bluuebunny/crossref_metadata_2025_split huggingface dataset:
Visualizing Geoscience Data Interpretation Into Photorealistic Modern Analog Using Generative AI: A Preliminary Result From Carbonate Platform Environment
Authors: Ramdani Ahmad Ihsan , Perbawa Andika , Vahrenkamp Volker 
Published: February 2024

Abstract
Geoscience datasets are fundamental for subsurface investigation. Paradoxically, they are sometimes exclusive and require subject-specific expertise to interpret and visualize. One such example is seismic interpretation. Geophysicists typically reconstruct ancient depositional settings by interpreting a myriad of seismic attributes and drawing analogs to the sedimentary process of the modern depositional environment (Posamentier et al. 2007; Vahrenkamp et al. 2019; Ramdani et al. 2021). Most of these interpretations will likely be reflection amplitude, frequency, impedance, or other geophysical attributes interpreted and "visualized" in the present-day geomorphology context (Posamentier et al. 2007; Warrlich et al. 2019; Ramdani et al. 2022b). The interpreter will then rely on verbal or written descriptions to convey their interpretation. Often, these descriptions are only well understood by fellow interpreters. Attempting to convey the same interpretation to a non-expert requires some degree of visual aid. Thus, a method to picture geophysical signals as a "depositional environment" is needed to bridge this gap. This study aims to leverage the application of generative AI as a tool for seismic interpretation. We propose a Conditional Generative Adversarial Network (CGAN)-based methodology capable of converting seismic attribute maps into photorealistic images of the modern satellite imagery analog as a visual aid for seismic interpretation.
Finding the Next Incident (FtNI): A Tool for Learning from Normal Work
Authors: Yasseen Abdelsalam , Nonno L. 
Published: February 2024

The conditions that could lead to the next serious incident in our organizations already exist today; the reason it hasn't yet occurred is simply because the combination of conditions has not materialized thus far.
When contemplating the next incident, important questions arise: What will happen? Where will it take place? Who will be affected? And, most importantly, why can't we anticipate it? If we haven't truly learned enough from previous cases, it raises the question of whether we need more high-potential "near misses" to enhance our understanding and foster better learning.
The diagram, represented as Figure 1, illustrates that incidents constitute only a small portion of the data available for Learning from Normal Work (LFNW).
Increasing Production Through the Application of an Emulsion Viscosity Reducer in an Onshore Gas Lifted Middle East Oil Field
Authors: Caird S. , Sharief R. 
Published: February 2024

Viscous emulsions are produced as oil and water are transported from the reservoir through the production infrastructure as a result of the shear forces exerted on the fluids by process restrictions. As fields mature and water cuts in wells increase so does the viscosity of the produced fluids due to the formation of emulsions. This increase in viscosity results in an increase in frictional forces and can lead to slugging and a reduction in production.
Laboratory testing was performed on fresh samples collected in the field to identify suitable Emulsion Viscosity Reducer chemistry by measuring the reduction in emulsion viscosity with the addition of various chemical formulations. Based on the results of this testing a field trial was performed on three wells, applying the selected formulation downhole via injection through the gas lift system. Gas lift compatibility testing was performed on the chemical prior to the trial.
Gas lift injection was demonstrated as a viable means in which to inject Emulsion Viscosity Reducer chemical downhole. A lag of between 12 and 24 hours was observed between chemical injection commencing and changes in the fluids being produced being observed. Emulsion was measured by centrifugal analysis and viscosity using a viscosity cup. Measurements were taken prior to chemical injection commencing and throughout the duration of the trial. The chemical injection was optimised and the effect on emulsion and viscosity observed. Reductions in viscosity of approximately 50% were achieved on each well. Emulsion content was also significantly reduced although some wells displayed more erratic results than others, indicating that slugging was a factor influencing emulsion stability. Oil production was also recorded, and increases observed with up to 10% more oil on average produced during the trial period compared to baseline data.
These reductions in viscosity and emulsion, and subsequent increase in oil production, show that existing artificial lift infrastructure can be utilised to increase production efficiency, opening the possibility for other producers of oil and gas in the region to maximise their existing their assets as water cuts increase.
Downhole Sludge and Deposition - Characterization and Treatment Design
Authors: AlMuhaish S. A. , Al Moajil A. M. 
Published: February 2024

Abstract
Sludge formation in oil wells results in near wellbore flow restriction or causes damage to electric submersiable pumps (ESP), thus, reducing their lifetime and causing operational upsets. Prevention and cleanout solutions of such deposits require understanding of sludge characterization and potential formation mechanism. The objective of this study is to present typical types of oilfield sludge and propose a systematic testing protocol to properly characterize organic/inorganic depositions.
Examples of typical oilfield sludge deposits were obtained for the study that either organic, inorganic, or mixtures of both. Several experimental and analytical techniques were used to develop a testing protocol for sludge characterization and remediation. This include filtration, centrifugation, extraction, solubility,, acid digestion, and geochemical analysis, pyrolysis, thermogravimetric analysis, Saturates Aromaticss Resin Analysis (SARA) fractions, Gas chromatography–mass spectrometry, thermogravimetric analysis, x-ray diffraction/fluorescence. Solvents were obtained characterize and analyze sludge components such as benzene, toluene, diesel, n-pentane, chloroform, dichloromethane, terpene or naphthalene-based solvents, HCl acids.
A sludge characterization workflow and testing protocol was developed that include the following main categories: 1) Sample preparation, 2) phase separation, 3) liquid portion, 4) water portion, 5) organic content, 6) inorganic content, and 7) sludge re-formation. The process provided characterization of the sludge composition and potential forming mechanisms such as inorganic, organic, water content and compositions. Most oilfield sludge deposits are mixtures of organic and inorganic components. Implementing systematic analysis procedures helped to better characterize the sludge samples. For instant SARA analysis showed presence of asphaltene in a sludge sample while Gas Chromotography (GC) and Gas Chromotography Mass Spectrometer (GC-MS) analysis suggested presence of synthetic polymer used in drilling operations of characteristics similar to ashapltene. In another example, treating a sludge sample composed of organic and inorganic components with only diesel, mutual solvent, or naphtha feeds was sufficient to partially dissolve and liquefy the sludge, thus, allowing it to be flowed back during production, and eliminating the risk of using HCl acid in acid-sensitive formations.
A Data-Driven Hydrate Plug Detection in Offshore Gas & Condensate Flowlines
Authors: Della Pietà A. , Galimberti C. , Corneo A. , Scaringi S. , Calzavara G. 
Published: February 2024

Abstract
In multiphase transport pipelines, gas hydrate blockages are a major flow assurance challenge, due to the difficulties in remedial actions and the potential massive production losses. Scope of this study is to define an innovative data-driven methodology to early detect hydrates formation, provide an alarm, and permit early intervention before the complete blockage of the flowline.
The proposed approach is applied on a Gas & Condensate pipeline during cold restart, which is the most critical scenario for hydrates formation. In the absence of reliable field data, the methodology was validated on synthetic data. Through a Design of Experiment (DoE) strategy, a wide range of operating conditions (with and without hydrate plug) has been simulated using a multiphase flow model, by varying some key parameters. Only field-measurable variables have been considered for the machine learning model training. In addition, a custom "Friction Factor" indicator and its derivative over time have been calculated, as they emerged to be crucial for model’s performance enhancing.
A classification model (XGBoost), called "Alarm Model", was defined to detect the formation of a hydrate plug and raise an alarm, based on a "RiskProbability" estimate. As a result, the model consistently managed to detect in advance the formation of hydrate plugs, particularly in cases of long-time formation.
A second model (XGBoost), called "Failure Temporal Distance Model", was developed to classify the system status after an alarm is raised, giving information about the residual time to reach the failure event. This model showed good performances, with 85% of recall for the most critical class (i.e., imminent events), and a global accuracy of 80%.
As a conclusion, this research highlights the successful application of machine learning and the relevance of the "Friction Factor" derivative in dynamically detecting plug formation in pipeline systems, without relying only on static thresholds. The use of DoE methodology has proven to be useful in obtaining sufficiently diverse simulations to achieve an algorithm that provides accurate and timely predictions. These findings contribute to the advancement of plug formation detection techniques, with potential applications in enhancing the operational efficiency and maintenance strategies of pipeline networks.
Characterizing Thermal Runaway of Reservoir Rocks Under Electromagnetic Irradiation Towards Hydrogen Generation from Petroleum Reservoirs
Authors: An Baizheng , Yan Keju , Yuan Qingwang 
Published: February 2024

Abstract
In-situ hydrogen generation and extraction directly from petroleum reservoirs provides a new solution to meet the increasing need for clean energy and to mitigate greenhouse gas emissions. This method leverages the abundant petroleum resources while simultaneously sequestrating carbon by-products underground. To enable in-situ clean hydrogen production from petroleum reservoirs, we proposed electromagnetic (EM)-assisted catalytic heating technology. Although significant potential has been recently assessed through lab-scale experiments and preliminary techno-economic analysis, the heating behaviors and interactions between EM waves and reservoir rocks are poorly understood, especially at a high enough temperature when hydrogen is generated. This study aims to elucidate the underlying mechanisms regarding the heating performance of sandstone and shale rocks under microwave irradiation. Advanced characterization techniques are employed to analyze the changes of rocks before and after microwave heating. The thermal runaway (TR) phenomenon is identified for the first time for San Saba sandstone rocks at 568°C and Mancos shale rocks at 253°C when they are exposed to microwave radiation. We further investigated the interactions of microwave with each pure mineral (e.g., albite, chlorite, illite, microcline, dolomite, kaolinite, calcite, and quartz) using a microwave reactor system. We identified that chlorite, albite, and illite are the main minerals that lead to the TR phenomenon. We also found that a high temperature can be easily achieved for both rocks at a much lower input power after TR, resulting in approximately 50% energy saved when the reservoir rocks are re-heated to 500°C. The occurrence of TR can therefore enhance the heating efficiency of reservoir rocks, reduce energy input, and significantly decrease the cost of in-situ hydrogen production from petroleum reservoirs using our proposed EM-assisted catalytic heating technology.
Paradigm Shift of the Deep Marine Fan Deposit (Ultra-Tight) Gumai Sand Reservoir’s Development Upon Recently Known Subsurface Heterogeneity and Uncertainty in Tempino Field, Jambi, Indonesia
Authors: Rahadian R. , Sipahutar H. , Hendrian D. , Priatama I. N. , Hakimi D. A. , Pratama H. , Alfajri R. , Subhan M. 
Published: February 2024

Abstract
This study focuses on gaining a deeper understanding of the Gumai sand reservoir in the Tempino Field, which is known for its complexity due to its heterogeneity and low quality properties. The research draws from insights gleaned from the drilling of six recent wells, shedding light on key factors that have a substantial impact on reservoir behavior and development strategies. One of the central findings of this study is the importance of rock typing. Historically, a simplistic single-rock-type model was used in reservoir characterization. However, the research demonstrates that this approach was inadequate in capturing the reservoir's complexity. By utilizing electrical open-hole logs and taking into account limited core analysis data, the study identifies three distinct rock types within the Gumai sand reservoir. This discovery is a significant departure from conventional practices and underscores the necessity of considering heterogeneity when dealing with sand reservoirs. Furthermore, the study delves into fracture pressure measurements and their implications. The discrepancy in fracture pressure data, observed at an equivalent depth of 1100 meters among the latest five wells, is discussed. This discrepancy is closely linked to the behavior of hydrocarbon production. It's a reminder that understanding fracture pressure is critical when evaluating a reservoir's behavior and productivity.
One of the noteworthy findings pertains to well T-220, which was positioned at the peak of the Gumai sand reservoir's closure. While based on a study conducted in 2022, it was expected to have the highest oil production rate, the actual results were disappointing. Even after a workover job with remedial cementing, the production behavior remained subpar. This observation highlights the importance of rock typing and how it directly correlates with the reservoir's production behavior.
In essence, this research offers a novel and different approach to managing a mature field with diverse, low-quality sand reservoir properties. It challenges the conventional paradigm by advocating for a more nuanced understanding of the heterogeneous sand reservoir. By acknowledging the presence of distinct rock types within the reservoir and accounting for their impact on production behavior, the study paves the way for more effective field development strategies.
Successful Field Trials for Tracking Casing Exit: Innovative Sensing Technology Application
Authors: Gamal Hany , Gomez Hector , Alshalan Meshari , Alshaarawi Amjad 
Published: February 2024

Abstract
Casing exit operations are a common technique in the well intervention domain due to many technical purposes as accessing more reservoirs (re-entry drilling) or bypassing downhole obstructions (remedial operations). The casing exit is a complex operation that involves milling through the well casing to create an exit path and then drilling a rathole for accommodating any subsequent drilling bottom hole assembly (BHA) such as mud motor or rotary steerable system. Accurate tracking of the casing exit process is essential to ensure the operation's success and save extra runs to check passing through the window. This abstract presents two successful field trials for a novel approach using advanced sensing technology to track the casing exit window.
Many factors impact successful window milling in terms of operation parameters, penetrated formation, casing and cement integrity, wellbore inclination and dogleg severity, subsequent BHA, etc. To date, there is no standardized application for tracking window milling, leaving a critical gap in the industry's ability to track this crucial process. Through this paper, innovative sensing technology was tested through two field trials to track the casing exit window through providing the angle change above the window and at the window end along the window profile. The innovative approach showcases the developed technology's remarkable capability to accurately assess the window quality, thereby effectively reducing additional run costs and time.
The field trials conducted on two wells have demonstrated the system's robustness and effectiveness in accurately tracking the milling window during casing exit. The two trials were conducted through casing exit jobs while the sensor was assembled with the milling string. The results obtained from the two jobs through angle differences measurements showed the good window quality to pass the BHA from the technical engineering and operation aspects. The subsequent BHA runs confirmed passing the window milling successfully and the next section was drilling within the same run. The successful implementation of this novel application represents a significant advancement in the field of casing exit operations. It offers tangible benefits to the oil and gas industry by tracking the window profile quality. The remarkable outcomes obtained from the successful field trials unlock opportunities for further advancements in downhole monitoring tools and subsequent real-time log data, leading to a path of increased automation and optimization in casing exit operations.
An Integrated Interdisciplinary Approach to Delivering Successful Infill Wells in a Mature Field
Authors: Yeoh X. , Iliani N. , Fadjarijanto A. , Gallagher B. , Bakar A. , Sikandar A. , Hoeyland H. 
Published: February 2024

Abstract
Jadestone Energy's main approach in maximizing recovery and extending mature field life is the integration of the various subsurface disciplines to improve understanding of the field development and production history. It is critical to capture the reservoir complexity and dynamic behavior to identify the remaining oil potential for future infill target opportunities.
An integrated interdisciplinary study was conducted to capture the reservoir complexity and understand the dynamics of the rock-fluid interaction leading to identification of bypassed oil volumes. Challenges addressed are structural and well placement uncertainties, non-reservoir glauconite distribution, water sweep at local and reservoir scale. Further re-evaluation of 3D seismic and understanding of historical and current production performance supports the infill targets. Fast cycle times between geoscience and well designs criteria resulted in optimum well trajectories for drilling.
Jadestone Energy acquired Stag field in 2017, located offshore Western Australia in the WA-15-L production license. Jadestone Energy has successfully drilled the first well, 49H in 2019 and replicated the success in 2022 by drilling two additional infill wells, 50H and 51H. 50H was strategically drilled perpendicular to existing wells to maximize reserves, resulting in severe anticollision provisions to drill across 10 wellbores within a narrow vertical window. This required careful planning and precise execution of the plan to stay in the sweet spot. 51H was considered as extreme- reach-drilling with the longest production section at shallow vertical depth. Drilling through low reservoir pressure, thin oil column was also impacted by risk of hydraulic fracture which required detailed geomechanical study.
Both wells were drilled safely and achieved the desired outcomes. Reservoir mapping tools were utilized to assist in accurately placing and steering the wells within the reservoir's sweet spot. As a result, 50H inversion results affirmed water cone of 75m when crossing in the vicinity of active producer, matched model prediction for initial rates and water cut, while confirming thicker oil column at toe of the well. It proved the well placement uncertainties of the existing well as per prediction. 51H was drilled safely to target length despite suffering total losses before entering the reservoir. This too confirmed pre-drilled oil column thickness and unique structural prognosis.
The success of an infill well drilling campaign was achieved through applying multi-disciplinary integrated solutions in a complex geological and production environment, coupled with overcoming challenging drilling operations through aggressive well planning and optimization. Successful application of deep resistivity reservoir mapping tools with geosteering was achieved for both wells.
An Experimental Study for the Impact of Heating and Cooling on Strength of Unconventional Reservoirs
Authors: Khan F. , Mahmoud M. , Patil S. , Raza A. , AlTammar M. J. , Murtaza M. , Al Marri M. , Al Shafloot T. 
Published: February 2024

AbstractUnconventional reservoirs (shale and tight sandstone) have gained significant attention in meeting increasing energy demand despite unconventional ways to exploit these resources. Numerous studies have been carried out to evaluate different aspects of unconventional reservoirs including geomechanical characteristics at high pressure and temperature. However, less attention has been given to understand the impact of temperature change on the strength of the rock. This study focuses on two unconventional rocks namely Kentucky Sandstone (0.98mD) and Eagle Ford Shale (21.39μD), aiming to investigate the effect of heating and cooling on strength. XRD analysis showed that the main mineral in the tight sandstone is quartz (61%), whereas in the shale, it is calcite (88.6%). A central hole was drilled in a 2.5-inch core to accommodate a temperature logger and heated to 250 °C. The rate of reduction in rock temperature was then recorded using a temperature probe till 30 °C. Micro CT-Scan imaging was performed before and after heating the samples to 250 °C to observe any microstructural changes. Finally, the strength of the rocks was determined through a scratch test. The obtained results demonstrated that the sandstone core exhibited a heating rate of 2.3 °C/min initially to reach up to 68 °C, then reduced to 0.8 °C/min to reach the final temperature of 85°C. In contrast, the Eagle Ford Shale showed a consistent single heating rate of approximately 1.7 °C/min to reach 85 °C. The final temperature was set to maximum value of 85 °C during heating due to limitation of temperature logger inside the oven, however for rate of cooling the samples were heated in the oven at 250 °C and cooled at room temperature, measuring the rate of cooling. Comparatively, sandstone was more conducive to heat than shale. During the cooling phase, the temperature of sandstone initially reduced at a rate of 6.5 °C/min to reach 110 °C, 2.7 °C/min till 60 °C, and eventually reached 30 °C at a rate of 0.7 °C/min. The Eagle Ford Shale exhibited a temperature reduction trend, ranging from 5.7 °C/min up to 110 °C, 2.0 °C/min till 60 °C, and reached 30 °C at a rate of 0.6 °C/min. The heating and cooling cycles resulted in reduced strength for both samples. The average strength of Kentucky Sandstone decreased from 5896 to 5415 psi (8.1% ↓), while the strength of Eagle Ford Shale decreased from 18240 to 16840 psi (7.7% ↓). These findings contribute to a better understanding of induced thermal impact on mechanical properties of unconventional rocks.