bluuebunny/crossref_metadata_2025_split huggingface dataset:
Using Fixed-Point Observation Experiments to Study the Expansion Law of Microfractures Induced by Shale Hydration
Authors: Tao Liang , Guo Jianchun , Li Geng , Chen Chi , Zhao Yuhang , Zhao Zhihong 
Published: November 2020

AbstractShale rocks are rich in organic minerals, also it contains multi-scale micro-nano pores, making flow mechanism of fracturing fluid in microscopic pores of shale and the interactions between fracturing fluid and shale very complicated. In this study, firstly, the initial microscopic pore structure of shale before hydration was analyzed by field emission electron microscope. Secondly, the dynamic changes of microscopic pore structure in shale hydration was observed at fixed points with the scanning electron microscopy to find out the correlation between induced micro-fractures and mineral components. Finally, the influence of hydration on the changes of shale physical properties was analyzed. The test results of shale sample from Longmaxi formation (LF) in the Sichuan Basin indicate the micro-fractures induced by shale hydration weremainly shale bedding fractures, with obvious directionality. Clay minerals play a leading role in the formation and expansion of induced fractures. After 10 days of hydration, the porosity can be increased by 2.1 times, and the permeability can be increased by 273.7 times. Therefore, an appropriate shut-in treatment can dramatically enhance post-fracturing performance. The research results can guide the optimization of flowback system and provide scientific basis for efficient development of shale gas reservoirs.
Digital Twin Implementation on Current Development Drilling, Benefits and Way Forward
Authors: Bimastianto Paulinus , Khambete Shreepad , AlSaadi Hamdan , Couzigou Erwan , Al-Marzouqi Adel , Chevallier Bertrand , Qadir Ahsan , Pausin Wiliem , Vallet Laurent 
Published: November 2020

Abstract
In the recurring need to optimize drilling operations and reduce costs, a full RTOC (Real Time Operations Center) solution was deployed as part of the organization structure. To bring accurate, automatic and relatable data capture from surface sensors, the RTOC introduced a digital twin approach to improve field to town collaboration. The paper will demonstrate the benefits brought to operations by the solution in terms of risk identification and lessons learnt.
RTOC digital twin solution integrates standard physical models’ workflows for hydraulics, torque and drag with advanced solutions using machine-learning algorithms. Capitalizing on operations recognition algorithm, the solution identifies thresholds and calibrates parameters to automatically classify operations into "Rig States" and "Drill States". The algorithm is trained to identify operational sequences and can derive complex measurements like downhole weight-on-bit and torque that are in turn fed into different workflows. This holistic event-based torque and drag baseline determination is used to define hole cleaning roadmap with minimum manual inputs.
RTOC receives, processes and publishes the real time data on through its platform for all drilling and completion operations. This continuous process has enabled drilling operations team to assess and intervene on a need basis thanks to the clear event identification it offers. Amongst the digital workflows, the hole cleaning roadmap, combines modelled and automatically identified torque and drag data points rendered and shared with the stakeholders to ensure the capture of deviations and framing of potential risks to acceptable levels through a common decision platform. The clear output of single identifiable drilling event (such as pick up, slack off and free rotating weight) provides constant fact-based data for an adequate protocol to run casings and liners and refine engineering designs. In turn it has enabled to break casing and liner run records in their different operating fields. The drilling efficiency roadmap rely on quantitative algorithm and reliable output of downhole weight-on-bit, downhole torque and mechanical specific energy with automatic calibration, without user intervention nor bottom-hole-assembly modelling, allowing to substitute actual downhole measurements. This has been a performance enhancer in the improvement of rate of penetration regardless of the availability of downhole sensors.
This new approach based on modern data science and digital twin based on a robust method, provides with a consistent and clear outcome regardless of service providers involved in the direct operations. It was trained, tested and validated prior to deployment, on more than 80 wells. This has also made possible the introduction of other algorithmic developments for Realtime dynamic modelling.
Automated Corrosion Mapping AI & Machine Learning
Authors: Majors Marc , Harrington Travis , Ferguson Eric , Dunne Toby , Potiris Steve , Vlaskine Vsevolod , Mohammed Jaffar , Bargoti Suchet , Naqshbandi Masood , Ahsan Nasir 
Published: November 2020

Abstract

Objective
Risk reduction and increased Fabric Maintenance efficiency using Artificial Intelligence and Machine Learning algorithms to analyze full-facility imagery for atmospheric corrosion detection and classification. Following imagery capture and processing, deficiencies are identified, and targeted mitigation strategies are executed at greatly reduced cycle time and cost.

Methods, Procedures, Process
A pre-mobilization facility scan plan is generated to maximize imagery quality, including high elevation scan positions, to ensure thorough and comprehensive analytics. Data from all scan positions are stitched together in a point cloud and aligned for accuracy relative to each location. Finalized imagery and point clouds are then tagged with unique piping line numbers per design, fixed equipment tags, or unique asset identification. The Machine Learning algorithm is intensely trained with manual ground truth inputs prior to analysis. The algorithm analyzes each pixel throughout the facility and detects, classifies, and reports on all identified corrosion, tagging faults to specific piping or equipment.

Results, Observations, Conclusions
Atmospheric corrosion is the number one Asset Integrity threat in the Gulf of Mexico. Utilizing this tool, we can have a comprehensive and objective analysis of a facility’s health in a matter of weeks from the time of data collection. Data collection for a large deep-water, spar facility requires approximately 12 days with 8 data scanning personnel. Conventional manual inspections incur higher risk, higher cost, and reporting is much less objective considering the number of inspectors involved and the duration of a full-facility campaign. Finally, all results are published in a user-friendly dashboard that can be filtered by process type, equipment type, corrosion severity, and many other criteria as the user requires. Each fault is associated with the specific equipment identification and the user can navigate to see the imagery of the corrosion in a 3D, photogrammetric environment. Remediation strategies can be collated into work packs for fabric maintenance teams, further Nondestructive Examination (NDE) assessment, or work orders for replacement. Fabric maintenance efficiencies are substantially realized by targeting decks, blocks, or areas with the highest aggregate surface areas of corrosion (on process equipment or structurally, as selected by the user) and concentrating remediation efforts on at-risk equipment.

Novel/Additive Information
This application of Artifical Intelligence and Machine Learning is a first-in-industry approach to having a comprehensive understanding of facility coating integrity and external corrosion threats. HSE analysis, Risk awareness, and targeted remediation strategies will make the Asset Integrity program more efficient, proactive, and reduce down-time across the Gulf of Mexico related to atmospheric corrosion.
A Novel Technique to Constrains kv/kh of Carbonate Reservoir, A Valuable Uncertain Parameters for History Match Process
Authors: Pamungkas Setiyo , Gueye Talla , Al Hammadi Fatema Yousef , Al Saadi Haleema Amer 
Published: November 2020

Abstract
A persistent challenge in reservoir modeling is to assign representative values for vertical permeability in reservoir models. It is a common practice to use kv/kh directly from the core measurements but this is not at the same scale as the model grid. It is also frequent to use one value for entire zones. The approach of using a single value applied to a single zone when the reservoir is heterogeneous is not correct and the same can be said regarding using core plug kv/kh as the grid scale is larger than the core plug therefore resulting in a difference in the statistical support of the two measurements.
This paper describes the technique to understand reservoir vertical connectivity by properly defining kv/kh, which later will be used as a matching parameter during the History Match process. Most of the time the data provided by the plugs is not appropriate due to the absence of vertical sampling or to problems of representativeness. Where plug data is available kv/kh ratios are often found to be close to one, a values too high to be realistic when considering the geological heterogeneity at small scale or plug scale. Even when plug measurements show homogenous at small scale (kv/kh ∼1), at grid cell scale the Kv and Kh are expected to be different (&lt;&lt;1). A methodology is proposed in order to give more appropriate ranges of values to the grid cell size, based on the small-scale permeability anisotrophy ratio (kv/kh) into grid cell size. A novel approach was established to get the ranges of kv/kh based on core mini-k measurements and core-plugs data.
This innovative workflow also considers a multi-disciplinary approach using Experimental Design methods to better understand and validate the kv/kh ranges. The main learning from this project is the importance of understanding vertical connectivity in a complex reservoir by properly capturing heterogeneity and other major geological features in the integrated 3D dynamic model with the aim to achieve an optimized history match at reservoir level but also more importantly on a well-by-well basis.
Gas Lift Well Operating Envelopes to Improve Production Operations: Field Applications in UAE
Authors: Mata Carlos , Saputelli Luigi , Mohan Richard , Rubio Erismar , Al-Attar Momamed Ali , Alhosani Abdulla , Al-Hosani Fatima , Reddicharla Nagaraju 
Published: November 2020

Abstract
Production operations in a modern oilfield production system becomes gradually more complex as the water cut increases and artificial lift is applied. To ensure production is continuously optimized, closer communication and a positive feedback loop are required between the petroleum engineer, the production supervisor and control room operators. ADNOC is developing a series of decision support systems to improve collaboration in production operations. One of the key systems consists of 2D operating envelopes charts for the gas lift wells, which relate the control variables of the wells, gas lift rate and production choke opening, with the expected flow behavior. The operating envelopes are visible in the control room and provide guidance to the operators on the stable production range of the wells, whilst leaving flexibility for adjustments, as the immediate production context evolves throughout the day.
The operating envelopes were computed by performing sensitivities on choke and gas lift settings on nodal analysis models of wells, chokes and flowlines, with different manifold pressures. The calculated rates and pressures are compared with a series of mechanical, reservoir and production constraints, to build the 2D envelope chart. The envelope shows the region where the well is in a stable and safe region, together with regions exceeding the maximum allowed casing pressure (MAWOP), hydrate formation, flowing below bubble point, exceeding allowed rates, tubing + flowline erosion, casing heading and tubing heading. The current operating point is shown in the chart, together with the recommended optimum setpoints.
Production operations use the system as a guidance tool to control the wells. The petroleum engineer is expected to keep the well models up to date, to make the operating envelopes robust. On the other hand, the operators are expected to test the wells frequently, to ensure the good quality of the models. Around 2-5% of oil production increase is expected from the continued use of this framework.
Advanced Combination of Proppant Fracturing and Sand Control Completion System Unlocks Gas Potential of Unconsolidated Jauf Formation in Bahrain
Authors: Prasad Vineet , Sultan Hussain , Al-Rumaidh Ahmed , Fateh Ahmed , AlTarif Nazar , Yudin Alexey , Md Noor Mohd Nazri , Fortuna Francisco , Guleryuzlu Metin , Al-Jalal Ziad 
Published: November 2020

Abstract
The Jauf formation of Bahrain's Awali brownfield is currently underdeveloped due to an extremely challenging geological environment. Because of high heterogeneity, the formation requires fracturing to produce economically. However, the Jauf sandstone is unconsolidated, and formation sand production does not allow for high gas rates. A combined solution was introduced using a completion assembly with frac ports and screens to restrict sand production with a tip screenout approach in the stimulation stage.
The studied well was completed with a 4 1/2-in. cemented liner that had been plugged and abandoned and left with 7 5/8-in. casing across the prolific Jauf sandstone. A completion string with screens and production sleeves, fracturing ports, and packers was deployed to compartmentalize and fracture the Jauf. Fracturing ports, while production sleeves were later manipulated with coiled tubing (CT) to allow production across the sleeve filter media, thereby preventing proppant or formation sand from being produced. A large fracturing treatment was placed in an aggressive tip-screenout mode to achieve optimum fracture length and maximize fracture conductivity. Afterwards, CT was used to close the fracturing port and open the screen ports to flow back the well and proceed with testing operations.
A hydraulically activated shifting tool was used to manipulate the fracturing ports (open and closed) as well as the production ports enabling gas production through the included screens. This technology enabled the fracturing operation to be executed in conjunction with sand management hardware during production, further providing more flexibility for future intervention operations when compared to frac-and-pack type assemblies. Considering the significant depth of the formation (11,700 ft), degradable fibers were used to minimize friction pressure and, respectively, maximize fracturing treatment rate to allow for optimum height coverage and lateral fracture penetration. The post-stimulation sand-free gas production rate through the screens was greater than 20 Mscf, which was confirmed with choke-variability testing operations conducted after manipulation of the completion ports. The trial well proved that proppant fracturing combined with innovative sand control hardware provides an effective method for producing gas from the prolific Jauf reservoir.
The described completion system represents an alternative to a traditional frac-and-pack hardware solution, enabling full control of the well with CT interventions. A tailored stimulation design and advanced placement technique coupled with detailed description of completion design and operations sequence will be of interest to experts dealing with tight unconsolidated formations in the Middle East and other regions.
Maximizing Liquid Recovery in Oil & Gas Processing
Authors: Karam Stéphanie , Valand Bhavesh N. , Aggarwal Rajdeep , Singh Harendra , Kamal Faris , Takieddine Oussama H. 
Published: November 2020

AbstractLiquid Product Recovery is an important metric to assess the quality of Gas and Oil Separation plant design and is required to be achieved at minimum CAPEX & OPEX to improve the overall economics. This paper presents a structured approach for an optimal solution to minimize loss of valuable components to the gas phase, thereby maximizing liquid recovery.Ideal Liquid Recovery is defined as the theoretical maximum liquid recovery possible by successively separating the lightest components from the well-fluid until the crude oil specifications are met, i.e. separating all the Methane (C1) and Ethane (C2), just the right proportion of Water, Propane (C3) and H2S to meet the specifications. In real life separation systems, however, such sharp separation is unachievable, i.e. some amount of intermediate and heavier components are likely to migrate to the gas phase and some of the lighter components may end up in the liquid phase. Accordingly, %Liquid Recovery is defined as: %Liquid Recovery=Actual Liquid RecoveryIdeal Liquid Recovery×100Oil and gas production is a complex process wherein many equipment and systems are closely coupled and interdependent. The art of designing an optimal process for Gas and Oil Separation plants lies in rigorous selection of appropriate process configurations and operating conditions. The design largely depends on several factors such as fluid compositions and properties, product specifications, etc. There is no single configuration or set of process conditions that can be the solution under all scenarios; thus each case requires to be analyzed independently.This paper uses a structured approach to evaluate the impact of each parameter individually as well as collectively, to select the optimum process configuration for separation and stabilization of the crude oil. A Gas and Oil Separation plant with multiple stages and a stabilizer column is used to demonstrate that the liquid recovery for a specific well-fluid composition can be maximized by varying separator operating conditions, column operating parameters and process configurations. The focus of the paper is on the ‘Design Process’ to achieve and assure an optimal design as well as understand its limitations.The suggested design approach demonstrates that liquid recovery values in excess of 95% can be achieved in comparison to typical liquid recovery values of around 93% for low GOR oil production plants. Even two percent increase in liquid recovery is quite significant, as on a 100,000 STBOPD plant it translates to 2,000 STBOPD production gain which is equivalent to more than US$ 33 million per year in additional revenue at crude oil price of US$ 50/bbl. This should be read with a caveat that incremental absolute revenue will be lower in a smaller capacity unit and hence, additional CAPEX, if any, should be evaluated accordingly. Higher liquid recovery also contributes to improvement in API gravity of the crude, and thus further adds to its value.
Utilization of the Innovative A.S.C. Technology for 24/7 Solar Enhanced Oil Recovery
Authors: Al-Maaitah Ayman 
Published: November 2020

Abstract
The objective of this paper is to demonstrate the usage of the innovative ASC technology on low cost storage of solar thermal energy to generate high pressure steam for 24 hours a day and 7 days a week to be utilized in Enhanced Oil Recovery (EOR). The technology is patented, simulated and tested at Masdar Solar Platform in Masdar City- Abu Dhabi. Simulation showed that the solar radiation is concentrated by thousands of times allowing for high temperature hot air receive fixed to the ground. The heated air will then be used to store thermal energy in low cost compact bed refractory materials or even bedrocks. Thermal energy can be retrieved upon demand and high-pressure steam can be generated to be utilized in Solar Enhanced Oil Recovery. The concentration of solar energy at a fixed focal point allows easy storage and utilization of solar energy. Temperatures at around a Thousand Degrees Celsius were obtained even at low solar radiation which allows energy to be stored in low cost compact bed and high-pressure steam can easily be generated even during night. Financial and technical feasibility of the system is being investigated. The system is self-cleaning and has low wind resistance hence not needed to be placed inside a glass house. The temperature and energy of the hot air is measured in various weather conditions and is simulated to be stored in a compact bed refractory ceramic materials. The size of the system is scalable and modular hence it can meet the demand for any scale. The novelty of this technology is of its low cost and ability to store solar energy cheaply to supply it upon demand.
Stimulation of Oil and Gas Wells in Carbonate Formation by Using Supercharged Nanoparticles
Authors: Sergeev Vitaly , Tanimoto Kenji , Abe Masashi 
Published: November 2020

Abstract
An article presents results of comparative analysis for evaluation of effectiveness of classical stimulation technique and innovative technique applied in the same mature carbonate oil-gas formation within two years. An innovative technique is based on a two-stages treatment of bottom-hole zone of production well with chemical compositions characterized by different impact onto the oil and gas bearing formation: water-blocking agent; water solution of acid-surfactant composition. An application of a new water-blocking agent – emulsion system with supercharged nanoparticles (ESN) as a first step of well treatment solves two following tasks: diversion of acid composition and long-term blockage of water bearing most permeable intervals of the formation thickness. The ESN is characterized by unique physicochemical properties such as high thermal stability, stability under filtration in porous media, enlarged surface activity, self-regulated rheology and reversibility of blocking effect. A combination of these properties in one solution makes positive impact on an efficiency of stimulation technique resulting in a redistribution of permeability profile within reservoir thickness and moderation of water-cut under increased fluid rate. A classical stimulation technique considered in this article is a one-stage treatment of production well by water solution of hydrochloric acid. Mature carbonate formation of Abdulovskoe oil-gas field considered in this study is found in Ural-Volga oil and gas province, Russia. The Abdulovskoe oil-gas field is under industrial development since 1970, and to date remained recoverable reserves are highly deteriorated. Moreover, the formation rocks are characterized by relatively high net sand coefficient (0.26), low porosity (0.10) and low matrix permeability (0.02 μm2). The net of natural fractures caused noticeable wells interference between the producer-producer as well as injector-producer, which complicates the oil-gas formation development process.