bluuebunny/crossref_metadata_2025_split huggingface dataset:
TREND PENELITIAN KESEHATAN MENTAL REMAJA DI INDONESIA DAN FAKTOR YANG MEMPENGARUHI: LITERATURE REVIEW
Authors: Aisyaroh Noveri , Hudaya Isna , Supradewi Ratna 
Published: October 2022

Remaja merupakan periode terjadinya pertumbuhan dan perkembangan yang pesat baik secara fisik, psikologis maupun intelektual dengan jumlah sekitar 18% dari seluruh penduduk di Indonesia pada rentang usia 10 – 19 tahun. Permasalahan remaja Indonesia mencakup 3 hal penting; masalah sosial, masalah budaya dan masalah moralitas. Hal tersebut disebabkan rasa ingin tahu yang besar, menyukai petualangan serta berani mengambil resiko yang dapat berdampak pada kesehatan fisik maupun psikologis jika keputusan yang diambil tidak tepat. PKPR merupakan pelayanan pada remaja yang diberikan secara komprehensif di semua tempat termasuk didalamnya intervensi pada pelayanan kesehatan jiwa remaja, meliputi: masalah psikososial, gangguan jiwa, dan kualitas hidup termasuk dalam deteksi kesehatan mental remaja. Studi literatur ini bertujuan untuk mengetahui faktor-faktor yang mempengaruhi kesehatan mental pada remaja. Metode yang digunakan literatur review berasal dari jurnal nasional Indonesia melalui data base google scholar menggunakan kata kunci “kesehatan mental remaja”, kemudian diseleksi berdasarkan kriteria inklusi dan eksklusi, artikel yang terbit tahun 2017 – 2022 dengan desain penelitian kuantitatif. Hasil analisis dari 14 artikel, mengacu pada framework influences on mental health yang diadaptasi dari Social Determinants of Health, diperoleh 3 faktor utama yang berhubungan dengan kesehatan mental, yaitu 1) faktor gaya hidup (bullying, regulasi emosi, cyberbullying, disiplin dan motivasi), 2) jaringan sosial dan komunitas (dukungan teman, media sosial, game online, dan konseling teman sebaya) serta 3) sosial ekonomi, budaya dan kondisi lingkungan (religiusitas). Didapatkan juga karakteristik demografis serta adanya faktor yang tidak ada hubungan dengan kesehatan mental; pemilihan makanan, pola asuh serta pengguna instagram
ON THE ORIGIN, FUNCTION AND DIFFICULTIES IN SPELLING PARTICLES
Authors: Momynova B. 
Published: October 2022

The article discusses the origin of auxiliary words and their division into lexical-semantic groups based on the meanings belonging to these words. It also discusses the role of spelling principles in writing auxiliary words; thus, the article focuses on the spelling of auxiliary words. In this respect, it is mentioned about the difficulties in spelling certain auxiliary words, despite the established spelling norms. The author refers to the fundamental works of renowned Turkologists in the field of grammar, and supports his arguments with examples taken from modern dictionaries on orthography. Evolutionary changes in a number of auxiliary words are highlighted. The main purpose of the article is a comprehensive analysis of auxiliary words and syllables, identifying problems associated with the spelling of these linguistic units and providing ways to solve them. Therefore, when writing the article, the author provides References to the fundamental works of famous Turkic scholars published in the field of grammar on each statement, relies on dictionary materials and argues his opinion. By describing the historical background of auxiliary names as auxiliary words and determining their grammatical and lexical meanings, their function in the language has been described. An overview of the differences between conjunctions in Kazakh linguistics and Turkology has also been shown,
A Preliminary Wellbore In-Situ Stress Model for Utah FORGE
Authors: Ye Zhi , Fang Yuan , Ghassemi Ahmad , McLennan John 
Published: October 2022

ABSTRACT:
Knowledge of the in-situ stress is very important to the geothermal reservoir development as well as to the planned R&D activities at the Utah FORGE. Whereas the vertical stress (Sv) and the minimum horizontal principal stress (Shmm) can reliably be determined through density logs and hydraulic fracturing tests, respectively, the determination of the magnitude of maximum horizontal principal stress (SHmax) is challenging. In this paper, we established a preliminary wellbore in-situ stress model for the Utah FORGE based on the drilling-induced fractures and wellbore breakouts observed in borehole image logs. We utilize stress polygon (frictional faulting theory), wellbore failure analysis, drilling-induced fractures, and borehole breakouts to constrain the magnitude of the SHmax in the well 78B-32 where both tensile and compressive failures occur. The constrained SHmax is in the range 0.83-0.98 psi/ft. The results are compiled to obtain a wellbore in-situ stress profile for the well 78B-32 which is in good agreement with other data.

1. INTRODUCTION
Understanding the magnitude and orientation of in-situ stress is important to many subsurface science and engineering problems. In the development of an Enhanced Geothermal System (EGS), the knowledge of in-situ stress impacts several aspects such as reservoir characterization, deep well drilling, hydraulic stimulation, and induced seismicity.
Constraining the in-situ stress requires the determination of a stress tensor with six independent unknowns (the magnitudes of three principal stresses and their orientations). In most geological settings within the Earth’s upper crust, we can assume that the three principal stresses are vertical stress (Sv), and two horizontal principal stresses (Shmin and SHmax). In general, the magnitude of vertical principal stress (Sv) is obtained by integrating the density logs, and the magnitude of minimum principal stress (Shmin) can be measured through hydraulic fracturing tests (e.g., DFIT, leak-off test, microfrac test). In addition, the orientations of Shmin and SHmax can be identified using observed wellbore failures (breakouts and drilling-induced fractures), crossed-dipole sonic logs, and seismic focal mechanisms. However, the determination of the magnitude of maximum horizontal principal stress (SHmax) is challenging.
How Grooves Can Improve Casing Tripping-Out from the Cemented Borehole
Authors: Xie Xiyang , Ytrehus Jan David , Taghipour Ali , Kulkarni Raghavendra 
Published: October 2022

ABSTRACT:
Field observation shows a challenge to pull out a cemented casing without cutting it into pieces due to the limitation of pulling force. Required force can often be beyond the capacity of pulling equipment and it can also be beyond the material strength of the casing causing failure if one should be able to use excessive force for removal. For cases where removal of the cemented casing is necessary different approaches have been considered. Introducing grooves to the casing lowers the pulling force to remove it from the cemented wellbore and has been conceptually considered. This method has been demonstrated successfully in lab-scale experiments. The simulations, based on lab-scale geometry, verify the experimental observation and frictional cohesion, the key parameter to control pulling force, is quantified. The field-scale simulation indicates a significant reduction of the pulling force even with small grooves (5 mm width). The peak of the pulling force also illustrates the possibility of pulling a 10-meter grooved casing without cutting it into pieces. This study demonstrates a potential to shorten the non-productive time and save cost on plug and abandonment tasks.

1. INTRODUCTION
Pulling a 20-inch surface casing from cemented borehole encounters challenges. In a field scenario, the evaluated pulling force can be more than 1000 tons to trip out a 10-meter surface casing. The downhole pulling tool limits the pulling force up to 350 tons in many situations. This allows only a 3-meter casing section to be pulled out at each run. With such restrictions, a 10-meter casing would be cut into 3 pieces (3 meters for each piece) and pulled out one by one. These restrictions increase the non-productive operational time and cost. Therefore, novel technics are demanded to lower the pulling force if mechanical casing removal is to be applied further. The aim is to pull at least one 10-meter casing at once.
Mechanism Analysis of the Regular Pipe Sticking in Extended-Reach Drilling in the Eastern South China Sea
Authors: Zhao Jun , Huang Wenjun , Gao Deli , Zhao Lipeng 
Published: October 2022

ABSTRACT:
In the drilling process of extended-reach wells in the eastern South China Sea, the problem of regular pipe sticking is quite prominent. In order to effectively control it, this paper studies the mechanism of regular pipe sticking. It is thought that there are two main reasons: (1) A large number of open hole keyways are formed because connectors grind cuttings bed and wellbore; (2) Serious local cuttings accumulation at the connectors because of axial motion. Based on the above analysis, the mechanical resistance coefficient is introduced to characterize the local resistance of connectors. In this way, an amended drag & torque model is built. The case study shows that the local resistance and additional torque of each connector are about 360 N and 25 N·m during backreaming, and 350 N and 21 N·m while drilling. Furthermore, the mechanical resistance coefficient increases with the increase of cuttings bed thickness and the decrease of formation strength.

1. INTRODUCTION
In the 1920s, the United States first used extended-reach wells to develop offshore oil and gas fields, which indicated that the directional drilling technology was developed to a new level (Gao, 2018). At present, extended-reach well has become the key technology for developing complex oil and gas resources in ocean, beach, lake, etc (Gao, 2019).
Since the first extended-reach well was drilled in 1997, more than 70 extended-reach wells have been drilled in the eastern South China Sea, which made important contributions to the effective development of oil and gas resources (Shi, 2008; Gao, 2009). However, serious regular pipe sticking caused huge economic and time losses. Fig. 1 shows its typical performance. During the drilling process, pipe sticking occurs frequently and usually takes a single drill pipe as a period, but the circulation of drilling fluid and the rotation of drill pipe string are not suffocated. According to statistics, it takes about 0.5~4 hours to deal with a stuck point, and sidetracking is even required in some severe cases. In general, about 70% of the lost time was related to pipe sticking (Alshaikh, 2018).
Numerical Simulation of Wellbore Closure Due to Shale Creep: Potential for Annular Sealing Barrier Formation
Authors: Morales-Monsalve C. B. , Fontoura S. A. B. , Rosero-Argote S. , Lomba R. F. , Machado L. , Carrera S. , Ezechiello I. 
Published: October 2022

ABSTRACT:
The abandonment of an oil well at the end of its operational life must adhere to strict regulations to ensure that no leakage from the reservoir surrounding the wells occurs. The high costs of plug and abandon (P&A) operations have prompted the oil industry to investigate the possibility that certain rock formations around the well could deform enough during the well’s life to close the uncemented annular and strongly touch the casing, thereby promoting the formation of an impermeable barrier. This paper describes a protocol for numerical simulation of uncemented annular wellbore closure in shale sections. The simulation is carried out in plane strain and axisymmetric conditions using the commercial finite element code ABAQUS. The short-term drilling displacements are modeled using the rock’s elastic response, and the creep behavior is evaluated using poroviscoelastic behavior. The results show that, depending on the hypotheses used, the annular space can be closed in a variety of time spans. Finally, the contact pressure developed between the casing string and the rock formation upon full annular space closure is shown, as well as its variation over time.

1. INTRODUCTION
Nowadays, the worldwide process of well abandonment and decommissioning is accomplished through wellbore annular cementation; this procedure is carried out to prevent fluid (oil and gas) leakage from the well to the surface (Williams et al., 2009). With the goal of improving this process, the Brazilian Institute of Petroleum (IBP) developed the document "Guidelines for Well Abandonment," which emphasizes the creep potential of some sedimentary rock formations, particularly evaporites and shales, and how this property can act as permanent barriers in parts of casing wells and non-cemented wells (IBP, 2017). This unique mobility characteristic should ideally be observed throughout the field, giving it a regional character rather than being restricted to the location of a well. Furthermore, in order to consider this option as a possible substitute for the reliable isolation provided by a cement barrier during field abandonment, the rock formation, upon closure of the annular space, must have low permeability and be able to withstand the stresses, fluid pressures, and temperature that will be applied over time (Fjaer et al., 2016).
A Comprehensive Case Study on Lost Circulation of Changqing Mizhi Block in Perspective of Geomechanics
Authors: Li Xingbao , Ban Fansheng , Zhu Yujie , Luo Jiangwei , Chen Shaoyun , Jin Sheng , Che Zhenhua , Dong Jingnan 
Published: October 2022

ABSTRACT:
Drilling mud loss is of crucial importance in drilling. Lost circulation will extend the well construction period, cause investment losses, and even cause serious downhole accidents. In the Mizhi block of Changqing Oilfield targeted by this research, serious leakage occurred in many wellbore drilling processes, which has seriously affected the development of the block and caused economic losses. This paper focuses the mud loss during the drilling process of more than 200 wells in the Mizhi block, and counts the key loss data such as the lost horizons, the amount of lost drilling fluid, the average leak rate, and the density of the drilling fluid, and fully analyzes the possible reasons of the lost circulation. Collecting logging data, modeling geomechanics of some key wells and formations and taking cores. Finally, the geomechanical model is established. Analyzing the logging data and the specific leakage situation, the leakage mainly comes from fracture, and the leakage horizons mainly locate at the bottom of the Liujiagou Formation, the entire interval of the Shiqianfeng Formation and the top of the Shihezi Formation. Most of the mud loss sections are sand-mudstone interbeds. Geomechanical analysis shows that the rock mechanical strength of the entire interval is difficult to support the stability of the wellbore under the drilling fluid density of 1.1 grams per cubic meter, but the block loss pressure is generally between 1.1 - 1.2 grams per cubic meter. Collapse and leakage coexist in the wellbore. This study gives the method of drilling fluid optimization, and gives the possible reasons for the leakage from the perspective of geomechanics, which has important guiding significance for the further development of the Mizhi block.

1. INTRODUCTION
During drilling or completion operations, when the pressure of the effective drilling fluid density in the wellbore is greater than the formation pressure, the fluid will flow to the formation along the leakage channel around the wellbore, resulting in lost circulation. (MD Hashmat et al. 2016)Loss of circulation not only causes a large amount of drilling fluid loss, but also may cause a series of other drilling accidents, such as stuck pipe, blowout and even wellbore scrapped and other serious consequences.(Zhang et al.2016) Ultimately, it increases the non-operation time of drilling and causes huge economic loss. The time consumed to deal with lost circulation accounts for about 10% of drilling operation time, and the economic loss in drilling caused by lost circulation is as high as 2 billion US dollars every year.(Arshad Umar et al.2014) If the leakage appears in the reservoir, it will also cause reservoir damage, thus affecting the subsequent production of oil and gas. Therefore, lost circulation is regarded as one of the most complex and harmful accidents in drilling operations.
Modelling Stress Evolution in Cement Plugs During Hydration
Authors: Moghadam A. , Corina A. N. 
Published: October 2022

ABSTRACT:
In this work, we have developed a methodology to model the stress evolution in cement plugs during hydration. The model begins with the slurry state of cement and calculates the water consumption and void creation over time as the hydration reactions progress. The void volume change due to chemical shrinkage is imported into a coupled mechanical model that calculates the pore pressure drop and the resulting change in stresses. The results of the proposed modelling methodology are verified using lab experiments from the literature. The results provide new insights in understanding cement behavior under lab and field conditions. Under most scenarios, cement’s pore pressure drops to saturation pressure of water which leads to partial evaporation of the remaining pore water. This pore pressure drop controls the radial stress change, according to the theory of poroelasticity. For a plug set under an initial pressure of 5 MPa, the radial stress drops to 1.6 MPa after 20 hours of curing. This stress drop can cause the cement to debond from the casing, if the fluid pressure above the plug exceeds the final radial stress. This methodology can be extended to annular cements and initial cement stress after placement can be readily calculated.

1. INTRODUCTION
Zonal isolation in active and abandoned wells is paramount to ensure minimal fugitive methane emissions and to protect shallow freshwater aquifers. Wells penetrate different strata and can create a leakage pathway in case of a damaged cement sheath. This has been linked to methane emissions to the atmosphere (Schout et al., 2019), and aquifers (Osborn et al., 2011). Historically, oil and gas wells have been the main culprit in providing the leakage pathway for unwanted fluids. As more geothermal, energy, and carbon storage wells are drilled as part of the energy transition, zonal isolation challenges require more attention due to the long expected lifetime for these wells and unique operating conditions.
Effect of Interlaminar Difference on Height Propagation Behavior of Hydraulic Fracture in Lucaogou Shale
Authors: Zhang X. H. , Zhang S. C. , Zou Y. S. , Li J. M. , Wang J. C. , Zhu D. Y. , Zhou G. J. , Yang C. 
Published: October 2022

ABSTRACT:
The shale oil reservoir of Lucaogou Formation is characterized by complex lithology changes in vertical direction and lamination. To simulate the lithology variation of shale oil formation, downhole cores with different lithologies were prepared and bonded to layered samples. After that, the influence of interlaminar difference on propagation behavior of hydraulic fractures (HFs) was investigated through laboratory hydraulic fracturing and mechanical characteristics analysis. The result shows that mechanically weak bedding planes (BPs) leads to obvious anisotropy of rock mechanical properties. The rock samples is unstable when loaded along the parallel BPs direction, the tensile strength decline significantly, which is about 20% of the tensile strength measured perpendicular to BPs. The brittleness of rock samples measured parallel to BPs is greater than that measured perpendicular to BPs, by about two times. This results in HFs induced by low-viscosity slickwater are easily arrested by BPs, can not penetrate interlayer. HFs induced by high viscosity gel can penetrate the bonding interface. The difference of tensile strength between layers increases, the decrease degree of fracture width increases 2.5 times. This will impede proppant placement in interlayer. This research results provide a basis for the optimization of hydraulic fracturing of Lucaogou shale oil reservoir.

1. INTRODUCTION
The reservoirs of Lucaogou Formation in Jimusar sag, Junggar Basin are saline lacustrine and delta facies (Zou et al., 2020; Nie et al., 2011). The variation of climate and source supply intensity as well as the periodical fluctuation of lake level lead to the longitudinal lithology variation, and BPs development (Li et al., 2020; Zhang et al., 2021; Yang et al., 2018; Zhi et al., 2019 ). The influence of interlayer difference and BPs on reservoir fracture propagation is unclear. The selection of fracturing techniques and engineering parameters lacks theoretical support, and HFs height and vertical fracturing volume are limited (Lei et al., 2021; Jiang et al., 2021;). Understanding the influence of interlayer difference and BP structure on fracture propagation is the key to optimize hydraulic fracturing strategy, which is of great significance to improve the adaptability of fracturing process parameters and realize the overall utilization of multi-layer sweet spot body.
Development and Evaluation of a Novel Delayed Crosslink, Low Friction, High-Density Brine-Based Fracturing Fluid for Ultra-Deep Fracturing Stimulation
Authors: Xu Hang , Zhou Fujian , Wu Hao , Li Yuan , Sheng Lianqi , Yao Erdong 
Published: October 2022

ABSTRACT:
Using heavyweight brines as a base for fracturing fluids is an effective method for solving the problem of exorbitant surface pressure during the deep well fracturing process. However, higher fluid densities can lead to higher friction pressures, and with the well depth increases, the travel time to the mudline prolongs, resulting in the demand for extended crosslink delay times. Therefore, fracturing fluids that provide flexibility in density, lower friction and extended crosslink times are required for effective stimulation in ultra-deep reservoirs. This paper presents details of laboratory studies to develop and evaluate a novel weighted fracturing fluid. The main additives of the novel system were sequentially synthesized, including modified guar gum, a new weighting agent and an organic boron-zirconium crosslinker. Afterwards, a series of lab experiments were carried out to test the comprehensive performances of the novel system, such as temperature and shear resistance, friction reduction, gel breaking performance and core damage rate. The optimal formula of fracturing fluid was 54.3 wt.% weighting agent + 0.4 wt.% modified guar gum + 1.0 wt.% pH regulator + 0.5 wt.% crosslinker. Results show that the novel weighted fracturing fluid is a good choice for ultra-deep reservoir hydraulic stimulation and hence improving the recovery.

1. INTRODUCTION
Advancement of exploration and drilling technologies impel the oil and gas industry to extend the depth for hydrocarbons. Achieving efficient development of deep oil and gas is an important way for China’s recent oil and gas exploration and development (Xu et al., 2022; Lei et al., 2021; Wei et al., 2021). For major high-temperature and ultra-deep reservoirs in West China, hydraulic stimulation is facing some particular challenges. For instance, where the true vertical depth is more than 6000 m, there the rock fracturing pressure is often over 100 MPa and the temperature beyond 150 °C (Zhu et al., 2021; Ma et al., 2022). The traditional fracturing fluid system is difficult to play a role in the high-temperature deep well-fracturing process, and the weighted fracturing fluid system is a potential solution for deep well fracturing stimulation. At present, the formula of the weighted fracturing fluid system is not mature enough, and the upper limit of the density that can be weighted is restricted by economic and environmental protection (Wang et al., 2019; Yang et al., 2020; Qiu et al., 2009). Meanwhile, the weighted fluid system does not possess excellent friction reduction performance and cannot meet the requirements of deeper well fracturing stimulation. Therefore, it is essential to carry out the research on a novel weighted fracturing fluid system with high density, low friction and other excellent performances.