bluuebunny/crossref_metadata_2025_split huggingface dataset:
Supervised Machine Learning in Predicting Multiphase Flow Regimes in Horizontal Pipes
Authors: Alhashem Mayadah 
Published: November 2019

Abstract
The petroleum industry has been undergoing transitional changes that were mandated by the high competition in the business. Making decisions and engineering approaches grew from being trial- and-error, educated guesses, well-studied designs, to finally creating advanced and well developed models and simulations. Yet, the development of approaches has been and will always be rapidly ongoing. In order to stay competitive, the approaches must be constantly improving.
This study was performed as a proof-of-concept to assess and prove the practicality of using supervised machine learning (ML) techniques to predict multiphase flow regimes in horizontal pipes. The flow is comprised of air, water, and oil. The input features used were water cut (the percentage of water), gas superficial velocity, and liquid superficial velocity. The predicted output was one of six possible flow regimes. The algorithms assessed in the study were Decision Tree, Random Forest, Logistic Regression, Support Vector Machine (SVM), and Neural Network Multi-Layer Perceptron (MLP). According to the results, the best candidate for the dataset is to use the random forest algorithm with a high accuracy of 90.8% and low training time (0.13 seconds) in case of increasing the size of the data and features.
All the predictive algorithms can be easily improved in accuracy by increasing experience, either increasing the size of the dataset or addition of relevant features. The trained model and logic can be applied in industry by automating flow control or installing prediction and mitigation systems in pipelines and field operations.
Oil Spill Detection, Thickness Evaluation with Radar, Optical and Infrared Sensors
Authors: Vinther Morten Loell 
Published: November 2019

Abstract
Leveraging dry wave monitoring technology to detect oil spills can contribute to quicker and more cost-effective oil spill rescue operations than leveraging in-water solutions or laser technology. Using X-band radar-based technology in combination with infrared-cameras is a proven method which supports both oil-spill surveillance and response. This technical paper highlights the physical material properties that make oil spill detection possible with a combined system of x-band radar technology and infrared cameras.
Challenges of Ethylene Process Compressor Trains: From Design to Start-Up and Operability
Authors: Corbò Simone , Calosi Mirco , Acquisti Gianni 
Published: November 2019

Abstract
This technical presentation features various challenges that a turbomachinery OEM and the end users face with compressor trains in Ethylene Process, from the initial design phase, to the plant commissioning and operation of these machines.
The presentation illustrates also the possible technical solutions, such as special coatings to prevent fouling in charge gas compressors, to help end users to reduce the operating cost and risk of production loss. The implementation of compact solutions, which helps the charge gas and ethylene compressors to deliver a higher-pressure ratio in one casing, results in lower number of bodies with same compression sections and consequently simplified installation and lower costs. Technical and special design features will be illustrated during the presentation.
A smoother operation of the units can be offered building a dynamic model capable to simulate the behavior of the drivers, compressors and process plant items, in stable operating conditions and transient phases. With such model, any potential criticality of the interactions between process and compressors can be identified up-front in a simulation environment, minimizing risks at site, during commissioning and first start-up.
The impact of fouling on ethylene plant equipment can be substantial. The high possibility of gas polymerization occurring in the cracked gas compressor can lead to efficiency loss and unplanned outages with associated lack of production. An advanced stage-by-stage water injection system coupled with fully removable nozzles during compressor operation and an efficiency monitoring and control system, will reduce operating cost and risk of production loss by providing operators with continuously updated equipment performance. This information can also be integrated with the analytic that performs an early detection of steam turbine fouling phenomena.
Finally, the authors present few case studies where the above strategies were successfully implemented.
Reaching Target Depth with Zero NPT in an HPHT Tight Gas Well: A Case for Automated Managed Pressure Drilling
Authors: Khalid Ali , Ashraf Qasim , Luqman Khurram , Hadj-Moussa Ayoub , Sheikh Daoud , Zafar Saad 
Published: November 2019

Abstract
As shallower reservoirs are driven to depletion the world over and the world energy demand keeps growing at a steady pace, operators explore for deeper horizons within current fields in hope of making significant discoveries. Deeper exploration in most fields entails significant risk, and a much higher cost per well.
With deeper drilling depths comes tougher drilling challenges, mostly arising from higher pressures and higher temperatures at those depths. High-pressure, high temperature (HPHT) wells present numerous drilling risks, often including influxes while drilling into over-pressured formations, insufficient mud weight and bottomhole pressure control due to bottomhole density reduction with high temperatures, late kick detection due to low permeability formations, swabbing from the formation due to an insufficient trip margin, losses due to high equivalent circulating densities (ECD's), differential sticking, and stuck pipe following extended periods of well-control events.
It is thus of paramount importance for the operator to minimize the associated risk, time, and cost on all HPHT wells.
One such field in Pakistan where the target formation is a high-pressure shale in the Lower Basal Sand Reservoir, which is potentially a tight gas reservoir. This shale formation is known to be over-pressured, with a pore pressure of 18.6 ppg equivalent mud weight (EMW). The estimated fracture pressure of this formation is 19.2 ppg EMW, which results in a narrow drilling window. When an offset well in the field was drilled conventionally, it was plagued with severe well control issues, lost circulation, and stuck pipe events due to ineffective ECD management with a conventional mud system. The operator spent a total of 45 days to regain control of that well.
The operator for the subject well therefore intended to deploy an automated managed pressure drilling (MPD) system to drill the target section with minimal nonproductive time (NPT). The MPD system was expected to facilitate drilling the section with minimal overbalance and compensate the required bottomhole pressure (BHP) with the application of backpressure. The automated MPD system would also account for mud density variations with a high bottomhole temperature (BHT) by executing an advanced well-hydraulics model in real time. Furthermore, the MPD system would provide early kick detection and reaction to well control events.
The operator, in addition to drilling, intended to collect three whole cores while drilling with an MPD system.
Through the application of an automated MPD system, the operator was able to reduce the NPT to practically zero, and successfully achieve target depth and collect the three desired cores.
The paper discusses the planning, wellsite execution, results, and lessons learnt by the application of an automated MPD system in the subject field.
Running Sour Hydrocarbon Assets: Eni's Story of Experience
Authors: Scataglini Luciano , Decarli Luca 
Published: November 2019

Abstract
Eni has more than 40 years' experience on developing and managing sour hydrocarbons Projects. That has allowed to build up in Eni a specific knowhow, which is continuously improving and updating through operational activities on assets with an high concentration of H2S in the process fluids such as Karachaganak and Kashagan in Kazakhstan, COVA in Southern Italy and the more recent Zohr facilities in Egypt.
The Eni's acquired knowledge in running sour hydrocarbon assets, both offshore and onshore, has been founded on a robust risk based approach. Since the project start, risk assessments such as blowout study, Quantitative Risk Assessment, Emergency Escape Rescue Analysis, etc. results are considered the pillars for the proper design, construction, commissioning, start-up and operations phases. Specifically, SIMOPS/CONOPS methodologies and procedures and their applications in sour operational contexts are defined for managing sour hydrocarbons assets and activities.
Achievement of Maximum Mud Weights in WBM with Micromax/Barite Blend and its Successful Implementation in Deep HPHT Challenging Environment
Authors: Sindi Rami , Pino Rafael , Gadalla Ahmed , Sharma Sunil 
Published: November 2019

Abstract
The use of water based mud (WBM) in drilling applications under extreme Pressure and temperature has been increasing rapidly in the drilling industry over the past few years. It is now more crucial to close the technological gap that presents challenges towards developing high Density water based mud systems for High Temperature High Pressure (HPHT) wells. These challenges include rheology control, weighting agents sagging tendencies associated with high down hole temperature, In addition to the high solids loading which limits the free water availability impacting polymers performance and therefore, rheology, HPHT fluid loss and filter cake thickness control become an issue that requires special optimization and extra field maintenance. Operating under narrow margin between pore pressure and fracture initiation pressures adds to the complexity of the drilling fluids maintenance where a slight change in the bottom hole pressure (BHP) could lead to significant increase in the non-productive time "NPT" due to the time spent in solving possible fluid losses and kicks.
This paper discusses the outstanding performance achieved in a deep HPHT formation drilled using water base mud weighted with Manganese Tetroxide (Micromax)/Barite blend, from planning and extensive lab testing to field implementation. This paper also describes and compares the methodology of using Micromax/Barite versus using barite only as the weighting agent and finally the field results.
State-of-the-Art Plant Operation Combining Kaizen & Digital Technology and the Challenge for LNG Value Chain Optimization
Authors: Arai Toru , Otawara Yuki 
Published: November 2019

Abstract
A prosperous business player must gain a competitive advantage over other companies to survive and dominate the market. In Japan, electricity market has progressively started its liberalization in 2000, and full liberalization in 2016 allowed all consumers to freely choose the power retailer.
In response to these dramatic changes in the business environment, we have proactively introduced KAIZEN and digital technology to gain a competitive edge. KAIZEN was introduced in Japanese automobile manufacturing and based on the philosophical belief that "nothing is seen as a status quo and everything can be continuously improved by racking one's brain." Simply saying, it is an initiative to improve efficiency value-adding work, and to eliminate non-value-adding work and waste & loss which we can not recognize. In addition, the advancement of digital technology enabled us to analyze the big data which we have storaged from the past more easily and in more detail.
As a result of introducing of KAIZEN and digital technology, the periodic inspection of thermal power plants has been shortened by over 40 %, and maintenance costs have been reduced by over 30 %.
This paper illustrates the details of our initiatives implementing KAIZEN and digital technology and our challenges in optimizing the LNG value chain applying the KAIZEN knowledge.
A Game Changer for Injection Wells Outflow Control Devices to Efficiently Control the Injection Fluid Conformance
Authors: Mohd Ismail Ismarullizam , Konopczynski Michael , Moradi Mojtaba 
Published: November 2019

Abstract
A new autonomous outflow control device is developed to choke back the injection fluid into natural/induced fractures and mitigate the disproportional injection of fluid into the thief zone and potentially creating short-circuit to the nearby producer wells. This paper will present an overview of the flow loop performance testing, and demonstrates the design consideration and integration with completion design and its benefit by reservoir modelling.
The bi-stable devices should be installed in several compartments in the wells and operate as normal outflow control valves initially. When the injected flowrate flowing through a bi-stable valve exceeds a designed threshold, the bi-stable valve will autonomously move to another position to choke back the injection of fluid at that specific compartment. This allows the denied fluid to be distributed among the valves installed at neighbouring compartments. This performance enables the operator to minimise the impacts of natural fractures on the injected fluid conformance and to control the growth of thermal fractures while improving the efficiency of the injection well systems.
The flow performance of the bi-stable valve has been validated and the flow behaviour can be simulated in the reservoir model. Static flow modelling has been used to establish the valve setting and packer placement in the well section and to demonstrate an improved distribution of the water injection and the effect of restricting water to the thief zone on the nearby producer oil recovery.
A reservoir modelling method has been established to evaluate the bi-stable device performance in reservoir environments and compared with outflow control devices (OCDs) and open hole completions. Due to the uncertainty of heterogeneous reservoirs and the potential for dynamic changes of injection properties, the simulation study showed that with a lower pressure drop compared to OCDs, the fluid front can be managed more efficiently to achieve the desired sweep and maximised ultimate recovery.
The first autonomous injection valve that restricts water into dilated/propagated fractures is developed. This device removes most of the deficiencies of OCDs and eliminates the requirements of running PLT and the prescribed well interventions e.g. closing/opening of sliding sleeves. Instead, it provides operators with a tool that enables the optimised completion to deliver optimum water injection techniques autonomously.
Innovative Solution to Automatically Import Well Production Profile Data into Process Simulation
Authors: Hassan Eman , Loretelli Giorgio , Singh Harendra , Kamal Faris , Takeidinne Ousama 
Published: November 2019

Abstract
EPC Contractors face the challenge of practicing/doing various activities that in most cases include some routine work (e.g. well characterization in Process simulation that requires extensive data entry, etc.). This routine work can be minimized by using developed automised solutions. These solutions will help to perform the above tasks as well as other tasks with higher efficiency and accuracy, less time and minimal errors while the Process Engineer will focus on more valuable tasks.
The Production Profile is one of the most important documents provided in any EPC stage since it is the basis for Process activities like simulations.
As per normal practice, the Process Engineer is requested to characterize each well in HYSYS using a no. of separation stages that depends on the project requirement. Well characterization includes finding the choke valve inlet flowrate and composition at the operating conditions using the productivity data. Productivity data includes the flowrates at Stock Tank Conditions and the reservoir composition. This task requires an extensive data entry since all wells have to be characterized for various production years. Moreover, any revision of such document may require an extensive re-work.
Performing Process simulations for an upstream project can be a challenging activity due to the possibility of having a high No. of wells that may need to be characterized in HYSYS. Moreover, the well characterization in HYSYS requires the input of oil/gas/water and gas lift productivity data in dedicated adjust blocks. For example, in a project having 100 wells and 4 governing cases, the No. of data that needs to be entered is 1200. This activity needs to be performed by the Process Engineer by reading the production profile and enter its data manually in HYSYS.
NPCC has developed a new software whose scope is to:Import the Production profile in a standard templateProvide a track change for any production profile revision.Provide the governing cases (Max. Oil/Gas/Water) and their relevant production years for individual wells/Flowlines/Trunklines/Pipelines as well as the overall production.Automatically export into HYSYS the production rates that need to be used for well characterization.
With the above software, the following benefits are achieved:Reduction in manhours.Increase in efficiency.Minimum supervision from Process Engineer is required.Reduction of mistakes/human errors.
This paper demonstrates that saving in manhours/manpower is achieved by interfacing EXCEL and HYSYS through VBA. Dedicated software has been coded to import the production profile provided during FEED/EPC stage in a more presentable and organized format that can be sourced to HYSYS. This will help in facilitating process simulations as well as achieving higher efficiency in Process activities.
Integrated Reservoir Study to Maximize Oil Recovery by Optimizing Shuaiba Dump Flooding into the Kharaib Reservoir
Authors: Mahmoud Ahmed , Khayami Abdulla , Mansoor Mohamed , Buasali Mohamed 
Published: November 2019

Abstract
A significant number of Kharaib horizontal and deviated producers drilled over the last decade have suffered from casing leaks, with many occurring in the first two years of production due to the exposure to highly corrosive water from the overlying giant water-bearing formation known as Shuaiba formation, resulting in production losses and water dumping from Shuaiba formation into the Kharaib reservoir through these damaged wellbores. This paper investigates the impact of Shuaiba dump flooding on the Kharaib reservoir’s performance, the integrated reservoir management study that was conducted and the implementation of the study’s findings to achieve the best results.
Severe casing leaks are the main production problems facing the Kharaib reservoir. A few repairs were attempted initially, however, high costs and failure rates led to a decision to cement squeeze all remaining casing leak wells, recomplete them in shallower reservoirs, and drill new replacement wells. All new Kharaib wells were designed with an extra casing to protect against the Shuaiba reservoir’s corrosive water. Although there are no longer any casing leak wells in Kharaib, their impact remains. The pre-casing leak production numbers and well counts are yet to be matched, and there is a large volume of hydrocarbons to be produced from the Kharaib reservoir. In addition, wells that are offset of old casing leak wells showed an increase in water cut, while the performance of new wells drilled down-structure of casing leak wells suffered from early water breakthrough. There is also strong evidence that the isolation in many casing leak wells, performed during the recompletion workovers, may be unsuccessful. All these factors indicate that dump flooding is likely ongoing in the Kharaib reservoir.
The consequences of dump flooding have not all been negative. An increase in average reservoir pressure and a strengthening of the reservoir’s weak water drive mechanism were observed. Currently, many wells have shown an increase in oil production, while other wells have shown steady oil production with a very gentle decline which is particularly reflected in wells located up-structure of the casing leaks. As a result of the study, many wells have been drilled in carefully selected locations in order to take advantage of the flooding, and the results of the study concluded a sustained production with a low water cut. Moving forward, there are further opportunities to increase the recovery factor by mitigating the unwanted effects of Shuaiba dump flooding and utilizing the phenomenon to its best potential.
Maximizing Conversion of Residues to Chemicals and Clean Fuels
Authors: Biswas Goutam , Chabot Julie , Gillis Daniel 
Published: November 2019

International Maritime Organization’s Marine Fuel Rule, or IMO 2020, is just around the corner. Few refineries are ready for the change to bunker fuel specifications caused by IMO 2020 where marine bunker fuel sulfur content will be reduced to 0.5 wt% from current 3.5 wt%. Many refineries around the world, who currently produce about 4 million barrels per day of high sulfur bunker fuel stocks, still need to invest in upgrading technologies.
In the past Visbreaking was used to make Residue Fuel Oil (RFO) as it reduces the viscosity of the resid by thermally cracking the heavy molecules, thereby minimzing cutter stocks. It also has a relatively low capital and operating costs compared to other residue upgrading technologies. However, it concentrates contaminants (sulfur, nitrogen, and Conradson Carbon Residue (CCR)) in the product. As a result, it is not considered a viable solution for RFO sulfur reduction.
Fortunately, there are several technologies available to upgrade the high sulfur residuum oil to high value products or low sulfur fuel oil as shown in Figure 1. The benefits and features of each of these options is discussed in this paper to provide an understanding of the various processes’ merits. Case studies are also provided to provide indications of which technologies are best suited depending on the specific scenario.