreflood tests were conducted to study the potential damage caused by the proposed systems.
Rheology tests showed that using surfactants with high ethylene oxide chain length (&gt;8) improved the performance of the FR at water salinity up to 230,000 ppm. Anionic surfactants performed better than cationic surfactants in improving FR performance. The ammonium persulfate was used as a breaker and showed effectiveness with the proposed formula. Finally, the retained permeability after 12 hours of injecting the FR was over 95%. This shows that after using this system, the productivity of the formation is minimally affected by the new FR system.
This research provides the first guide on studying the impact of using different ethylene oxide chain lengths of surfactants in developing new FR systems that can perform well in a high salinity environment. Given the economic and environmental benefits of reusing produced water, this new system can save costs that were previously spent on water treatments.
The Impact of Extended-Time Proppant Conductivity Impairment on the Ultimate Recovery from Unconventional Horizontal Well Completions
Authors: Pearson C. Mark , Fowler Garrett 
Published: January 2022

Abstract
The stimulation design of hydraulically fractured wells has always pitted the engineer's capability to maximize the fracture extent (or fracture half-length within the formation) versus the conductivity of the fracture pack generated by the deposited proppant material. In essence, the area of productive reservoir rock contacted by the hydraulic fracture treatment needs to be appropriately engineered to remain connected to the wellbore over the life of the well to maximize reservoir recovery.
The completion design of multi-stage hydraulically fractured horizontal wells has been driven by their application to unconventional oil and gas reservoirs. This has primarily occurred in North America where most of the wells drilled and completed were operated by small, private, or upstream-only independent public companies. Metrics used to evaluate performance and completion design changes were short-term in nature and typically focused on parameters such as peak-month production, 90- or 180-day cumulative production; or at longest, the first year or two of cumulative production. Capital efficiency, and capital return or well payout were drivers of value creation in an environment where the well inventory was viewed as extensive if not unlimited and the quick recycling of invested capital created the illusion of value creation.
Short-term performance metrics give credence to fracture designs that value most the early-time production that is dominated by rate acceleration. The work presented in this paper shows a comparison of fracture designs in deep unconventional formations looking to minimize cost by pumping all sand proppants versus a focus on ultimate recovery from the reservoir with designs that are more applicable to the stress regime. The work shows the importance of maintaining the wellbore connectivity to the reservoir by designing fracture treatments using proppant conductivity decline data measured over an extended-time period of months or years to maximize ultimate recovery from the reservoir. This approach will be critical to those E&P companies who view their well inventory or resource base as finite and consequently place a priority on maximizing recovery from the reservoir.
The Use of Hydraulic Completion Snubbing Units HCU in Long Laterals in U.S. Shale Plays
Authors: Frantz Joseph H. , Tourigny Matthew L. 
Published: January 2022

Abstract
Coiled tubing units (CTU) have been used to drill-out frac plugs in shorter horizontal shale wells for the last decade, but coil has mechanical limitations. The new innovative technology of Hydraulic Completion Snubbing Units (HCU) is gaining popularity across North and South America to drill-out frac plugs in long lateral, high-pressure, and multi-well pads. The HCU is designed for drill-outs and interventions where coil may not be the best option. This paper will summarize the recent evolution of the HCU system. Case histories will be provided from the Appalachian and Permian shale plays.
The latest HCU consists of a stand-alone unit that mounts on the wellhead after completion. The primary components include the jack assembly, a gin pole, traveling/stationary slips, a redundant series of primary/secondary blowout preventers, a rotary table, power tongs, and an equalize/bleed off loop. Tubing up to 5 ½" is used to carry a downhole motor, dual back pressure values, and the drill bit. Slickwater is used for the drilling fluid to carry out parts from the frac plugs while the tubing is rotated via the jack rotary table. Torque and drag modeling are performed to guide downhole expectations that allow most wells to be drilled in one trip and with one bit without short trips back to the heel or bottom- hole vibration assembly tools. Finally, a remote telemetry data acquisition system has been added that summarizes the drilling data and key performance indicators.
In 2016, a North American operator drilled and completed the first super lateral in the Appalachian Basin, setting the completed lateral record at over 18,500 ft. Since then, many operators have been routinely drilling laterals between 12,000 ft and 16,000 ft. HCU technology has been used in the longest laterals in onshore North America, including the lower 48 U.S records for completed lateral length (LL) at 20,800 ft and the total measured depth (MD) record at 30,677 ft. The average lateral contains between 60 to 90 plugs and can be drilled out in 3.5 to 4.5 days. The record number of plugs drilled out by an HCU is 144 and took 5.2 days. High-pressure wells are also routinely encountered where pressures range from 3000 to 8000 psi during operations. Operators are achieving faster drilling times per plug, less chemical usage, faster moves between wells, and running tubing immediately after the drill-out, thus eliminating the need for a service rig.
Operator's desire to reach total depth with the least risk and as cost-efficiently as possible resulted in the HCU gaining market acceptance. This paper will showcase the novel evolution of the HCU system that has enabled it to be a safe and effective option for interventions outside of just frac plug drill-outs such as fishing for stuck/parted coil or wireline and installing production tubing/artificial lift systems.