bluuebunny/crossref_metadata_2025_split huggingface dataset:
MEDIA SCRAPBOOK DALAM MENINGKATKAN KREATIVITAS SISWA SEKOLAH DASAR KOTA BENGKULU
Authors: Abdul Muktadir  , Prayuningtyas Angger Wardhani  , Alrahmat Arif  , Jatu Wahyu Wicaksono  
Published: September 2023

Pengembangan Media Scrapbook dalam Meningkatkan Kreativitas Siswa Sekolah Dasar Kota Bengkulu. Tujuan penelitian ini adalah mengembangkan media Media Scrapbook Dalam Meningkatkan Kreativitas Siswa Kelas IV Di Sekolah Dasar Kota Bengkulu yang valid. Metode yang digunakan adalah Reseach and Development dengan menggunakan model ADDIE ((Analysis – Design – Develop - Implement – Evaluate). Target dalam penelitian ini adalah siswa sekolah dasar kelas awal. Hasil penelitian menunjukkan bahwa media Scrapbook validasi ahli materi yang telah dilakukan memperoleh nilai rata-rata 4,75 dengan kategori sangat baik dan layak digunakan. Validasi bahasa juga memperoleh skor 4, 62 dengan kategori baik dan layak digunakan. Berdasarkan hasil tersebut dapat disimpulkan bahwa media scrapbook yang telah dikembangkan layak digunakan untuk meninfkatkan kreativitas siswa sekolah dasar.
Modern Patellofemoral Arthroplasty
Authors: Bond Elizabeth C. , Stauffer Taylor P. , Hendren Stephanie , Amendola Annunziato 
Published: September 2023

Introduction:
The ideal procedure for isolated patellofemoral arthritis is a controversial topic. Patellofemoral arthroplasty (PFA) is an option that aims to restore normal kinematics to the knee while preserving bone. PFA has been shown to have benefits compared with total knee arthroplasty (TKA) in this patient population but has historically had a high failure rate. Revision rates are improving with modern implants and tight indications but still remain higher than TKA. This review summarizes current thinking around PFA using modern implants and techniques in 2023, provides an implant-specific analysis, and assesses how we can improve outcomes after PFA based on the current literature. The aim was to provide an outline of the evidence around PFA on which surgeons can make decisions to optimize patient outcome in this young and active population.

Methods:
Four databases (MEDLINE, Embase, Scopus, and SPORTDiscus) were searched for concepts of patellofemoral joint arthroplasty. After abstract and text review, a screening software was used to assess articles based on inclusion criteria for studies describing indications, outcomes, and techniques for isolated PFA using modern implants, with or without concomitant procedures.

Results:
A total of 191 articles were included for further examination, with 62 articles being instructional course lectures, systematic reviews, technique articles, narrative reviews, expert opinions, or meta-analyses. The remaining articles were case reports, trials, or cohort studies. Articles were used to create a thorough outline of multiple recurrent topics in the literature.

Conclusions:
PFA is an appealing option that has the potential to provide a more natural feeling and functioning knee for those with isolated PF arthritis. The high rate of revision is a cause for concern and there are several technical details that should be stressed to optimize results. The uncertain outcome after revision to TKA also requires more investigation. In addition, the importance of strict selection criteria and firm indications cannot be stressed enough to optimize longevity and attempt to predict those who are likely to have progression of tibiofemoral osteoarthritis. The development of new third-generation implants is promising with excellent functional outcomes and a much lower rate of maltracking and implant complications compared with earlier generations. The impact of these implants and improvement in surgical techniques on the revision rate of PFA will be determined from longer-term outcomes.
President’s Column with Terry Palisch: Creating Our Energy Future (September 2023)
Authors: Palisch Terry 
Published: September 2023

Terry Palisch will take office as 2024 SPE President during the 2023 SPE Annual Technical Conference and Exhibition in October. The following is a transcript of his podcast episode recorded with Pam Boschee, SPE director of magazines, for this month’s Journal of Petroleum Technology.
In this inaugural podcast episode and transcript, we discussed Palisch’s views of the challenges facing our industry and SPE members, his outlook for our industry, and what his goals will be during his presidency.
Welcome to the Society of Petroleum Engineers podcast with 2024 President Terry Palisch. I’m Pam Boschee, director of SPE magazines, and Terry joins me today to share his thoughts about being named president with the official passing of the baton from 2023 President Med Kamal at our Annual Technical Conference and Exhibition (ATCE) in San Antonio in October.
Terry is the vice president of technology and engineering at Carbo Ceramics in Richardson, Texas. He began his career with Arco during which he served 10 years in Alaska and 4 years as a senior petroleum engineering advisor in Algeria. He joined Carbo in 2004, and in his current position leads a team of technologists developing and championing new products and services and advising clients in completion and fracture optimization.
He has been an SPE member for more than 40 years, serving in various roles including past chairman of the SPE Dallas Section. He has been the past chair of the ATCE technical program and the former SPE Completions Technical Director. He is an SPE Distinguished Member and received the award for Distinguished Service as well as the SPE Mid-Continent Regional Completions Optimization and Technology Award and the Regional Service Award. In 2013 he was named one of the top 15 best engineers by the Texas Independent Producers and Royalty Owners Association, and in 2015 he was named the SPE Dallas Section Engineer of the Year. He has authored more than 50 SPE technical papers and holds several patents.
He holds a bachelor’s degree in petroleum engineering from the University of Missouri Rolla, now the Missouri University of Science and Technology, and was recently recognized as a distinguished alumnus.
Test Shows Fracturing Can Also Create Underground Water Heating Systems
Authors: Rassenfoss Stephen 
Published: September 2023

Fervo Energy has shown that fracturing can be used to build a geothermal heating system in hot, hard rock.
During a 37-day test at its Project Red test site, the Houston company produced as much as 63 L/s (998 gal/min) of water heated to 336°F. By pumping water from an injection well through fractured hot rock to a producing well, it heated enough water to generate up to 3.5 MW of power, according to a company release.
In a world where demand is commonly measured in gigawatts, that’s not much, but it is more than double the highest flow rate from tests going back decades. And unlike those earlier tests, the company has a clear path to heating higher volumes and lowering the cost.
“I think this is just a big moment for both our company, but also the industry at large, to finally have this proof point where we can deliver commercial levels of permeability and flow rates for these wells,” said Jack Norbeck, co-founder and chief technical officer for Fervo.
The idea of injecting water through hot rock has been around for decades as a way to create enhanced geothermal systems (EGS), but this is the first time someone has achieved this level of flow and is moving next to create a group of geothermal wells for commercial generation.
Fervo has taken methods developed to extract oil and gas from ultratight rock and shown they can be used to do something quite different.
“Overall, there’s nothing really surprising here—they used a pretty standard shale frac design and observed pretty similar performance from what you would see in a shale play. Or at least, what you’d expect if you used a shale well as a long-term water injector and circulated fluid over to a neighboring production well,” said Mark McClure, chief executive of ResFrac, a reservoir modeling and consulting firm, in a blog post.
This fracturing-based option poses a challenge to EGS researchers who live in countries where completions using oil industry fracturing techniques are not an option.
“The EGS community has conventionally been focused on ‘stimulating natural fractures,’ and this has led them to use fracture designs that would be considered suboptimal, from the perspective of oil and gas field experience,” McClure said.
What Fervo has done is show that fracturing can be used to get past a barrier blocking EGS development using current fracturing technology.
“The breakthrough is that someone actually had the guts and organization to go out and do it,” McClure said.
Those at Fervo, though, have little time to celebrate the milestone as they focus on improving those methods to economically produce geothermal energy.
“In successfully completing this project, we have demonstrated that no major technical barriers exist to deploying horizontal EGS in similar meta-sedimentary or igneous formations to temperatures of approximately 400°F,” according to a Fervo paper.
That feat was recognized by a leader at the FORGE test site, which is also doing EGS research and development with substantial financial support from the US Department of Energy.
Case Study: Conductor-Integrity Monitoring in Subsea Wells in Harsh Environments
Authors: Holden Harald 
Published: September 2023

_
A decade-long project to monitor drilling operations on subsea wells in harsh environments has delivered interesting results.
Subsea production and exploration wells are subjected to loads from the drilling riser and subsea blowout preventors (BOP). The latter have grown in size and weight over time, resulting in larger wellhead loads.
The main task of a subsea conductor is to transfer these loads into the seabed. The bending load applied on the wellhead is transferred into the conductor, which again transfers the loads through the cement and into the soil.
In cases where the load exerted on the soil and cement exceeds the capacity, the soil around the conductor might fail. The cement filling the cavity between the conductor and the soil can also crack and consequently lose its intended function. This support degradation reduces the conductor’s ability to support the well.
4Subsea’s Subsea Wellhead Integrity Monitoring (SWIM) service for operations on subsea wells has now been in action for more than a decade. Sensors monitoring the motion and loads near the subsea wellhead have been mounted on more than 300 drilling campaigns (Fig. 1). In recent years, more than 70% of the drilling operations with semisubmersible drilling rigs on the Norwegian Continental Shelf (NCS) have been monitored using SWIM.
As a part of the service, integrity parameters showing whether the conductor gives the intended amount of support are calculated. A major finding is that loss of conductor support during drilling operations has been observed in several of these campaigns, with different integrity issues detected.

In at the Deep End
Wells in the North Sea, the Norwegian Sea, and the Barents Sea are often developed as subsea fields. The typical setup while drilling these wells utilizes a mobile drilling unit (semisubmersible or drillship) with a marine riser and subsea BOP. The well foundation must be designed to withstand the imposed loads.
In accordance with Norwegian Safety Authority facility regulations, wells and their foundations must follow strict regulations. These include that the conductor shall provide structural integrity of the well during its service life, and that it shall be evaluated with respect to structural loads and fatigue.
Subsea wells can be divided into two categories based on the type of support of the respective conductor.
- Supported conductors are the most-common configuration for subsea production wells in harsh environments, with a template structure supporting the conductor.
- Unsupported conductors are used for exploration and production wells in less-harsh environments.
During well foundation design, there are typically three different failure modes to consider.
- Extreme load failure (ULS, ALS) of the wellhead system and supporting structures
- Fatigue failure (FLS) of the wellhead system and supporting structure
- Failure of the soil support and cement around the conductor
SWIM covers both fatigue monitoring and detection of issues with the soil and cement support.
Technology Focus: Field Development (September 2023)
Authors: Garmeh Reza 
Published: September 2023

The integration of machine learning and physics-based simulation modeling offers a comprehensive approach to optimizing unconventional development and addressing parent-/child-well depletion issues. By combining the predictive capabilities of machine-learning models with the insights gained from physics-based modeling, operators can develop customized solutions tailored to the specific characteristics of the reservoir. Machine-learning models can optimize well-spacing, -placement, and -completion designs, while physics-based simulation modeling provides a deeper understanding of reservoir behavior and performance.
Machine learning has emerged as a powerful tool, leveraging large volumes of data to provide data-driven insights and predictive capabilities. By training machine-learning models on geologic, completion, and spacing data, operators can predict production performance and make informed decisions to enhance production and cost-efficiency.
Parent/child interactions, where production from a parent well negatively affects subsequent child wells, pose challenges in unconventional development. Benchmarking, through the comparison and analysis of performance data, plays a crucial role in understanding and mitigating these issues. By benchmarking production data, completion designs, and reservoir properties, operators can identify best practices and develop strategies to minimize the interference between parent and child wells.
By harnessing the power of data-driven insights and the knowledge gained from physics-based simulation modeling, operators can make informed decisions regarding well spacing, completion designs, and operational strategies. This integrated approach enhances decision-making, reduces uncertainties, and increases overall efficiency in unconventional development projects. As technology continues to advance, the use of machine learning and physics-based simulation modeling will further improve the optimization of unconventional development, driving the industry toward greater efficiency and sustainability.
The selected papers and suggested additional reading provide valuable insights into the evolving field of development optimization using physics-based simulation models and machine learning.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 205651 Digital Field Development Planning: A Collaboration Between Technology and Process To Enable Fast and Efficient Field Development Planning by Mohd Aminuddin Bin Md Karim, Petronas
SPE 207899 Artificial Intelligence for Infill Well Placement and Design Optimization in Multilayered/Stacked Reservoirs Under Subsurface Uncertainty by Shi Su, SLB, et al.
SPE 208529 A Comprehensive Machine-Learning Approach for Quantitatively Analyzing Development Performance and Optimization for a Heterogeneous Carbonate Reservoir in the Middle East by Ruijie Huang, Research Institute of Petroleum Exploration and Development, et al.
Potential Revealed for Hydrogen Production From Offshore Wind in Uruguay
Authors: Carpenter Chris 
Published: September 2023

_
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31879, “Assessment of the Potential for Hydrogen Production From Bottom‑Fixed Offshore Wind in Uruguay,” by Juan Tomasini, SPE, Pablo Gristo, SPE, and Santiago Ferro, SPE, ANCAP, et al. The paper has not been peer reviewed. Copyright 2022 Offshore Technology Conference. Reproduced by permission.

_
With almost the entire electricity matrix having been decarbonized, the next step in the Uruguayan energy transition includes the development of a hydrogen economy. In the complete paper, the authors present the results of the assessment of two regions suitable for bottom-fixed offshore wind energy (OWE) technologies. Results are encouraging and could lead to new possibilities in supporting the development of a hydrogen economy.

Introduction
For Uruguay, hydrogen is expected to play an important role in tackling the various challenges of the second phase of decarbonization; it holds the potential for use in the transport sector and in raw materials and chemical products.
Having no oil production, Uruguay is a net oil importer; therefore, the extensive use of hydrogen in the domestic market may have a profound effect on the national economy and energy sovereignty. Preliminary findings show that Uruguay may have hydrogen production costs between $1.2 and $1.4/kg, placing the country among the world’s net exporters.

Green Hydrogen Production From Offshore Renewable Energy
Compared with onshore wind, OWE presents several advantages, including a greater capacity of each turbine (fewer turbines required for the same wind-farm capacity) and the availability of larger areas (allowing larger wind-farm capacity). Even if bottom-fixed is the predominant technology for OWE projects, floating technology is attracting increasing investment and public policy support because of its potential to access wind resources at water deeper than 40 m, where bottom-fixed may be less feasible technically, economically, or logistically.
Green Hydrogen Production. Contrasting with blue or gray hydrogen (produced from fossil fuels with or without carbon capture and storage, respectively), green hydrogen provides the lowest near-zero-emissions option. Green hydrogen can be produced through the gasification of biomass or the electrolysis of water powered by renewable electricity.
Alkaline electrolysis and proton-exchange-membrane (PEM) technologies are widely available commercially. Alkaline electrolysis is a fully mature technology that represents the lower-cost option, but its operational load limits are not as broad as those for PEM; therefore, its coupling with variable renewable sources should be carefully managed. On the other hand, PEM electrolysis is not yet a fully mature technology, with higher costs that are expected to be reduced in the coming years.
Technology Focus: Oilfield Chemistry (September 2023)
Authors: Fuller Michael 
Published: September 2023

Avid readers of recent technical literature in upstream energy can identify an upward trend in the frequency of studies that use large-data-set analysis to improve decision-making regarding production and operations. While big data and artificial intelligence had originally been fascinating concepts without wide examples of practical use, recent studies have showcased more practical uses of these methods of data analytics.
The technical arena of oilfield chemistry, both that of the natural downhole environment and that of chemistry introduced downhole, provides a rich testing ground for advanced uses of data. Whereas early uses of data in the upstream chemical space included use of design of experimentation for vetting or developing new chemistries, today data analytics enables, for example, production allocation based on assessment of produced hydrocarbons. Featured studies showcase this type of application of data analytics to improve production assessment. One example reviewed various geochemical methods to allocate zonal contribution to production by analyzing produced fluid composition and decoupling the contributions of individual zones’ fluids. Another selection measured the carbon isotope signatures of gas from individual zones and used it to determine the thermal maturity of the gases from different reservoirs; this work has the potential for similar zonal allocation assessment of gas production.
In its current maturity, machine learning also provides significant potential to improve our understanding and prediction of downhole chemical reactions. In another featured study, a geochemical data set of staggering proportions was populated with water composition data from many years and wells. Coupled with the equations that govern many downhole reactions to use machine learning, the presented tool allowed improved modeling and prediction of, for example, inorganic scaling behavior under downhole conditions.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 206091 Asphaltenes: Fundamental Principles to Oilfield Applications by Oliver Mullins, SLB, et al.
SPE 211238 Detection and Monitoring of Corrosive Oilfield Microorganisms Through Novel Biomarker Technologies by Sven Lahme, ExxonMobil, et al.
SPE 207340 Toward the Rational Design of Chemical Formulations for EOR From Carbonates: Molecular-Level Understanding of Carbonate Wettability and Its Reversal by Surfactants and Ions by Shixun Bai, University of Wyoming, et al.
Geochemical Approaches Assist Production Allocation of Commingled Fluids
Authors: Carpenter Chris 
Published: September 2023

_
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 205130, “The Application of Petroleum Geochemical Methods to Production Allocation of Commingled Fluids,” by Richard Patience, Mark Bastow, and Martin Fowler, Applied Petroleum Technology, et al. The paper has not been peer reviewed.

_
Geochemical-based methods for production monitoring and allocation are much lower-cost than use of production logging tools because no additional rig time or extra personnel are required at the well site. Additionally, no intervention to the production of hydrocarbons from a well is required, reducing operational risk. The complete paper summarizes these approaches and provides examples and describes a best practice that avoids a one-size-fits-all approach.

Introduction
Production allocation from petroleum geochemistry is defined here as the quantitative determination of the amount or portion of a commingled fluid to be assigned to two or more individual fluid sources at a particular moment in time based on fluid chemistry. It requires knowledge of the original chemical compositions of each of the fluids before mixing (referred to here as the “end members”) and the ability to identify statistically valid differences in their chemistries. The fluid may be oil, gas, or water. The concept is illustrated in Fig. 1a by mixing colors to represent the end members and commingled fluid.
Production monitoring, in contrast, is the analysis of a time series of production fluids from the same source. This is demonstrated in Fig. 1b, where a change in chemistry can be observed between Days 60 and 100. Two data points at the same time are duplicates, proving that the change in chemistry is real and not an artifact.
It is generally qualitative to semiquantitative in comparison with production allocation.
Production allocation, therefore, is inherently more complex, in terms of both the sample requirements and data treatment. Allocation is the main focus of this paper.

Allocation Sampling Strategies
For a production allocation project, the three following distinct stages require samples:
Stage 1: Can Contributing End Members Be Distinguished? In the initial stage, a determination must be made regarding whether end member reservoirs contributing to production can be distinguished based on their chemical composition.
End Members From Conventional Plays. These typically are flowed samples from drillstem tests, bottomhole samples from wireline tools, or production tests, usually taken during the drilling of exploration or appraisal wells.
Several issues must be considered when assessing the usefulness of such samples:
- Are the end member samples representative of the reservoir as a whole?
- Is the end member sample contaminated with organic compounds from drilling fluid?
- When were the end members taken, how were they stored, and has there been significant alteration of the composition of the sample as a result?