bluuebunny/crossref_metadata_2025_split huggingface dataset:
How to Verify the Performance of a Flowmeter in Field Conditions Against Another Device
Authors: Pinguet Bruno , Pieper Anna 
Published: November 2020

Abstract
Multiphase and wet gas flowmeters (MFMs) are becoming drastically cheaper, allowing the capability to be used by most of the oil and gas companies today. If the CAPEX can be reduced, the main question about the reliability and the capability of such equipment to provide accurate data and to perform correctly compared to previous technology (usually a separation-based system) remains. The unrealistic specification of multiphase manufacturers made in the past led to suspicion of such products by oil and gas companies. Additionally, the reluctance of using MFMs could be due to a number of technologies that require significant effort to have a proper understanding of the device.
The buying process very often leads to some form of comparison test made either before delivery (usually tested in a third-party facility), or later in the field regularly or spot check against standard equipment (separators, tanks or any other trending devices). This fair initiative to understand the real performance usually leads to more questions about what/how/where/when to compare and are also incredibly important. Last but not least, what should define the "PASS/FAIL" criteria? It should also be noted that limited test envelopes (flow conditions) may not reflect the entire performance of the meter. Therefore, either additional measurements or statistic elements should be used to establish the actual statement or meter performance.
It is incredible to see, today, in the billions of dollar oil and gas business that most of the systems are reporting flow rates without any information about the measurement uncertainty, this leads to the belief that the production is entirely known. Unfortunately, people working in allocation are the first to face this challenge and to reconcile the data. On the other hand, the top-class MPFMs are providing uncertainty on measurement, which is as good as, if not better than, some of the standard equipment that is used and so the uncertainty of both devices needs to be thoroughly taken into account in these comparisons to make allocation fair and indisputable.
The paper will embrace these comparison tests, the author has repeatedly faced such cases over the years and wishes to bring to light the relevant work that needs to be done before, during, and after the tests to make it conclusive. We expect to provide some practical statements which will progress and help all parties involved in these comparison tests where the presence of a third party (being impartial and independent) can ensure there is no bias in the overall statement.
Predicting Just in Time: Prognostic Health Management for Oilfield Equipment.
Authors: Bannikov Denis , Lyapunov Konstantin , Pantsurkin Danil , Parkhonyuk Sergey , Velikanov Ivan 
Published: November 2020

Abstract
Delays in the hydraulic fracturing stimulation process due to equipment issues may result in Non-Productive Time (NPT) and often associated with high costs. Both operators and service companies are interested in implementing a system to predict these events in advance so that they can proactively react and prevent failures before they occur. Our objective was to develop, implement, and demonstrate the capabilities of such a system.
Based on historical data, we identified the most NPT-prone subcomponents of stimulation equipment. We combined failure reports and maintenance records with sensors data to train Machine Learning (ML) models. The final solution was deployed on the cloud to predict remaining useful time (RUL) in real-time and to start specific notifications sending whenever RUL dropped below the preset value.
We analyzed 20,000+ failure records and identified the most NPT-prone equipment, subcomponents, failure modes, and root causes. We found out that root causes are very scattered. We evaluated the applicability of physics-based and data analytics approaches for Top-10 root causes by NPT duration and NPT count. When NPT count per root cause is low (&lt;10), the trained ML models had insufficient accuracy. In this case, only subject matter experts and understanding of physics behind performance deterioration allowed us to boost data-driven models’ accuracy. We started with testing on historical data. Then we continued testing on real-time data without field intervention. This stage was required to check and to build trust in the predictive ability of the models. After initial testing, we eliminated some of the models and switched to monitoring with field interventions. For six months of operating, the model helped to decrease the NPT related to the selected subcomponent by 20 times.
This work presents the process of enabling Intelligent Diagnostics for hydraulic fracturing equipment by implementing failure identification and prediction models. It combines both domain knowledge (failure modes of the equipment, sensors data) and recent advances in ML (time series analysis, data processing, and feature engineering). The developed system to be further extended to different equipment, as the workflow described in the present study is not specific to particular equipment.
Pressurized Mud Cap Drilling Replacing Floating Mud Cap to Reduce Drilling Risk and Optimize Mud Consumption
Authors: Ullah Syed Zahoor , Ruzhnikov Alexey , Prasetia Andi Eka , Al-Fakih Abdulqawi , Almomen Mohammed Sami 
Published: November 2020

Abstract
Unmanageable losses through carbonate formations led to pumping water through the drill pipe and heavy mud cap in the annulus to drill with total losses. Although this technique overcomes the need to fly mix drilling fluid, it adds the complication of pumping heavier mud cap into the annulus. Pressurized Mud Cap Drilling (PMCD) was introduced the first time in the project to eliminate the requirement of mud cap for improve wellbore condition, efficient well control and to optimize the overall cost while drilling with total losses.
As mud cap density increases based on reservoir pressure, so does solids concentration in mud cap. Apart from mud cap getting extremely expensive at higher densities, it deteriorates hole condition due to continuous addition of solids especially for horizontal wells where solids keep piling up on the low side of the wellbore. With total losses in the reservoir, drilling is followed by image log, followed by reaming run and finally open hole completion runs to isolate those fractures.
On wells where higher density mud cap was used, severe hole problems leading to stuck pipe were faced either during logging or open completion runs. On most of the occasions, solids of mud cap have been proven as the root cause for worsening the situation.
PMCD has been introduced as a solution to such high-pressure wells to drill and complete them with total losses more efficiently and cost-effectively. It not only reduces the volume of solids dumped in the wellbore in the form of mud cap thus improving the hole condition but also saves the immense cost of mud cap which is especially massive for long laterals while dealing with long reaming operations.
The above motivation of finding a solution for drilling in total loss environment emerged from one of the wells where pipe conveyed logging string (TLC) got differentially stuck while pumping a 90 pcf mud cap. The pipe could not be recovered even after cutting it inside the casing shoe confirming it was packed off with solids laden mud cap. The well was sidetracked and was completed with PMCD successfully without any complications. After that job, PMCD has been implemented in five other land wells successfully and being recognized as standard practice for drilling high-pressure wells with total losses.
This paper illustrates the challenges faced by turn key project team due to total losses and drilling with mud cap, and overview of PMCD procedures, comparison of mud cap and the inherent advantages of PMCD over mud cap drilling. It provides details of the well which could only be recovered using PMCD after sidetrack due to stuck pipe.
Seismic Attributes for Channels Identification and Facies Modelling Application in a Siliciclastic Onshore Reservoir, Kazakhstan, Central Asia
Authors: de Sousa Ana , Bizarro Paulo , Ribeiro Maria Teresa 
Published: November 2020

Abstract
Seismic attributes often provide support for identification of several important parameters that could be applied in geomodelling for constraining reservoir properties such as porosity, permeability and fluid saturation. Additional insight can be gained as a way of detecting depositional features and geometries, and improve qualitative (e.g., data quality, seismic facies mapping) and quantitative analyses (e.g., net sand, porosity prediction).
The case study is a deep gas bearing Jurassic fluvial channel sandstone reservoir in an onshore field in Kazakhstan, Central Asia. The data set is scarce, with only a few wells penetrating the reservoir. The available 3D seismic data is weak to a reasonable quality, and an attempt was carried out to use a series of attributes for channel identification and imaging. After testing several attributes, only two of them have shown good results: Generalized Spectral Decomposition (GSD) and Variance. Geobody extraction was also tried, but the seismic quality was not sufficient enough to further pursue such methodology.
To overcome this issue, a joint approach for channels detection and extraction was tested by looking at the variance attribute in time slices and applying a workflow for an alternative way. With this technique (Alternative way for extracting geobodies), the facies property was generated in zones where the information was limited. The implementation of this approach, together with core facies interpretation has allowed a way of constraining other properties (e.g. porosity) and undoubtedly increased the robustness of the static model. Such model will support a more accurate estimation of HIIP volumes, future decisions on the most proper development plan and also investment decisions.
The alternative way for extracting geobodies was tested in two channels examples and for different zones in Jurassic reservoir with success. The described workflow helped in channel extraction and it can be used in facies modelling when the reservoir data set is scarce. A more robust facies model can be generated by combining the seismic attribute results with well data.
Accurate Reservoir Characterization in Multi Barrier Well Bore Systems with an Advanced Multi-Detector Pulsed Neutron Logging Technology
Authors: Elyas Mohamed , Freile Daniel Agustin , Tagarieva Larisa , Abu-Eida Abdullah Ibrahim , Al-Azmi Nasser Hadi , Patra Milan Kumar , Al-Sabea Salem 
Published: November 2020

Abstract
The five detector pulsed neutron (FDPN) tool is one of the most advanced tools in cased-hole reservoir evaluation. The evolution of multi-detector pulsed neutron tools (MDPN) created a turning point in the methodology to properly handle the different challenges within petrophysical cased-hole evaluation either in conventional or unconventional formations. This study demonstrates the applications of the FDPN tool and the methodology to handle the challenges in the multi-barrier well bore systems.
The FDPN tool was used in two double-barrier well bore field cases in addition to one case with a triple casing system. Each case was unique in terms of objectives and challenges: Case 1 (13.375 inch, 9.625 inch and 7 inch casings) aimed to estimate the presence of gas in the annulus between the two casings and the formation gas behind the double-barrier wellbore system, while Case 2 (7 inch liner and 4.5 inch ICD) required to perform a three-phase calculation. In Case 3 (13.5 inch, 10.75 inch and 7.625 inch casings) diffusion-corrected sigma was recorded to be able to determine the water saturation in a triple casing system. In all these case studies, Monte Carlo simulations (MCNP) were performed to characterize tool response and to determine if the data to be recorded will achieve the objectives of these jobs.
In Case 1, the FDPN tool helped to establish the presence of gas in the annulus between casings and determined the gas saturation profile in the formation using the difference between the normalized capture and inelastic ratios. This case was unique since other MDPN tools were not able to quantify the volume of gas in the formation due to their lower gas sensitivity. In Case 2, the objectives were successfully achieved. Also, it was possible to differentiate between the formation gas and the gas pockets between the 7 inch liner and the 4.5 inch ICDs using the comparison between inelastic and capture measurements. In Case 3, a diffusion-corrected sigma was measured and identified formation water movement in the zone of interest which helped to make a decision about drilling of the offset well.
The FDPN tool provides a higher spacing between the detectors and neutron generator which gives a better quantification of hydrocarbons especially for large casing and borehole sizes. Furthermore, the spacing between the long and proxy detectors is increasing the gas measurement sensitivity compared to other MDPN tools. Also, the 1.69 inch pulsed neutron logging tool was successfully run for first time in Kuwait to record diffusion corrected Sigma over a triple casing interval.
Development of Oriented Fracturing of Chemically Induced Pressure Pulse for Unconventional Gas Reservoirs
Authors: Al-Nakhli Ayman 
Published: November 2020

Abstract
Commercial production from unconventional reservoirs require new technologies to reduce the breakeven cost. Multistage fracturing was an enabler of gas production from such reservoirs; however, it is responsible to significant cost. Fracturing jobs cancelation, due to high pressure, results in non-productive wells, which also represent high cost. Moreover, unfractured wells results in locked and unproduced potential gas.
One of the major challenges that is faced by fracturing companies is the high breakdown pressure of such reservoirs, which exceeds tubular and pumping pressure limitations. This results in non-fractured wells. A recently developed technology is chemically-induced pressure pulse, where exothermic reaction is triggered in-situ to generate pressure pulse sufficient to fracture the formation. Initiated fractures, then propagated with hydraulic fracturing. This paper study the generated fractures, using chemical pulse, on confined and unconfined conditions. Moreover, the study shows a successful new techniques of orienting the pulse fracturing.
The objective of developing a new method of orienting in-situ pressure pulse is to increase the stimulated reservoir volume in unconventional reservoirs, and ultimately enhancing commercial production. The technology will also enable fracturing high-stress rocks, deep unconventional reservoirs, as conventional hydraulic fracturing method fails to fracture the formation.
A novel technique for oriented chemically-pulse fracturing was developed. The invented method is to create oriented fractures around wellbore, therefore enhance productivity. Having an oriented chemical pulse fracturing, will significantly impact the application of this technology for unconventional gas, especially during long horizontal wells.
Application of Flat Rheology Drilling Fluid System for Overcoming Operational Challenges in Ultra Deepwater Environment
Authors: Alimuddin Sultan , Dey Rahul Sukanta , Srisai Wanchana , Aldea Catalin , Kaewpraphan Kingkarn , Temaismithi Kantaphon , Maheshwari Mukesh 
Published: November 2020

AbstractThis paper presents a comprehensive laboratory and field study discussing development, formulation, and application of a new flat rheology drilling fluid system that meets the challenges faced when drilling in an ultradeepwater well environment. The use of this new flat rheology drilling fluid system for the first time in Asia-Pacific Region has created the potential to efficiently drill more challenging deepwater and ultra deepwater wells in offshore Myanmar, Malaysia, and other associated countries.In a deepwater block situated on Myanmar's west coast, conventional synthetic-based drilling fluids (SBM) have been used to drill all the wells to date. During the planning phase of an ultradeepwater well with a water depth of 2,300 m, it was found that the equivalent circulating density (ECD) with a narrow pore pressure and fracture gradient would have increased downhole complications leading to non-productive time (NPT). The main concern was not being able to reach total depth (TD) or successfully setting casing on bottom with the original well design, requiring implementation of a contingency casing and pushing the operational cost over authority of expenditure (AFE). To overcome the challenges, a new flat rheology drilling fluid system was introduced based on ECD challenges and rheology requirements. The initial study of modelled hydraulics showed a significant ECD reduction using a flat rheology drilling fluid system.The first round of laboratory tests exhibited promising results of flat rheology across all temperature ranges and after iterating numerous formulations developed with local seed mud were narrowed down to two final formulations of 1.08 sg and 1.17 sg. The formulation was field trialed with some slight adjustment in chemical concentrations to meet specific field mud properties. The well was drilled successfully with no major variation in ECD or issues related to the large temperature range. Implementing this customized solution combined with precise strategy led to successful results in efficiently completing one of the most challenging wells of the campaign.The paper presents a comprehensive study of the challenges formulating and implementing a new flat rheology drilling fluid system. Additionally, a detailed study on ECD challenges when drilling an ultradeepwater well is also done. The paper also discusses the comprehensive pit management program and required treatment plan for drilling. Finally, the paper aims to compare the existing results with previous drilling techniques, which will assist operators with the future advances in similar fields.
Ensuring Pipeline Integrity in a Marginal and Aging Asset
Authors: Chantawit Damrong , Tarasantipong Wason 
Published: November 2020

Abstract
In a marginal and aging asset, ensuring the pipeline integrity plays an important role in order to maintain fluid transmission. Shutting off a single pipeline could jeopardize the overall asset operation. This paper presents a methodology for the identification, assessment and mitigation of dragged submerged pipelines.
As part of Pipeline Integrity Management, the inspection of an anchor-dragged submerged pipeline was carried out with the aid of a Remotely Operated Vehicle (ROV) equipped with pipe-tracker module. This enabled us to determine the extent of the pipeline alignment deviation, as well as to conduct a close visual inspection of the pipeline. With the information retrieved from the inspection, a fit-for-purpose pipeline drag analysis was performed to assess the pipeline integrity. The pipeline was simulated using the Finite Element Analysis (FEA) methodology which considered various axial and lateral soil friction factors to achieve the closest approximation of the pipeline's actual condition. Once the best-fit parameters were determined, code checks were performed in accordance with the DNVGL-ST-F101 [1] international standard to assess the acceptable pipeline operating envelops. This assessment results provide the inputs to develop the mitigation plans required to safely keep the pipeline in operation until the pipeline repairs can be executed.
Improving Operations Within Capital Project Execution with Case Examples
Authors: Shenoy Ramachandra , Haley Kerry 
Published: November 2020

Abstract
Recent surveys of major capital project performance conclude that most oil & gas major capital projects fail to meet their budget and schedule objectives. We describe a new technical framework for project execution, drawing upon principles originally applied in the fields of computer and telecommunications network systems design. The constraints and activity synchronization needed to successfully operate digital network systems have many similarities with, and arguably much greater complexity than, the constraints and activity synchronization required to seamlessly execute capital projects. We show the applicability of utilizing network engineering principles to improve capital project execution. The observation is not new – indeed other industries routinely apply network systems engineering to manage their complex project operations and associated supply networks. Companies successfully applying such principles include Amazon, Federal Express and Walmart.
After giving a high-level introduction to the commonality between the fields of network systems engineering and project management and execution, we briefly compare our approach with related ones such as Lean Project Management. The latter approach draws from the operations research and industrial engineering fields, which are foundational in network and systems engineering. We close by describing case examples from recent oil & gas major capital projects and the superior performance obtained by using a network systems approach.