bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fault-Guided Seismic Stratigraphy Interpretation via Semi-Supervised Learning
Authors: Di Haibin , Kloucha Chakib Kada , Li Cen , Abubakar Aria , Li Zhun , Jeddou Houcine Ben , Mustapha Hussein 
Published: December 2021

AbstractDelineating seismic stratigraphic features and depositional facies is of importance to successful reservoir mapping and identification in the subsurface. Robust seismic stratigraphy interpretation is confronted with two major challenges. The first one is to maximally automate the process particularly with the increasing size of seismic data and complexity of target stratigraphies, while the second challenge is to efficiently incorporate available structures into stratigraphy model building. Machine learning, particularly convolutional neural network (CNN), has been introduced into assisting seismic stratigraphy interpretation through supervised learning. However, the small amount of available expert labels greatly restricts the performance of such supervised CNN. Moreover, most of the exiting CNN implementations are based on only amplitude, which fails to use necessary structural information such as faults for constraining the machine learning.To resolve both challenges, this paper presents a semi-supervised learning workflow for fault-guided seismic stratigraphy interpretation, which consists of two components. The first component is seismic feature engineering (SFE), which aims at learning the provided seismic and fault data through a unsupervised convolutional autoencoder (CAE), while the second one is stratigraphy model building (SMB), which aims at building an optimal mapping function between the features extracted from the SFE CAE and the target stratigraphic labels provided by an experienced interpreter through a supervised CNN. Both components are connected by embedding the encoder of the SFE CAE into the SMB CNN, which forces the SMB learning based on these features commonly existing in the entire study area instead of those only at the limited training data; correspondingly, the risk of overfitting is greatly eliminated. More innovatively, the fault constraint is introduced by customizing the SMB CNN of two output branches, with one to match the target stratigraphies and the other to reconstruct the input fault, so that the fault continues contributing to the process of SMB learning. The performance of such fault-guided seismic stratigraphy interpretation is validated by an application to a real seismic dataset, and the machine prediction not only matches the manual interpretation accurately but also clearly illustrates the depositional process in the study area.
Individual Fracture Efficiency Monitoring in Horizontal Wells by Using a New 3d Fine-Grid Temperature Modelling
Authors: Virt Vitaly , Kosolapov Vladimir , Nagimov Vener , Salamatin Andrey , Fesina Yulia , Alekseeva Anastasia , Yakhina Yulia , Skutina Elizaveta 
Published: December 2021

Abstract
Profitable development of hard-to-recover reserves often involves drilling of horizontal wells with multistage hydraulic fracturing to increase the oil recovery factor. Usually to monitor the fracture sweep efficiency, pressure transient analysis is used. However, in case of several fractures this method delivers only average hydrodynamic parameters of the well-fracture system. This paper illustrates the value of temperature logging data and demonstrates possibilities of the 3-D thermo-mechanical modelling in evaluating the differential efficiency of multi-stage hydraulic fracturing.
Modern Drilling and Completion in Contradiction of New Artificial Lift Method Concept
Authors: Hegazy Gehad Mahmoud 
Published: December 2021

Abstract
In challenging times of 2020 and inconsistency with the background of a low-oil-price environment, innovative ideas needed to give a second life to all available resources such as unconventional, shallow, depleted, mature, heavy oil and by bypassed oil with a cost-effective manner (usually innovation created to fit needs). U-shaped well a combined with pigging lifting (conceptual study for new artificial lift method) is one of the selected scenarios studied under the objective of innovative, low-cost techniques to overcome many projects challenges.
U shaped well accompanied with a new pigging artificial lift method are new concept studied in this lab work. Conceptual model presents many benefits of this new application such as solving most of the current wells and production challenges. The study reflects more well control with two paths, better well stimulation, low fracturing pressure and double rates, inject and lift chemical for clean without intervention, double well life "additional strings", new recompletions without rig, two horizontal side used for production or injection, step change for reservoir monitoring, improving artificial lift performance and allow creating Pigging lift "New artificial lift concept".
U shaped well accompanied with a new pigging artificial lift method study shows the following progress: 1. Additional down hole barrier from the deepest point and additional open side keep the well under control more over minimize the existing well control killing procedures with low cost and risk in addition to discarding the CT operations for killing or prepare the well for W/O. 2. Decreasing stimulation pressures needs (double injection rates) and overcome the existing accessibility challenges 3. Allowing pull heading stimulation w/less displacement time and high rate and chimerical batch pumping from one side to another increase well life and eliminate PKRs risk as chimerical batches will be pigger, easier and faster. 4. Additional down hole monitoring system allowing uniform stimulation and discarding the CT operations for well stimulation and cleaning, 5. Avoiding post stimulation damage throughout fast clean-up 6. Ability to stimulate from one side with artificial lift from other side Avoiding the corrosion and erosion by faster operations 7. Allow faster plug and perf. multistage fracturing technology and overcome the unconventional well fracturing which required rate and pressure 8. Eliminate rig usage to pull the frac string to run completions 9. Step change for reservoir mentoring without S/D and real-time Logging, Sampling
The deployment of U Shaped Well allows new artificial lift concept (Pigging lift) to apply. This new approach led to improved wells performance also raising efficiency of the use of the existing resources besides saving time and in return cost. This approach helps in improving well utilization and efficiency levels.
Advanced Light Weight Thixotropic Lost Circulation Cement Solution for Vugular and Natural Fractured Limestone Formations: UAE Offshore Case History
Authors: Doutoum Mahamat Habib Abdelkerim , Bermudez Alvarado Romulo Francisco , Alaleeli Ahmed Rashed , Phyoe Thein Zaw , Salazar Jose , Albuja Eduardo Herrera , Kapoor Saurabh , Orfali Mohd Waheed , Rahhal Gilbert 
Published: December 2021

Abstract
Lost circulation while drilling across vugular or naturally fractured limestone formations is a costly challenge and has financial impacts including nonproductive time and remedial operational expenses. Many fields in the UAE are encountering notorious lost circulation complications, which are difficult to control with conventional lost circulation solutions while drilling surface sections. Novel lightweight thixotropic cement has proven beneficial to take control of severe losses in these vugular and naturally fractured limestone formations.
The main challenge while drilling across the surface section in UAE offshore field is the heavy or total loss of returns. Drilling performance is affected due to poor hole cleaning, a risk of stuck pipe, surface fluid handling problems, and well control risks. Conventional extended cement slurries have been widely used to cure losses while drilling but with limited success. A new lost circulation solution combines lightweight (10.5- lbm/galUS) high solids fraction cement (trimodal system) and a thixotropic agent, which develop fast gels with high compressive strength. Thus, it enables plugging of large voids and fractures to deliver the wellbore integrity required to continue drilling with enhanced performance and efficiency.
Intensive laboratory qualification tests focusing on static gel strength and compressive strength development was performed to tailor the new solution. The results were promising with more than 100 lbf/100 ft2 of static gel strength in 10 minutes and compressive strength development of 1,000 psi within 24 hours at low surface temperature. In addition, a transition time (TT) on-off-on test demonstrated more rapid gel strength development when the shear is reduced and regained fluidity with reapplication of shear.
In one of the wells, heavy losses were encountered while drilling across surface section. The lightweight thixotropic solution was pumped for the first time worldwide and it was shown that the innovative lost circulation solution was effective in significantly reducing the losses and enabled the operator to continue drilling to section TD.
This case study demonstrates that this advanced system is effective in curing losses and reducing nonproductive time. The unique properties of faster rapid gel strength and high compressive strength make this solution effective for treating a wide range of lost circulation events while drilling. Furthermore, the advanced lightweight thixotropic cement lost circulation solution exhibits strong performance in curing heavy losses and establishing well integrity with reliability.
Experimental Results to Design Lactic Acid for Carbonate Acidizing
Authors: Alhamad Luai , Alfakher Basil , Alrustum Abdullah , Aldarweesh Sajjad 
Published: December 2021

Abstract
Acidizing deep carbonate formations by Hydrochloric acid (HCl) is a complex task due to high reaction and corrosion rates. Mixing organic acids with HCl is a typical method to reduce the acid's reactivity and corrosivity. Lactic acid has not been investigated completely in the area of carbonate acidizing. Lactic acid has a dissociation constant similar to formic acid, which is approximately 10 times larger than acetic acid. Therefore, the objective of this work is to compare lactic/HCl blends with plain HCl and formic/HCl blends.
Corrosion tests were conducted at high temperature on C-95 steel coupons to investigate associated corrosion damage. Coreflood tests were performed on Indiana limestone cores to mimic matrix acidizing treatment and to investigate amount of pore volumes required to breakthrough. All blends were prepared to be equivalent to 15 wt% (4.4 M) HCl for comparison. Lactic and formic acid concentrations were set to be (0.5 or 1 M), and HCl concentration was calculated as appropriate to reach a blend with strength of 4.4 M.
In terms of corrosivity evaluation, blends of lactic and HCl acids showed a corrosion rate of up to 1.97 lb/ft2 at 300°F. The formic and HCl blend showed a corrosion rate of 1.68 lb/ft2 at the same temperature. The difference in corrosion rates between the two mixtures is due to molecular weight difference between lactic and formic acids. When both acids were prepared at 1 M, lactic acid blend required more HCl to be equivalent to 15 wt% HCl acid which was associated with an increase in corrosion rate. Coreflood results established acid efficiency curves for lactic/HCl acid blends. The curves highlighted the correlation between acid-core reactivity, injection rate, and dissolution pattern. Lactic/HCl blend was less reactive than formic/HCl mixture as the last required lower injection rate to obtain optimum pore volume to breakthrough at 300°F. Lactic/HCl blend was able to generate an optimum dissolution pattern as a dominant wormhole was shown on tested core plugs inlet face.
This study expands the investigation of lactic acid utilization in carbonate acidizing. Major advantages rendered by using lactic acid with HCl include: (1) favorable dissolution pattern due to lactic acid being less reactive than HCl or formic acids, and (2) less corrosion rates comparing to HCl, that can reduce allocated costs for maintenance and replacements.
Application of Okra Mucilage for the Prevention of Shale Swelling
Authors: Murtaza Mobeen , Tariq Zeeshan , Kamal Muhammad Shahzad , Mahmoud Muhammad , Al Sheri Dhafer 
Published: December 2021

Abstract
Maintain wellbore stability is a very critical aspect of the drilling operation. The unstable wellbore provides severe loss to the drilling operators in terms of time and money. One of the significant reasons for unstable wellbore occurs due to the expansion of shale formation. Several solutions are utilized to tackle the expansion of shales, such as salts, PHPA, silicates, and oil-based drilling fluids. There are limitations associated with these solutions, such as thermal instability, limited supply, unfriendly to the environment and marine life, etc. In this study, Okra mucilage has been introduced as a shale swelling inhibitor in drilling fluids. Okra is widely used in the medical and food industries as a viscosifier as it is abundantly available in tropical and subtropical regions. Okra powder has been used as a fluid loss control additive in the literature. The application of the Okra solution as a shale swelling inhibitor in drilling fluids was not investigated in the past.
In this study, Okra mucilage was extracted from the Okra plant and used as shale swelling inhibitor. Three different concentrations (5, 10 & 20) vol% of Okra mucilage mixed solutions were used for linear swell test. The test was performed using a linear swell tester at atmospheric conditions for 24 hours on bentonite wafers. Further zeta potential, particles size and capillary suction timer test (CST) were conducted. The experimental study revealed that Okra mucilage reduced the swelling of bentonite. For instance, 10 and 20% of Okra mucilage solutions reduced the swelling by 36.8% and 50.5%, respectively. The Okra mucilage decreased the zeta potential of clay and increased its particle size. CST time decreased initial at low concentration and increased with concentration. Overall, experimental investigations suggested that Okra mucilage could be an alternate green shale inhibitor in drilling fluids without compromising other drilling fluids' properties.
The Role of Turbomachinery in Enabling the Hydrogen Economy
Authors: Corbò Simone , Wolfler Tommaso , Banchi Nicola , Furgiuele Ippolito , Farooq Majid 
Published: December 2021

Abstract
The purpose of this paper is to present the various technological solutions optimized for the use of hydrogen, in transport, distribution, storage and utilization, analyzing their criticalities and advantages. Hydrogen compression is a fundamental step in the transportation and storage segments and continuous improvement are required. The greatest technological challenges are certainly the high pressures required for the various fields of use, the need to maintain a clean gas and to use materials that are not subject to embrittlement. The choice between the different compression technologies is based on the need for pressures and flow rates; in the case of high flow rates and low compression ratios a centrifugal compressor is preferable, while for low flow rates and high compression ratios the choice goes to piston compressors.
To prevent gas contamination, dry reciprocating compressor are preferred because they allow to avoid an oil separator filter on the discharge. Current technology of reciprocating compressors allows to compress hydrogen up to 300 bar with lubricated machines, while with dry technology it is possible to reach up to 250 bar. A second criticality on reciprocating compressors is maintenance: the parts subject to wear need to be serviced every 8000 hour of operation. The use of innovative materials will increase the maintenance intervals reaching higher pressures without lubrication.
To increase the pressure ratio with centrifugal compressor, it's needed to increase the rotating speed, therefore the peripheral speed, with materials suitable for H2, stages get high compression to reduce the number of compressor bodies.
If the process conditions require high delivery pressures combined with large flow rates, a solution of centrifugal compressors alone would be able to manage the flow rate but not the required delivery pressure. On the other hand, the use of reciprocating compressors would require a considerable number of units. In this case, therefore, the optimal solution is to combine the two technologies, centrifugal and pistons, using the best features.
A case study in which the superior performances of the hybrid solution in terms of total cost of ownership will be described and compared with traditional single technology compression train
Probabilistic Economical Evaluation for Business Decisions Through Integrated Uncertainty Assessment and Reliable Ensemble-Based Production Forecasts
Authors: Abd-Allah Mohammed , Abdelrahman Ahmed , Van Den Brul Luke , Taha Taha , Javed Mohammad Ali 
Published: December 2021

Abstract
Economic evaluation of exploration and production projects ensures a positive return for asset operators and stakeholders and evaluates risk in field development decisions related to both reservoir model uncertainties and fluctuations in oil and gas prices. Traditionally, such evaluation is performed manually and deterministically using single or limited number of cases (limited number of reservoir models and few values of economic parameters). Such traditional approach does not integrate seismic-to-simulation reservoir model uncertainties, the reservoir model used is often unreliable due to inconsistent property modifications during the history matching process, full span of prediction uncertainty isn't properly propagated for economic evaluation and the whole process is not fully automated.
This paper presents an integrated and automated forward modelling approach where static and dynamic models are connected to integrate the impact of uncertainties at the different modelling stages (seismic interpretation through geological modelling to dynamic simulation and further to economic evaluations). The approach is demonstrated using synthetic 3D model data mimicking a real North Sea field. It starts by building an integrated modelling workflow that can capture the various reservoir model uncertainties at different stages to automatically generate multiple probable model realisations. Proxy models are constructed and used to refine the history match in successive batches. For each prediction development scenario, prediction probabilities are estimated using posterior ensemble of geologically consistent runs that matches historical observed data. The ensemble of reservoir models is automatically evaluated against different possible economic scenarios.
The approach presents a seamless and innovative workflow that benefits from new-generation hardware and software, enables faster simultaneous realisations, produces consistent and more reliable reservoir models. Probabilistic economic evaluation concept is implemented to calculate the statistical probabilities of economic indicators.
Using New Intervention-less Surveillance Technology to Optimize the Implementation of Waterflood
Authors: Al Anbari Ali , Al Harthi Mahmood , Choudhury Suryyendu , Borkent Evert-Jan , In ‘T Panhuis Petrus , Hemink Gijs , Al Yahmadi Mundhr , Abdul Abbas Hawra , Morianta Marpaung 
Published: December 2021

AbstractThe value of implementing intervention-less downhole surveillance technology lies in early assessment of field-scale reservoir performance and well deliverability in South Oman's largest waterflood development. Such technology can aid in assessing whether aquifer support by means of (controlled) fracture injection is achievable, which is potentially more valuable than matrix injection to enhance oil production. At the same time HSSE exposure and deferment will be reduced by avoiding well interventions. This paper will share learnings from Distributed Fiber-Optic (FO) Sensing technology.More specifically, this paper will present the case study of field ‘A’, where waterflood is being operated in two methods based on sectors depending on field geological and reservoir properties:‘Deep’ water injection in the aquifer, under fracture conditions ‘Shallow’ water injection close to the oil-water-contact (OWC), under matrix conditions‘Deep’ water injection minimizes the risk of early water breakthrough, but it delays the aquifer pressure support which in turn means lower offtake. The ‘Shallow’ water injection (trialed by injecting water 50m below OWC) has a higher risk of water short circuiting, accelerates pressure support and thereby enhances production / well deliverability.Fiber-optic data is part of a decision-based surveillance program, which also included injection / production logging via PLT, step-rate tests, and pressure monitoring. The time-lapse data has illustrated some fracture growth up- and downwards of the perforation interval in most wells but is still contained below the OWC. In some wells, the injection growth is also controlled by the presence of several intra-reservoir shale baffles that are acting as barriers to vertical communication and thereby delaying the injection response while inducing a strong pressure response in nearby producers. The data has helped to further calibrate and validate the model assumptions and will help in optimizing the waterflood development concept for the field. Proactive interventional-less surveillance enables monitoring of the zonal injection conformance, provides advantage of learning reservoir performance and supports agile WRFM operations and decision making. Furthermore, cost competitive and credible technology have made PDO a front runner to keep subsurface risk at as low as reasonably practical levels and boost oil production. This distributed fiber optic sensing technology provided cost-effective, fit-for-purpose, and intervention-less well-and-reservoir surveillance.
Enhanced Production with Self-Driven Multi-Phase Pumps
Authors: Abdul Halim Maamoun , Maianti Emiliano 
Published: December 2021

Abstract
Some wells are either producing intermittently or ceasing against the trunk line pressure due to low flowing wellhead pressure. OLS with MPP provides the flexibility such as boosting pressure from low flowing wellhead pressure well to the existing trunk lines. The MPP has a wider pressure operating envelope to accommodate the less flowing wellhead pressure well in long run. Incremental Oil & gas production will be realized by lowering the FWHP on this well using the OLS.
Multi-Phase Pumps solutions have sustained production from marginal and restarted non-producing wells.
Production gains are highly dependent on the reservoir and well parameters.
Using AI/ML to Explore & Develop Quickly and Efficiently
Authors: Aming Anthony 
Published: December 2021

Abstract
See how application of a fully trained Artificial Intelligence (AI) / Machine Learning (ML) technology applied to 3D seismic data volumes delivers an unbiased data driven assessment of entire volumes or corporate seismic data libraries quickly. Whether the analysis is undertaken using onsite hardware or a cloud based mega cluster, this automated approach provides unparalleled insights for the interpretation and prospectivity analysis of any dataset.
The Artificial Intelligence (AI) / Machine Learning (ML) technology uses unsupervised genetics algorithms to create families of waveforms, called GeoPopulations, that are used to derive Amplitude, Structure (time or depth depending on the input 3D seismic volume) and the new seismic Fitness attribute. We will show how Fitness is used to interpret paleo geomorphology and facies maps for every peak, trough and zero crossing of the 3D seismic volume. Using the Structure, Amplitude and Fitness attribute maps created for every peak, trough and zero crossing the Exploration and Production (E&P) team can evaluate and mitigate Geological and Geophysical (G&G) risks and uncertainty associated with their petroleum systems quickly using the entire 3D seismic data volume.