bluuebunny/crossref_metadata_2025_split huggingface dataset:
Public knowledge, beliefs, psychological responses, and behavioural changes during the outbreak of COVID-19 in the Middle East
Authors: Abazid Husam , Basheti Iman A. , Al-Jomaa Esraa  E. , Abazid Ayham , Kloub Warda M. 
Published: May 2021

Objective: To evaluate the knowledge, believes, psychological and behavioural impact of COVID-19 on the general population in the Middle East, exploring how it impacted public lives.
Methods: A descriptive cross-sectional online survey was sent to a convenience sample in the Middle East through social media (Facebook and WhatsApp) between 16th of June and 30th of June 2020. The questionnaire was designed to collect the demographic, participant’s source of information regarding COVID-19, knowledge and believes about COVID-19, the psychological consequences of COVID-19, impact of COVID-19 on participant’s behaviour. The final version of the questionnaire was further tested for content validity by experts in the field.
Results: A total of 2,061 participants completed the survey, with the majority being females (n=1394, 67.6%), from urban areas (n=1896, 92%) and the majority were from countries of The Levant (n=1199, 58.1%), followed by the Arabian Peninsula (n=392, 19.1%), Iraq (n=300, 14.6%) and Egypt (n=138, 6.7%). Few participants (3.0%) reported to have been infected and many (n=1847, 89.6%) were committed to quarantine at home. Social media platforms were the most common sources of information (41.2%). Many (63%) believed that COVID-19 is a biological weapon and were afraid of visiting crowded places (85%). The majority avoided public facilities (86.9%) such as prayer places and believed that the news about COVID-19 made them anxious (49.5%).
Endoscopic Treatment of Calcific Tendinitis of the Gluteus Maximus
Authors: Su Charles A. , Ina Jason G. , Raji Yazdan , Strony John , Philippon Marc J. , Salata Michael J. 
Published: May 2021

Case:
Calcific tendinitis of the gluteus maximus is a rare condition with poorly described operative treatment options. We present a 51-year-old man with chronic left posterolateral hip pain because of gluteus maximus calcific tendinitis that was refractory to conservative treatment. Endoscopy was pursued given the severity and chronicity of his symptoms. The patient remains asymptomatic without recurrence.

Conclusion:
This is the first description of endoscopic management of calcific tendinitis of the gluteus maximus. This is a minimally invasive, efficacious option for management of this pathology.
Successful Hydraulic Isolation Assessment Saves Rig Utilization Time and Unnecessary Cement Remedial Squeeze Operation - Case Study, Kuwait
Authors: Elyas Mohamed , Freile Daniel Agustin , Pawlowski Maciej , Tagarieva Larisa , Elaila Shamseldin Zakrya , Sergeev Evgeny 
Published: May 2021

Abstract
While drilling an 8 1/2-incli section of a north Kuwait producer well, severe mud losses were encountered. Hence, it was decided to design a light weight cement for the 7-inch liner section to avoid further losses while pumping the slurry. The main objective was to achieve a hydraulic isolation to avoid any heavy remedial intervention and potential dump flood behind the liner from the high-pressure Lower Burgan (LB) to Shuaiba.
Full suite of well integrity logs were ran to properly assess whether enough hydraulic isolation was in place. To evaluate the bonding quality of the cement, two independent measurements were carried out across the 7-inch liner with the ultrasonic and sonic bond logs. A subsequent temperature survey was recorded to determine any geothermal anomaly, which could be indicative of fluid movement behind the casing. Finally, oxygen activation stations were conducted based on the cement log and temperature surveys to assure no water movement behind the casing.
The ultrasonic and sonic bond log measurements showed an acceptable bond quality generally. However, the top part of Shuaiba formation up to LB exhibited relatively lower bond quality. The subsequent temperature and oxygen activation logs indicated that the zonal hydraulic isolation was achieved by showing no water movement behind the 7-inch liner. The two complementary surveys helped to take the proper forward decision for this well to go ahead with the planned perforation without cement remedial squeeze, since enough hydraulic isolation was proved to be in place behind the 7-inch liner. Additionally, this saved the rig utilization time and cost by avoiding unnecessary remedial operation. This is usually a heavy-duty operation, which takes time and induces holes in the casing that should be avoided, knowing this type of operation only provides a very marginal gain in terms of isolation. Furthermore, the well is currently producing at 0% water cut after completion.
The proper cement design using light weight cement and optimized casing-landing plan were crucial to achieve good cement placement against formation. The use of the right well integrity approach helped to confirm that effective hydraulic isolation was achieved. Hence all these efforts resulted in the saved rig utilization time and cost by avoiding unnecessary squeeze intervention.
Assessing the Impact of Drilling Tools on Wellbore Quality Using Ultrasonic Borehole Imaging
Authors: Penman Andrew , Wong Siong Ming , Cooper Paul , Fares Wael , Parker Tim , Goraya Yassar , Alfelasi Ali Saeed , Khemissa Hocine , Al Dhafari Bader Mohamed , Khaled Islam , Ashraf Muhammad , Al-Mutwali Omar , Okuzawa Takeru 
Published: May 2021

Abstract
A detailed visualization of borehole size and shape, both while drilling and prior to running casing, completions, or wireline logging equipment, is an essential requirement to minimize non-productive time (NPT) associated with poor borehole quality or wellbore stability issues. The required visualization is made possible using logging-while-drilling (LWD) high-resolution ultrasonic imaging technology, suitable for both water-based mud (WBM) and oil-based mud (OBM) systems.
This paper provides borehole size and shape assessment from field deployments of a 4¾-in. ultrasonic calliper and imaging tool, illustrating the impact on borehole quality of various bottom-hole assembly (BHA) designs, including positive displacement mud motors (PDMs) and rotary steerable systems (RSS). The visualization of borehole quality enables features such as borehole spiralling and enlargement to be assessed and used as input into optimizing completions planning and formation-evaluation programs. In addition, the combination of high-resolution travel-time and reflection-amplitude images enables artefacts induced by drilling equipment, including RSS, to be identified and understood.
High-resolution travel-time and reflection-amplitude images and 3D borehole profile plots are presented from multiple wells, showing how different drilling systems and logging parameters, including drillstring rotation and logging speeds, impact borehole quality. The relationship between the angular bend in the PDM and the impact it has on borehole spiralling is discussed.
The LWD logs presented illustrate the factors that influence borehole quality and the methodology used to ensure that high-resolution images are available in both vertical and high-inclination wellbores, leading to the ability to reduce the NPT associated with wellbore stability issues. The observation and assessment of drilling artefacts and irregular borehole size and shape act as inputs into optimizing completion and logging programs, evaluating the optimal placement of packers and other completion equipment, and the design of the drill bit and BHA.
The ability to collect high-resolution travel-time and reflection-amplitude ultrasonic images in both WBM and OBM, in wellbores ranging from 5¾ to 7¼-in., leads to significant improvements in the understanding of wellbore quality. Borehole size and shape can now be visualized in real time in either water or oil-based drilling fluids at a resolution capable of identifying all significant drilling-induced geometric artifacts. This allows the adjustment of drilling parameters to minimize NPT associated with common drilling hazards, the optimization of completion programs and wireline logging programs.
Effect of Drilling Fluid Temperature on Formation Fracture Pressure Gradient
Authors: Samak Ahmed Mostafa , Elsayed Abdelalim Hashem 
Published: May 2021

Abstract
During drilling oil, gas, or geothermal wells, the temperature difference between the formation and the drilling fluid will cause a temperature change around the borehole, which will influence the wellbore stresses. This effect on the stresses tends to cause wellbore instability in high temperature formations, which may lead to some problems such as formation break down, loss of circulation, and untrue kick.
In this research, a numerical model is presented to simulate downhole temperature changes during circulation then simulate its effect on fracture pressure gradient based on thermo-poro-elasticity theory. This paper also describes an incident occurred during drilling a well in Gulf of Suez and the observations made during this incident. It also gives an analysis of these observations which led to a reasonable explanation of the cause of this incident.
This paper shows that the fracture pressure decreases as the temperature of wellbore decreases, and vice versa. The research results could help in determining the suitable drilling fluid density in high-temperature wells. It also could help in understanding loss and gain phenomena in HT wells which may happen due to thermal effect.
The thermal effect should be taken into consideration while preparing wellbore stability studies and choosing mud weight of deep wells, HPHT wells, deep water wells, or wells with depleted zones at high depths because cooling effect reduces the wellbore stresses and effective FG. Understanding and controlling cooling effect could help in controlling the reduction in effective FG and so avoid lost circulation and additional unnecessary casing points.
Pore Pressure Prediction in Sandstone Using a Lateral Transfer Approach
Authors: Consuegra Jose Francisco 
Published: May 2021

Abstract
Accurate pore pressure prediction is required to determine reliable static mud weights and circulating pressures, necessary to mitigate the risk of influx, blowouts and borehole instability. To accurately estimate the pore pressure, the over-pressure mechanism has to be identified with respect to the geological environment. One of the most widely used methods for pore pressure prediction is based on Normal Compaction Trend Analysis, where the difference between a ‘normal trend' and log value of a porosity indicator log such as sonic or resistivity is used to estimate the pore pressure. This method is biased towards shales, which typically exhibit a strong relationship between porosity and depth. Overpressure in non-shale formations has to be estimated using a different method to avoid errors while predicting the pore pressure.
In this study, a different method for pore pressure prediction has been performed by using the lateral transfer approach. Many offset wells were used to predict the pore pressure. Lateral transfer in the sand body was identified as the mechanism for overpressure. This form of overpressure cannot be identified by well logs, which makes the pore pressure prediction more complex. Building a 2D geomechanical model, using seismic data as an input and following an analysis methodology that considered three type of formation fluids - gas, oil and water in the sand body, all pore pressure gradients related to lateral transfer for the respective fluids were evaluated. This methodology was applied to a conventional reservoir in a field in Colombia and was helpful to select the appropriate mud weight and circulating pressure to mitigate drilling risks associated to this mechanism of overpressure. Seismic data was critical to identifying this type of overpressure mechanism and was one of the main inputs for building the geomechanical earth model.
This methodology enables drilling engineers and geoscientists to confidently predict, assess and mitigate the risks posed by overpressure in non-shale formations where lateral transfer is the driving mechanism of overpressure. This will ensure a robust well plan and minimize drilling/well control hazards associated with this mode of overpressure.
Chemically-Induced Pressure Pulse: Fracturing Competent Reservoirs
Authors: Al-Nakhli Ayman R. , Tariq Zeeshan , Mahmoud Mohamed , Abdulraheem Abdulazeez 
Published: May 2021

Abstract
Commercial volumes of hydrocarbon production from tight unconventional reservoirs need massive hydraulic fracturing operations. Tight unconventional formations are typically located inside deep and over-pressured formations where the rock fracture pressure with slickwater becomes so high because of huge in situ stresses. Therefore, several lost potentials and failures were recorded because of high pumping pressure requirements and reservoir tightness. In this study, thermochemical fluids are introduced as a replacement for slickwater. These thermochemical fluids are capable of reducing the rock fracture pressure by generating micro-cracks and tiny fractures along with the main hydraulic fractures. Thermochemical upon reaction can generate heat and pressure simultaneously. In this study, several hydraulic fracturing experiments in the laboratory on different synthetic cement samples blocks were carried out. Cement blocks were made up of several combinations of cement and sand ratios to simulate real rock scenarios. Results showed that fracturing with thermochemical fluids can reduce the breakdown pressure of the cement blocks by 30%, while applied pressure was reduced up to 88%, when using thermochemical fluid, compared to slickwater.
In basins with excessive tectonic stresses, the current invention can become an enabler to fracture and stimulate well stages which otherwise left untreated. A new methodology is developed to lower the breakdown pressure of such reservoirs, and enable fracturing.
Keywords: Unconventional formation; breakdown pressure; thermochemicals; micro fractures.
Anti-Collision Study for the Wells from New Artificial Islands Across Gigantic Mature Oil Field in Middle East Area
Authors: Fujinaga Ryota , Alzaabi Mohamed Abdulrahman , Toki Takahiro , Toma Motohiro , Andrews Kerron Kerman 
Published: May 2021

Abstract
107 new wells are planned to be drilled primarily from two new Artificial Islands during the period of one project from 2023 to 2029. The number of existing wells in the oil field has reached 1,068 Mother bores, 2,178 wellbores @16,453,666ft total well length as of December 2019. Trajectories, especially from existing Artificial Islands, are getting more complex so as to avoid collision issues, and it is becoming increasingly difficult to drill accordingly. It is of great importance to assure that it is possible to drill the planned wells without serious collision issues before the execution of the project.
Trajectories for planned wells were drafted one-by-one utilizing "DecisionSpace Well Planning" based on the predetermined slot allocation with the planned drilling pad design. Geological models are incorporated into DecisionSpace Well Planning. Therefore, formation tops were taken into account in order to make the trajectories more realistic. After that, trajectories were exported to "COMPASS" and anti-collision scan was performed on well-by-well basis. Anti-collision scan was performed among planned wells as well as actual wells. In case that one well has such serious collision issues that the well cannot/should not be planned based on company policy as a result of Anti-collision scan, trajectory or Landing Point (LP)/Total Depth (TD) location were adjusted. Then, Anti-collision scan was carried out again. If it was confirmed that there is no serious Anti-collision issues, trajectory was considered as final.
It has been found that all the wells during the period from 2023 to 2029 can be drilled without serious collision issues by slightly adjusting LP/TD while satisfying several practical drilling requirements.
Through the Anti-collision study, following recommendations for the avoidance of collision were obtained:Multi Station Analysis (MSA)+In-Field Referencing (IFR)+SAG correction should be applied in all the Jack up operations as well as Island operationsApplication of real-time MSA should be considered on a case-by-case basisMWD survey for the past wells should be corrected with IFR+MSA to reduce EOU sizeRe-Gyro jobs for low-quality survey wells should be enhanced around the project's development areaKick off point (KOP) should be deeper in the center of the drilling pad and shallower in the edge of the drilling pad
Successful Implementation Of Geomechanics In Deep Water Setting: A Case Study From KG Offshore, India
Authors: Bhimpalli Sarah , Shinde Ashok , Rao Bayye L , Perumalla Satya , Panchakarla Anjana , Chakrabarti Prajit , Saha Sankhajit 
Published: May 2021

Abstract
Geomechanics has an important role in assessing formation integrity during well construction and completion. It also has its effect when the wellbore is in production mode. Geomechanical study evaluate the impact of the present day in-situ stress and related mechanical processes on reservoir management. The study field ‘K' belongs to Plio-Pleistocene sequence of deep-water environment with hydrocarbon prospects. This belongs to Post-Rift tectonic stage of evolution with hydrocarbon occurring in structurally controlled traps. As a part of exploration activity, four offset oil wells were drilled earlier which were considered for the geomechanical model construction. Field (K) development plan comprising of six hydrocarbon producers and four water injectors was prepared.
Considering the thick water column (300m-650m) in this deep water area of offshore and young unconsolidated sedimentary sequence in the sub-surface, expected pore-pressures can be high whereas the fracture gradient can be low. As a result, the safe drilling mud window can be narrow. Upon successful drilling of a well in such challenging environment without NPT (Non-Productive time), completing the well with best possible technologies suitable to the reservoir's mechanical behavior is utmost important for maximizing the production and minimizing the risk. To mitigate these problems in developing this field, an integrated reservoir geomechanics approach is adopted to optimize the drilling plan and reservoir completion parameters for the planned well. This paper covers the geomechanical study of four wells namely W, X, Y & Z drilled in the field ‘K'. The principal constituents of the geomechanical model are in-situ stresses, pore pressure and the rock mechanical properties.
Geomechanical model for the field ‘K' was built utilizing the available data by integrating drilling, geology, petrophysics and reservoir data. Methodology adopted in this paper also highlights how a reliable geomechanical model can be built for a field, which is having data constraints. Constraining of stress magnitudes, orientation and anisotropy added value for efficient well planning in deep waters reservoirs. Calculating well specific reservoir rock mechanical properties, it made possible to identify the most optimal completion strategy. Approach contributed knowledge of geomechanical parameters based on the data of four offset wells has been used for successfully drilling and completion of all the subsequent wells without major challenges. Overall, geomechanical modeling has played a major role in drillability and deliverability of the reservoir. Integrated approach adopted in this paper can be used for well planning and drilling of future wells in East Coast of India with similar geological set up.
No Tag to Hard Tag - Case History About Effective Cement Plug Placement Techniques
Authors: Prabhu Pratik , Abad Juan Miguel 
Published: May 2021

Abstract
The success or failure of cement plugs are known to alter the timeline of an oil well; not to mention the additional costs and NPT associated with the rig activities. Unsuccessful cement plug costs oil companies considerable amount of capital both in extra rig time and service company expenses. Suggested procedures for placing cement plugs have been presented in number of papers - comprising of slurry design, spacer recommendations, laboratory testing and placement techniques. However, it is very easy to deviate from these standard practices due to over confidence, negligence or both.
In Mexico, it was observed that the success rate of placing cement plugs dropped due to operational and engineering design shortcomings. Towards the end of 2018 there were several unsuccessful cement plug jobs that questioned the regular plug procedures. Careful analysis of the past mistakes led to the conclusion that an effective approach to alter the local plug placement practices was necessary.
An updated cement plug placement software was used in conjunction with strict standard practices that turned around the trend and enabled consistent successful placement of cement plugs in the first attempt itself. A detailed yet simple approach towards cement plugs was adopted in both engineering design and operational execution. Additionally the updated plug placement software ensured accurate prediction of the cement plug top; that was confirmed by the actual tag of the plug.
This paper will enlist the major analysis carried out on the unsuccessful plug jobs and highlight the different techniques that were adopted in the subsequent jobs to ensure successful placement and tagging of the cement plug. The paper will also focus on how the plug placement software's new additional features have made a significant contribution to this success story.
Machine Learning as New Approach for Dogleg Severity Prediction
Authors: Fakhrylgayanov Ayrat , Soh Azrin Aik Jun , Osman Ahmed 
Published: May 2021

Abstract
Conventionally offset well studies are performed by individuals where the results depend very much on visual perception, interpretation, and experience. In the specific cases for predicting the dogleg severity (DLS) output, the offset well study will take time proportionate to the volume of input, with the results being averaged out and contain high tolerances. In specific projects, these tolerances are larger than accepted, encouraging the service provider to utilize conservative solutions such as rotary steerable system (RSS) with high DLS capability in order to reduce the residual risks. These solutions can often be more costly in terms of maintenance and may add unnecessary tortuosity to the hole leading to issues during execution. This paper explores the concept of using machine learning (ML) to perform offset well study and defining key parameters affecting the DLS output. This concept consolidates the vast volumes of data that have been acquired while drilling and defines the relationship of each parameter to the final output of DLS.
The first analysis reviewed five offset wells and found a multivariable correlation between applied drilling parameters to the DLS output. This correlation was then applied in 6 boreholes (3 multilateral wells), observing consistent DLS output increase by 50% using the same technology and optimal drilling parameters. The second analysis uses the same process to determine a planning DLS limit in a curve section over different formations.
This paper demonstrates the potential of ML in offset well studies and beyond to predict behavior and define the relationship in a big data environment.