bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advanced Prediction of Sand Production Onset Using Data Analysis and Machine Learning Techniques: Insights from Adriatic Sea Gas Wells
Authors: Nguyen S. , Gabry M. Adel , Soliman M. Y. , Myers M. , Ayman A. 
Published: October 2024

Abstract
This study revisits the field observations of sand production of gas wells in the Adriatic Sea to develop comprehensive correlations of key parameters and identify the most critical factors influencing the onset of sand production. The primary objective is to leverage profound data analysis and machine learning (ML) techniques to boost predictive consistency and provide actionable insights for sand-free production practices.
The research employs a two-pronged approach. First, a detailed data analysis is conducted, featuring vivid cross plots to illustrate relationships between cohesion strength and various parameters such as depth, interval transit time, cohesion strength, original static reservoir pressure, effective overburden stress, depleted pressure, total drawdown pressure, perforation interval, shot per foot, and produced gas and water rates. Second, the study applies ML models, including Gradient Boosting (GB), XGBoost (XGB), Random Forest (RF), CatBoost (CATB), and Support Vector Machine (SVM), to categorize data and identify the most critical features impacting sand production onset. SMOTE is utilized to rectify class imbalance, and GridSearchCV optimizes model parameters. Additionally, LOOCV is employed for rigorous model evaluation. SHAP analysis further interprets the model results.
The cross plots reveal significant relationships between cohesion strength and other essential metrics, providing thorough knowledge of their interactions. In the ML classification phase, the GB model achieves a perfect accuracy of 1.0, significantly outperforming XGB (0.86), RF (0.71), and CATB and SVM (both 0.57). The GB, XGB, and RF models identify critical features such as interval transit time, cohesion strength, and water production as major influencers on the onset of produced sand. SHAP analysis further elucidates the contribution of these features, offering interpretable insights into their importance. The findings suggest that ML models, particularly GB, can effectively predict sand dislodgement, thus aiding in developing sand production preventive strategies.
This paper introduces an alternative application of ML techniques to foresee sand production onset, an essential challenge in oil and gas well management. The study provides new insights and enhances predictive accuracy by integrating extensive data categorization with advanced classification models. The use of LOOCV ensures rigorous model evaluation, and SHAP analysis for model interpretation offers a transparent understanding of feature importance, making the findings highly valuable for sand control approaches. This research contributes additive information to the existing literature, emphasizing the potential of data-driven approaches in improving operational decisions in long-term production.
Integrated Reservoir Evaluation and Simulation Study of the Northeast Alamein Field: A Field Case Study
Authors: Ubani Ephraim , Shahsavari Darius , Duruewuru Lester 
Published: October 2024

Abstract
The Northeast Alamein (NEAL) field, discovered in August 2010 with the drilling of NEAL-1X well, is an integral part of the Yidma-Alamein concession in the Western Desert of Egypt and is located about 3 km to the northeast direction from the Alamein oil field. Eighteen wells, a mix of vertical and horizontal, have been drilled in the field. The NEAL field is one of the primary oil producers of the concession and of the estimated 42.7 MMSTB of OOIP, the current recovery factor is about 12.0 percent. The objective of the study of the NEAL field was to develop a better understanding of the field comprising seven main complex reservoir members (A/R "E" sands, Upper A/R "G", A/R "G" Dolomite, Upper Bahariya, Middle Bahariya, Basal Middle Bahariya and Razzak sands), assess the production pattern of each reservoir and recommend an optimum production plan based on the ultimate oil recovery and economics.
The study involved the reservoir characterization of the reservoirs, which spanned seismic evaluation, petrophysical evaluation, facies modeling, and stochastic reservoir parameter distribution, culminating in static model development. All available engineering and production data were integrated with the static model to develop a representative model of the NEAL reservoirs, which were applied to derive future development plans.
The Upper A/R "G" and A/R "G" Dolomite reservoirs are most probably deposited in shallow marine from outer subtidal to intertidal zone, while the tidal flat depositional setting is proposed for the Bahariya and the Razzak units. Recommended optimum production plan involved a combination of infill drilling, well recompletions, pump optimization, and water injection.
The results of implementation of recommendations exhibit success in terms of additional reserves, of about 2.0 MMSTBO, and doubling production rate from the NEAL field. Lead tasks for water injection were completed with drilling of two water source wells and conversion of two wells for water injection. Water injection started in one of the wells on August 7, 2024. The offset producers are being monitored.
Integrated reservoir study in support of reservoir management of a mature field has led to successful drilling, recompletion, artificial lift optimization and other workover campaigns, which have yielded significant production optimization and reserves addition, as well as expected good performance of a waterflood project.
Maximizing Profitability through Automated Production Optimization: A Game-Changer for Digital Oil Field Operations in Kuwait Integrated Digital Field
Authors: Al-Rashidi H. , Singh Sahil 
Published: October 2024

Summary
The paper outlines a digital transformation of a business process called production optimization, which traditionally an approach of identifying wells in the asset as candidates for choke or artificial lift parameter change. Optimization takes into consideration reservoir guidelines and well and facility constraints. The business process impact multiple teams that are involved in order to increase or optimize well production for over 2000 producers on daily basis. The paper focuses on the automation of engineering workflows, reporting, and decision making, ticketing and tracking of each opportunity through KwIDF platform. It introduces model based approach in decisions making related to choke change, artificial lift optimization or rerouting of the wells, which was not traditionally followed while identifying optimization opportunity on daily basis. In the end all the action and decision related to each opportunity are recorded which can be utilized to provide feedback thereby improving effectiveness and efficiency of the workflows and business process in the future.
Multiple engineering workflows involved in the business process start from updating or creating well models automatically after new drill, workovers or rig-less activity. An automated well-model management system ensures data accuracy, transformation of the data and timeliness by fetching information from the production database. Another workflow updates well performance for each wells automatically based on the multi-rate well test data. In the end optimization workflow utilizes well models and identifies opportunities for improving well production or running ESP pump optimally based on artificial lift, well, reservoir and facility limits and constraints. This automated approach enhances the identification of valid optimization opportunities and facilitates well performance management, leading to significant oil production gains and informed decision-making within the field.
Evaluation of CO2 Storage Capacity Potentiality as a Secondary Driving Mechanism in Enhanced Oil Recovery in East Bahariya Field, Bahariya Concession, Western Desert, Egypt
Authors: Dahman Ahmed , Mohamd Hazem , El-Rahman Reda Abd , Ataallah Mohamed Abdelwahab 
Published: October 2024

Abstract
Egypt formulated its sustainable development strategy "Egypt Vision 2030" in 2015. This strategy aims to protect the environment in the development process by integrating environmental aspects into economic and social development plans to manage natural resources, conserve natural capital, and develop to protect the environmental rights of future generations. According to the IEA (International Energy Agency) CO2 emission reduction projects to track advances in carbon capture, utilization, storage as well as use of naturally occurring CO2 for EOR (Enhanced Oil Recovery) of depleted reservoirs. This paper proposes a methodology for evaluating underground CO2 storage capacity according to the facies of different formations applicable to the CO2 EOR projects. The methods proposed in this document will not only help third parties create reports and inventories of greenhouse gas emissions from companies, but also help governments to encourage companies to reduce their CO2 emissions. It would be beneficial for the industry implementing CCUS (Carbo Capture Utilize and Storage) projects to provide key evaluation parameters and implement the necessary monitoring techniques. Due to advantages and vast resource capacity, onshore CO2 storage provides an attractive option.
Bahariya concession is located at the eastern trough of Abu Gharadig basin, Western Desert, Egypt. By Using the available data, a subsurface geologic evaluation and 3D modelling was carried out in terms of thickness variation, lithofacies, structural setting and depositional environment of the studied rock unit in the encountered basin. This study presents both depleted reservoir and shallow non-reservoir formations as preliminary targets for CO2 storage potential.
It was concluded that both clastic and non-clastic Cretaceous formations have a high-quality potential geological reservoir repository for CO2 storage capacity.
Re-Access Oil Reserves of Watered Out Shut-In Well in Mature Field; Case Study in the Gulf of Suez
Authors: Falamouny Peter M. , Ibrahim Ahmad , Salah Muhammed , El-Sheikh Mahmoud , Khalil Ahmed , Ayyad Abdelhadi 
Published: October 2024

Abstract
Hilal field is a mature brown field in Gulf of Suez. The field was discovered in 1982 and started production in July 1984 from five reservoirs. The platform was damaged due to ship collision shut down in 2007. A new platform was installed and restarted production in 2014. This paper showed the integrated dynamic and static study conducted to define and restore the remaining reserves of old P&A watered out producer.
The study included reviewing wells/ reservoir production and pressure performance and all saturation and production logs to monitor water movement across the field and compare wells production performance in different reservoir compartments. New structure maps were built based on new seismic and geological interpretation and to match the dynamic information got the study. Review of the completion fluid during workovers was done to judge its effect on wells production performance. Water oil ration versus cumulative oil production curve was studied for all Nubia reservoir to define the general WOR trend and define remaining reserves of old wells.
Wells production performance and production logs showed that despite being in down dip location, WELL-5 was the only well Nubia reservoir producer when old platform was, while up dip wells were completely watered out. Structure map was updated based on information and new fault was added to isolate Well-5 block. Focusing on Well-5 as possible oil potential location, the well was completed as Nubia producer in 1985 became a commingle producer from Nubia and Nukhul S. St in 2000. The well was producing with 85% WC when P&A. Production logs run in 2002 showed that Nukhul was producing with 90% water cut and 60% of liquid rates. Well workovers history showed that Nubia reservoir was damaged due to completion fluid during workover in 1994 and productivity was decreased. This justifies the domination of Nukhul S. St on Nubia. WOR versus cum oil curves suggested that Hilal-A5 was producing 60-70 % WC from Nubia when the well was P&A and Nukhul S. St was watered out. Based on the study, Hilal-B6 well was drilled targeting Well-5 location. The well penetrated +250 ft oil column in Nubia. By selective perforation, the well started production with traces water cut from Nubia.
This paper showed the value of detailed integrated dynamic and static study. It showed workflow of studying the re-development of mature fields and finding sweet spot that can raise the field production.
Enhancing Oil Production Through Inclusive ESP Solutions
Authors: Alfaitouri I. , Awedan H. , EL-Dalim M. , Bosnina S. A. , AlKyarie S. 
Published: October 2024

Abstract
This paper introduces and evaluates the effectiveness of a comprehensive upgrade to the electrical submersible pump (ESP) systems implemented in Libya's Waha oil field, the country's most mature and giant oil field. This upgrade integrates advanced technologies across both downhole and surface components of the ESP systems, incorporating the latest digital ESP solutions tailored to meet customer operational requirements.
The paper details how this extensive enhancement in ESP design has significantly improved system efficiency and performance. By modernizing conventional ESP setups. The upgrade addressed the limitations of outdated ESP systems, enhanced ESP monitoring capabilities, and significantly boosted oil production in Waha field.
Success Story: Improving CBL Quality in Loss Circulation Conditions Using Low-Solids-Shear Dependent Cement System
Authors: Rachman Ryan Pratama , _ Sulistyo , Syarif Mustafa , Anuraga Edo , Daroni Afwan , Adrian Nur Alam Rifqi , Martin Ranti , Delgado Francisco 
Published: October 2024

Abstract
An operator onshore Indonesia performed a remedial squeeze cement operation to help improve the quality of the cement bond based on cement bond log (CBL) results. The 4.5-in. production casing, perforated between 1850 and 1852 m measured depth (MD), showed well instability with static losses at 0.7 bbl/min and dynamic losses at 1 to 1.18 bbl/min with minimum flow rates up to 3 bbl/min. Four conventional cement slurry squeeze operations failed to yield positive results in addressing the losses because all the cement was lost to the formation behind the casing no cement was tagged inside the casing across the perforated interval.
A low-solids-shear dependent (LSSD) cement system with a density of 11 lbm/gal was considered to address the challenge. This cement system reduced hydrostatic pressure above the loss zone and had tailored characteristics of early development of static gel strength. The 40-bbl treatment was pumped through an open-ended drillpipe (OEDP), with the annulus closed above the loss zone. Initially, 10 bbl were pumped to the formation, 30 bbl remained inside the casing, and 15 bbl were then squeezed behind the perforated interval using the hesitation squeeze method, followed by an eight-hour wait on cement (WOC).
After the completion of WOC, the well remained static, and cement was tagged 104 m above the perforated zone. No further static or dynamic losses occurred after the cement was drilled. A successful pressure test up to 1,000 psi was performed. The repeat CBL showed improved zonal isolation and a competent barrier between the zone of interest and the water zone, which enabled the operator to proceed with the completion program without any additional treatments.
The application of the LSSD cement system resolved losses on the first attempt, while four conventional cement slurry operations failed. Additionally, the LSSD cement system improved cement bond quality behind the production casing, which achieved the CBL result necessary for the operator to proceed with the well completion program.
Advanced Drilling Strategies and Zonal Isolation Techniques for High Temperature, High Pressure Wells, A Case Study
Authors: Presniakov Mikhail , De Souza Giovana , Lujan Juan Rodrigo , Barrera Edison , Ivanov Roman , Nunez Andres 
Published: October 2024

Abstract
This case study outlines the successful risk management through engineering in Mesozoic reservoir. The subject well is a High-Pressure High Temperature (HPHT) extended reach S-Shape. The primary objective of this paper is to detail the strategy applied to ensure well integrity, effective zonal isolation, and operational efficiency while mitigating risks associated with mud losses and crossflows. Scope will cover efficient isolation using a 5-in. liner × 6-1/8-in. open hole with a custom swellable packer; Validation the use of Managed Pressure Drilling (MPD) techniques and two-phase flow systems; minimization non-productive time (NPT) and operational costs.
Risk management strategy starts through offset wells analysis. General well design is affected by the presence of a series of folds and faults, as well as salt domes without a predetermined orientation. Therefore, the existence of significant uncertainty in pore pressure prediction. A safe execution depends on real time follow up through dynamic simulations and managed pressure drilling with advanced intelligent chokes. Whenever the combination of late and early Jurassic was confirmed, contingency scenario needs to be activated. This involves custom cement job in reduced annular clearance of 5-in. × 6-1/8-in. with fit for purpose packer and cement system. And finally, to explore the early Jurassic reservoir at depths from 7,400 m to 7,500 m true vertical depth (TVD) safe execution depends on managed pressure drilling (MPD) with continuous nitrogen injection and real time parameters correlation with dynamic simulations for drilling 4-1/8-in. section.
This strategy yielded several positive results. Good identification of the geo-body position through controlled influx management within 1.75 to 1.81 gr/cc using MPD equipment. Successful zonal isolation, through selection and deployment of a cement system and a swellable packer activated by oil-based mud, designed to operate up to 191 degrees Celsius (°C) and withstand differential pressure up to 10,000 psi. The well integrity was confirmed through negative test and further in production phase. The reservoir was successfully explored with minimal reservoir damage possible in subject conditions through the use of at balance two-phase flow to manage mud losses and maintain well control. Although at first, such target depths and high-pressure nature of the field may seem to be intimidating, the successful risk management and timely intervention to activate contingency has proven successful. The well achieved the planned technical limit time of 131 days, demonstrating this strategy's efficiency.
Rejuvenating Mature Field Production Through Optimized Artificial Lifting Methods
Authors: Mousa A. A. , Abdelazim A. , Youssef F. , Elkody M. , Farag N. 
Published: October 2024

Abstract
Marina oil production Company aiming to enhance oil recovery factor, which represents percentage of economically recoverable original oil in place by changing the artificial lift technology in the Sidi Rahman brownfield. Improving the recovery factor help increase the field's overall production and extend its productive life.
The Company has established a technical team consists of members from different disciplines. The team conducted a comprehensive study, re-evaluated the reservoir characteristics, original oil in place and remaining reserves in each reservoir sand, to maximize the recovery factor. To increase oil production, reduce operating costs, and evaluate new infill drilling opportunities. The main challenges that the wells encounter Multilayer reservoirs and the existing artificial lift system (Sucker Rod Pump) cannot establish higher draw down in high productivity index reservoirs due to the limitation of downhole pump size (through tubing pump, not bigger than 2.25") to allow zones with different reservoir pressure to contribute its production, despite the fluid level is near by the surface. Hence, it is decided to replace the existing Artificial lift method by an electrical submersible pump (ESP), to create a higher drawdown and increase production rate.
A work over campaign was successfully executed and converted the two sucker pump wells to produce by electrical submersible pumps. The results of ESP installation and commissioning were amazing and indicated a significant increase in Marina Company production from 130 to 1000 BOPD. Oil production increasing approximately by 660 % from company production prior the workover campaign, in addition to a significant decrease in operating cost from approximately 38 to 15 USD / bbl. oil through first year of implementation.
The new artificial lift method (ESP), successes in enhancing contribution from multiple zones with different reservoir pressures and contributed in increasing the recovery factor by 7 % during this period.
Evaluation of Waterflooding Project Technical Viability in a Clastic Sandstone Reservoir: A Case Study in Western Desert, Egypt
Authors: Anwer E. , Rizk A. S. , Muaz A. , Abdelfadil M. 
Published: October 2024

Abstract
Waterflooding is a widely used and well-established secondary recovery technique that has been thoroughly studied over the last decades across the literature. However, the practical implementation of this technique in the field still raises many lessons to be learned. The objective of this paper is to present a detailed implementation framework that was developed for a waterflooding project in the western desert, Egypt. In addition, the paper emphasizes the major challenges faced during the implementation of the project and the proposed solutions. The considered reservoir is a sandstone characterized by moderate porosity/permeability values and underlain by a weak to moderate aquifer drive. The reservoir pressure and production rate declined severely from 2400 psi and 1000 BOPD to 600 psi and 400 BOPD, respectively, after production of only 260 MSTB. In addition, decline curve analysis (DCA) yielded a base case with very low recovery factor (10%). Accordingly, waterflooding project was implemented as a secondary recovery mechanism in order to support the reservoir pressure and improve the sweep efficiency. The original oil in place (OOIP) was evaluated using volumetric calculations and validated using rate-transient analysis (RTA)to be around 7 MMBO at the early production phase of the field and using material balance equation (MBE) later on. The results of the established framework yielded to the drilling of 12 new wells (8 producers and 4 injectors) to follow a combination of seven-spot and peripheral flood patterns, keeping into consideration an optimum voidage replacement ratio (VRR). This plan resulted in a significant enhancement of reservoir performance. Within just two months, the reservoir pressure increased by ±1000 psi, and production exceeded the pre-project rates by 4000 BOPD. Consequently, the expected recovery factor is anticipated to rise dramatically from 10% to 35% (incremental gain around 1.8 MMBO). For sandstone black oil reservoirs, following this framework will form a reference to evaluate any future waterflood projects. This reflects that integration between reservoir characterization and analytical engineering tools is powerful approach to achieve optimum field development plan which in turn reflects on the NPV of the project.