bluuebunny/crossref_metadata_2025_split huggingface dataset:
Challenges Overcome and Lessons Learned: Knowledge Acumens from Drilling Geothermal Wells in Turkey
Authors: Birinci S. B. , Merey M. G. , Buyukekinci O. , Bukhamseen R. 
Published: November 2024

Abstract
This paper provides an overview of the extensive geothermal drilling activities in Turkey. Based on the large-scale data obtained in Turkey, the study identifies and classifies the challenges and risks that have been faced during drilling according to the risk severity and repetition frequency. The main challenges that have been encountered can be grouped into several categories: formation/lithology, equipment requirements, excessive vibration levels, and high temperature. Due to the fractured nature of the metamorphic formations, partial or full losses have been faced frequently, which increases the possibility of stuck pipe issues. Directional control and the hole geometry are frequently affected by the strong formation dips, requiring extensive directional planning and detailed offset well analysis. Moreover, since the stratigraphy is interbedded with heterogeneous and hard formations that act like a "stinger", the bit choice and drilling parameter evaluation possess extra caution and necessitate point-by-point analysis. In addition, these formations are severely abrasive and require a high level of tool quality, especially coating-wise. Downhole drilling temperatures up to 180 degrees Celsius require service companies to utilize more durable seals, sensors, and materials. Extreme levels of vibrations and shocks above 100G may be faced during drilling, causing a lower rate of penetration. Results show that extensive off-set well analysis, utilization of vibration mitigation tools, cooling procedures, proper bit and directional equipment selection, and certain stuck pipe practices may minimize the risks involved while drilling geothermal wells, especially in metamorphic rocks.
Smart Alarm Management Framework for Gas Condensate Field Surveillance and Production Optimization
Authors: Alsaeedi Ayesha , Alhammadi Maryam , Alhammadi Rashed , Albadi Mohamed , Alzeyoudi Mohamed , Alharethi Fahed , Konkati Sarath , Jani Mansi , Siddiqui Sameer 
Published: November 2024

Abstract
With the industry’s drive to move toward smart field implementation, data-driven surveillance and monitoring have become the need of the hour. Especially, for large matured and depleting reservoirs with well deliverability sensitive and deteriorates rapidly. This paper elaborates on the smart alarm management system to make surveillance and monitoring more efficient to overcome suboptimal production and well downtime reduction.
To support the critical and tedious daily task of surveillance and monitoring wells for large, depleted fields, a smart alarm management system was created within the Integrated Asset Operation Model (IAOM) solution. The alarm management was implemented in three different categories, such as
Category-1 (Real-time alarm): These alarms are based on the real-time parameters from the field sensors (via real-time data source). Category-2 (Setpoint alarm): These alarms are based on the well’s operating point parameters. Category-3 (Custom intelligent alarm): These are user-defined alarms that are created in the conjugation of measured and physics-based tuned models.
The smart alarm management system facilitated efficiently and proactively the identification of the wells with suboptimal well performance either due to external factors (facility bottlenecks) or due to well deliverability deterioration. The alarm management system was able to highlight the wells for different categories.
Category-1 (Real-time alarm): Identified wells with small delta pressure across the choke suffering from high backpressure. Category-2 (Setpoint alarm): Identified wells with a large deviation between estimated volumes and the measured daily production volume. Thus, identifying the instrumentation issue in the field. Category-3 (Custom intelligent alarm): Identification of the wells with suboptimal well deliverability as the well was suffering from liquid loading
The alarm management system on a daily basis sends an email notification to all the stakeholders with a summary of the alarm wells along with the brief details of the alarm. Advanced dashboards report provided systematic information, and guide users' engineering judgment to take preventive decisions.
Advanced action tracking (operation management system) was utilized to plan and execute the remedial action. Well’s downtime time was reduced, and significant production improvements were observed for these wells, thereby leading to a tangible reduction in cost and time.
Using the smart alarm management system under the IAOM provides tools to identify wells that are currently demonstrating sub-optimal well performance and might even cause cease to flow conditions. Thus, utilizing the integrated framework in taking a proactive remedial reduces loss in production and also acts as a guideline while optimizing the gas production.
First Multilateral Well Drilled in Under Balanced Manner within ADNOC Group with Successful Trials Of UBCTD
Authors: Zain Fawad , Deshmukh Rohit V. , Almteiri Nama , Baslaib Mohamed Ahmed , Osama Mohamed , Mantilla Alfonso , Solaiman Tarek , Alzeyoudi Mona , Jayeoula Abiodun , Elshehat Ayman , Abdulsalam Fouad , Mengal Salman , Alshehhi Hajar 
Published: November 2024

Abstract

Objectives/Scope
Exploring the frontiers of exploration, ADNOC Onshore's ASR Team has pioneered the use of Underbalanced Coiled Tubing Drilling (UBCTD) within the entirety of the ADNOC Group, further extending its application to a multilateral well. This technique reduces reservoir impairment resulting from overbalanced drilling conditions and employs coiled tubing instead of a traditional drill rig. The operation realized a remarkable total drilled footage of 11,422 ft, overcoming the technical and safety challenges associated with drilling in an environment containing sour gas with a concentration of 6% H2S.

Methods, Procedures, Process
The initiative involved exploiting the UBCTD approach for tapping into sour gas deposits, a first for any ADNOC entity. A multitude of stages such as selecting appropriate sites, intricate engineering planning, optimizing well designs, comprehensive risk assessments, the tendering process, recruitment of services, standard drilling operations, connections, and finally, CT drilling took place. The adoption of UBCTD facilitated a safer and more efficient drilling method, allowing for continuous production testing and directional steering while drilling. By creating triple lateral wells, the project not only enhanced reservoir exposure but also cemented UBCTD's efficacy compared to other examined technologies on these specific gas reservoirs.

Results, Observations, Conclusions
ADNOC, a dominant force in energy resources, adopted the UBCTD method to access reservoir sections without most conventional logging tools. This innovative drilling technique offers several benefits including reducing formation damage, enhancing well productivity and recovery rates, achieving ideal drainage lengths, decreasing completion times, and elevating net present value. Despite initial apprehensions owing to inexperience and perceived risks, the inaugural implementation of UBCTD within the ADNOC conglomerate signifies a leap forward, particularly for re-entry and new sour gas wells where traditional underbalanced drilling is constrained. Notably, UBCTD is gaining global acceptance for its efficiency in both new wells and revisiting existing ones with the goal of maximum resource extraction.

Novel/Additive Information
The document will delineate a comprehensive procedure used in orchestrating the unique Multilateral CTUBD venture for ADNOC Group, highlighting operational and HSE factors that contributed substantially to the accomplishment of this groundbreaking project.
Habshan Seismic Stratigraphy Framework to Reveal Stratigraphic Play Potential in Southeast Abu Dhabi, UAE
Authors: Kim Dongoh , Yoo Seunghak , Di Simone Salvatore 
Published: November 2024

Abstract
The Lower Cretaceous (Berriasian to Valanginian) of Southeast Abu Dhabi, U.A.E. consists of a large carbonate platform system and the Habshan Formation is a major carbonate reservoir in the region, hosting significant hydrocarbon potential with more than 1,000 feet in reservoir thickness. The progressive nature and clinoform structures have been highlighted through many vintages of seismic imaging and previous stratigraphic studies. This underlines the necessity of understanding sequence stratigraphy to appreciate the variations and distribution of facies by the integration of all available geological and geophysical data in the study area.
Seismic data interpretation based on a high-resolution 3D survey covering more than 4,400 sq-km was conducted to identify geological features and variations in the Habshan Formation. Data-driven interpretation utilizing different types of 3D seismic attribute volumes, including acoustic impedance volume, was used to identify main cycles and their internal stratigraphic architectures. Well correlation was also conducted to build well-scale stratigraphic framework. Core, logs, and well test data were integrated to understand reservoir properties and distribution. Updated Gross Deposition Environment (GDE) maps and depositional sketches were produced through the integration of seismic data analysis, the revised stratigraphic understanding and well correlation.
A seismic-based revision of the existing sequence stratigraphic interpretation allowed for the identification of better-defined sequences and their systems tracts. The Habshan Formation is interpreted to comprise four main cycles (I, II, III and IV), while the Zakum Member represents one cycle (V). The seismic-based interpretation of the cycles is supported by core and log data and is in line with published data from various locations in Oman. The enhanced sequence stratigraphic understanding resulted in a better definition and prediction of reservoir development and distribution across the study area, by filling the gaps between the sparse available drilled wells. The study results allowed the identification of potential hydrocarbon plays in different stratigraphic settings, by highlighting the geometry and reservoir quality variations of each cycle.
This work demonstrates the role of in-depth, refined data interpretation and integration in identifying possibly overlooked subtle traps through the understanding of sequence stratigraphic signatures in seismic and well data. The results of this work can be used as a basis for the understanding and exploration of the Habshan Fm. and other similarly stratigraphically complex formations in the study area and beyond.
Assessment of CO2 Storage Capacities and Identification of Operational Risks Using Large Basin-Scale Multi-Physics Simulation on Unstructured Mesh
Authors: Chehade Philippe , Ramsay Travis , Raguenel Margaux , Gacem Mohamed , Ronot Cyril , Kloucha Chakib , Jellema Raymond , Hamon Francois , Gross Herve , Bourgeois Frederic , Kachuma Dick 
Published: November 2024

Abstract
The assessment of safe and permanent CO2 storage is of outmost importance to both International and National Energy Companies. Large-scale and robust geological carbon storage projects align with Net-Zero strategy of government and private companies, solidify the response to climate change, and establish entities as major global player in the advance for decarbonization. These aspirations are in line with the Paris Climate Change Agreement, and they offer major economic opportunities to elevate the national and private entities to the forefront of a nascent global decarbonization economy.
A major hurdle for geological carbon storage is ensuring that detailed numerical simulations of the CO2 plume evolutions and the induced geomechanical rock deformations demonstrate safe and permanent storage for several centuries after the injection has stopped. A multiphysics approach combining flow and geomechanics is necessary for a detailed assessment of storage capacity. Combining flow in porous media with rock mechanics over large areas (greater than 60,000 km2) and long periods of time (1,000 years) calls for advanced numerical methods and tools designed for high-performance computing. Safe storage of the injected CO2 requires detailed modelling of all physical phenomena involved in injection and trapping, and a complete risk assessment using uncertainty quantification methods calls for fast simulations. CO2 geological storage simulations must therefore quantify: The migration of the CO2 plume (saturation) and the associated pressure changes,Well performance and injectivity near injection points,Global and local changes in stress (leading to possible fault activation, cap rock fracturing),CO2 dissolution in the brine, and its mineralization,Surface expressions due to the injection, and induced seismicity risks.
Full-Scale Drilling Test Facility: Fast Field Validation of Drilling Automation Solutions
Authors: Wessling S. , Koeneke J. , Arevalo P. , Klemme V. , Schuberth F. , Biedorf R. 
Published: November 2024

The worldwide land and offshore drilling fleet is implementing automated rig and bottom hole assembly (BHA) control functionality using surface and downhole data. End-user validation of automation functionality, conducted during early development, is imperative for qualification. Late-user adoption and inappropriate test environments cause lengthy and costly system adjustments and detrimentally affect end-user trust in the operational system. This paper presents the experiences and benefits of using a full-scale test rig for acceptance testing of automation functionality.The test rig has been instrumental in shortening the time required to qualify BHAs and validate the functionality of automated features covering automated directional drilling (ADD), optimization of drilling parameters, and a variety of well protection features, such as the definition of safe operating envelopes (SOE) for surface parameters. By including a full-scale test rig in the process of technology development, the risk of downhole tools or software malfunctioning is greatly reduced. This translates into more stable deployments and avoidance of non-production time (NPT).In the context of drilling automation applications, the test rig has enabled a faster validation of automated directional drilling (ADD) features in full control mode. This has been achieved by drilling over 2000m of pre-defined well paths covering a variety of drilling and steering scenarios. Such test deployments have enabled a faster evaluation of performance, robustness and accuracy of the overall application. For the case of advisory applications, such as rate-of-penetration (ROP) optimization and well protection, the test rig facilitates and end-to-end validation of the whole data chain including visualization. The visualization concept used by the drilling automation applications varies depending on the final user: directional driller (DD), drilling optimization engineers (DOE), and the driller. For the case of the driller, a driller’s advisory display is installed in the driller’s cabin to show target set points of surface parameters and steering commands, as well as set point limits for surface parameters and the rig equipment. Having a dedicated UI in front of the driller at the test rig provides a faster feedback loop to appraise user acceptance.
Definitive Dynamics Survey: Redefining Efficiency in Wellbore Surveys, A Novel Approach in Andaman Sea Deepwater
Authors: Firnanto Andrean , Siregar Ronny Costamte , Bonafid Kalim , Halim Hulyadi , Salim Victor , Wijayanto Timora 
Published: November 2024

Abstract
Since the 1960s, the oil and gas industry has utilized six-axis stationary surveys with measurement-while-drilling (MWD) technology, requiring torque and pressure release for stationary downhole surveys, leading to time wastage and increased stuck pipe risks. The innovative definitive dynamics survey (DDS) technology improves MWD efficiency by allowing definitive surveys during bottom drilling without the need for a stationary mode. This paper highlights DDS's benefits over conventional MWD, that was introduced first time in deepwater frontier exploration in the Andaman Sea – Indonesia, which is essential for cost management.
The deployment method involves comparing actual survey amounts using DDS against scenario survey amounts with ±120-ft intervals (based on rig tubular handling capability). The study focuses on evaluating the technology's benefits, as follow: eliminating static survey time; reducing the ellipsoids of uncertainty; and enhancing accuracy in determining actual trajectory (wellbore positioning and tortuosity index). Furthermore, the evaluation is performed on benefit of potential reducing the differential stuck pipe risk for future development projects with deviated well trajectories.
The result of this pioneering technology represents a significant advancement in the oil and gas sector, providing operators with key benefits such as reducing EOUs, improving rig time efficiency, and offering enhanced insights into wellbore position and tortuosity. By surpassing the limitations conventional MWD technology that required static time for surveying and provided less accurate trajectory data, this innovation emerges as a compelling replacement.
Finally, this paper validates the directional drilling survey selection method used and emphasizes the pivotal role accurate surveying technology plays in enhancing operational efficiency. In addition, DDS technology provide potential benefits for the highly deviated well development by having accurate surveying enables precise reservoir mapping, optimal well placement in geo-steering applications, reducing stuck pipe risk and enhances reservoir drainage.
Holy Grail of Offshore Decommissioning – Regulatory Approvals for Minimally Invasive, Cost Optimized Abandonment
Authors: Shaik Mohiddin , Jovan Stojkovski , Taha Nagi 
Published: November 2024

Abstract
Offshore decommissioning is a critical aspect of the energy industry, with significant financial implications. The forecast for offshore decommissioning expenditure from 2023 to 2032 is approximately $118 billion, with annual spending expected to exceed $14 billion by 2032. This represents about 3% of the total offshore exploration and production budget. This paper focuses on plugging and abandonment (P&A) of offshore wells, as well as the removal of platforms and subsea equipment. We explore the regulatory framework, items to be decommissioned, removal technologies, demand trends, and cost considerations.
Regarding offshore wells, new decommissioning technologies offer significant cost-saving potential, particularly within the P&A of wells, which accounts for approximately 60% of total offshore decommissioning expenditure. Key technological advancements include rigless WL, CT and HWU well P&A, highly efficient casing milling or perf wash & cement casing penetration techniques for plug placement. As for platform and subsea equipment, technological advancements also aim to remove or repurpose infrastructure, where Innovations in cutting techniques and lifting technology further contribute to cost reductions.
In terms of results and observations, delaying decommissioning spending is generally ill-advised, especially for the permanent P&A of wells. Costs can increase significantly if decommissioning is postponed by several years compared to P&A within three years after well production ends. Similarly, removal costs for platforms and subsea structures may escalate over time. Interestingly, even in regions with stringent regulations (e.g., the North Sea), obtaining approvals for technologically innovative solutions is feasible. Approaches like "rigs-to-reefs" and repurposing existing structures for renewables, CCS can lead to substantial cost reductions while ensuring environmentally sustainable outcomes.
Maximizing Efficiency: Centralized Project Material Management For Owner Operators in Oil and Gas
Authors: Kalleparambil S. A. , Mekala S. , Ibrahim A. , Granata M. M. 
Published: November 2024

The demand for oil and gas remains high despite the increasing prominence of renewable energy sources, highlighting the industry's vital role in the global economy. Oil and gas projects, requiring significant capital and facing high complexity and risk, necessitate effective project management to optimize performance through agility, accurate forecasting, risk mitigation, and stakeholder collaboration (Redda, Turner, and Milano 2018; Yananto, Putro, and Sunitiyoso 2022). Leveraging data-driven approaches enhance operational efficiency, reduce costs, and support informed decision-making, which is crucial given the lengthy timelines and substantial financial commitments in this sector (Darusulistyo et al. 2022; Urton and Murray 2021).
Oil and gas projects span upstream exploration, midstream transportation, and downstream refining and distribution. Each phase presents unique challenges due to technical complexity, stringent regulatory demands, environmental considerations, and market volatility. Projects are generally managed through portfolios to enable dynamic prioritization based on scope, financial goals, risks, resource availability, and alignment with the organization's strategy and governance (Sirisomboonsuk et al. 2018). Portfolio management helps prioritize projects based on scope, financial goals, risks, and strategic alignment, improving financial performance and transparency (Sirisomboonsuk et al. 2018; Wood 2016). Major projects typically follow a stage-gate process, breaking the project into phases—Concept, Feasibility, Definition, Execution, and Operation—each marked by a gate ensuring the project is on track (Newman, Begg, and Welsh 2020; Akhtar 2020).
This paper focuses on the critical aspect of material management that spans across all project phases and relevant contribution to improve capital-project performance. Globally, 64% of projects face budget overruns, and 73% experience schedule delays with material and equipment issues as one of the primary contributors (EY 2020). Material cost is a significant component of overall construction costs, constituting 25–40% of the total cost of typical projects (Mir et al. 2021). Effective material management is integral throughout the entire project lifecycle, from initial concept and feasibility studies to the final operation and maintenance phases. By emphasizing a comprehensive and integrated approach to material management, this study aims to demonstrate how coordinated efforts across all project phases can lead to enhanced project performance, reduced costs, and improved alignment with long-term operational goals.