bluuebunny/crossref_metadata_2025_split huggingface dataset:
Drillstring Failure Prevention - A Data Driven Approach to Early Washout Detection
Authors: Kuesters Andrea , Mason Colin , Gomes Paulo , Cockburn Colin , Lodhi Huma 
Published: February 2020

Abstract
Drillstring washouts occur when a leak path develops through the drillstring, leading to the loss of pressure integrity. These events often lead to significant non-productive time across the industry, with many operators experiencing multiple events per year across their global operations. Data driven techniques were applied to detect washouts and prevent them developing into twist-offs. Statistical techniques, rules-based logic and machine learning approaches were assessed against various operations where washouts had occurred. The results showed that data driven techniques can provide effective solutions for detecting the onset and development of drillstring washouts.
Wellhead and Conductor Multi-Variate Fatigue Analysis for Old and New Subsea Wells
Authors: Pilisi Nicolas , Lewis David 
Published: February 2020

Abstract
Deepwater wells historically have, and will continue to, push technological limits. Through the years, water depths and well depths have continued to increase. BOP's are now substantially larger than they were 20 years ago and casing string weights have also steadily and substantially increased. Additionally, since the Macondo incident 10 years ago, capping stacks have also been included in the design process. All of these developments have resulted in higher fatigue loads and an evolved conductor design, wellhead design and in some cases, inclusion of the 28″ pipe (secondary conductor) to support the 36″ conductor. But what about older wells? Wells that may need to receive a modern drill-ship for work-over, intervention or abandonment?
The objective of this paper is to answer the question posed and in doing so create an awareness of the ability for historical well designs to receive a modern BOP and capping stack – or not. In answering, this paper presents a case study of fatigue analysis performed on generalized modern and historical designs and their ability to receive a modern subsea BOP and capping stack. This paper examines the need for full and proper multi-variate fatigue analysis of existing and newly installed subsea wellheads and conductor strings for a set of subsea equipment, top of wellbore architecture, met-ocean and soil conditions. In performing this work, soil and metocean data were considered for the Mediterranean Sea, the Gulf of Mexico and West Africa.
In evaluating, a sample of well designs from 20 years ago through today was selected and a modern fatigue analysis workflow applied. It shows the engineering methodology for calculating and estimating the remaining fatigue life of existing and newly installed wellheads and conductors following the installation of a modern BOP and capping stack. The paper explores the important role of fatigue analysis and shares identified limitations. It also considers what physical factors may be modified to find an acceptable solution. In doing so, readers should get a sense for where potential issues may lie and consider the question of whether lighter BOP and / or capping stack solutions are a consideration for the future.
Drilling Dynamics Model to Mitigate High Frequency Torsional Oscillation
Authors: Shen Yuelin , Chen Wei , Zhang Zhengxin , Bowler Adam , Jeffryes Benjamin , Chen Zhenyu , Carrasquilla Maria Neves , Smith David , Skoff Greg , Panayirci Huseyin Murat , Arevalo Yezid , Bolchover Paul 
Published: February 2020

Abstract
In recent years, the phenomenon of drill string torsional oscillation at frequencies over 50 Hz has been well documented. This high frequency torsional oscillation (HFTO) creates cyclic fatigue loading on bits and drilling tools within the bottom hole assembly (BHA) and thus limits tool life and drilling performance. However, few models exist which can predict occurrence of HFTO and its severity. To our knowledge; none of these models consider the entire drilling system including the bit-rock interaction, downhole drive(s), BHA design, and surface drilling parameters, and hence there is a need to develop a system model for HFTO mitigation.
A 3D transient drilling dynamics model has been extended to study the severity of HFTO and cyclical loading to drilling tools. The accuracy of the model was validated by theoretical calculation, and high frequency downhole data. An example analysis was conducted to evaluate drilling system design performance in terms of HFTO risks. Good correlation was found between the analysis and field data collected from the Permian Basin.
Advanced models were developed for mud motors and rotary steerable system (RSS) tools. After conducting a full drilling simulation, the drilling system behavior under HFTO can be fully described. Cyclical torque loading of differing magnitudes and frequencies were observed for different BHA components depending on HFTO vibration mode, HFTO severity and BHA design. PDC cutters were subjected to different cyclical loading depending on bit design, formation and HFTO conditions. The mud motor power section was found to undergo high frequency cyclical loading which could accelerate its rubber degradation. Since the failure of PDC cutters and the degradation of mud motor power sections have a critical effect on drilling performance, the importance of mitigating HFTO cannot be underestimated. By evaluating the loading conditions, an optimized drilling system can be selected. Field data has proved the validity of this approach.
The methodology presented in this paper offers a new way for the industry to systematically mitigate HFTO by considering the rock drilled, bit design, mud motor utilized, the mechanics of RSS and other tools in the BHA, as well as drilling parameters. The usage of this approach can reduce premature drilling component failure and improve drilling performance, especially in the high energy drilling applications found in North America Land and other areas.
Managing Lost Circulation in Highly Fractured, Vugular Formations: Engineered Usage of High Fluid Loss Squeeze and Reticulated Foam Lost Circulation Materials
Authors: Savari Sharath , Butcher Jacques , Al-Hulail Mustafa 
Published: February 2020

Abstract
Controlling severe to total lost circulation in naturally fractured/vugular formations has always been challenging, particularly in carbonate formations across the Middle East. For such situations, conventional particulate lost circulation materials (LCMs) might not be effective. An extension to the work presented on a high fluid loss squeeze (HFLS) and reticulated foam LCM that provides further technical justification for making such LCMs more suitable for severe to total losses in uncertain situations is discussed.
Savari et al. (2016) presented laboratory evaluation methodology, test results, and field applications of the subject HFLS and reticulated foam LCM. At the time, laboratory test data were presented for the LCM combination that could seal a laboratory-simulated fracture/slot size of 9,800 microns. For the current work, a similar test setup evaluated the efficiency of this LCM to seal larger openings. An adapter with an opening of 31,700 microns was used, and the combination of HFLS and reticulated foam LCM successfully sealed the opening when tested using an industry standard test setup.
For laboratory-based tests, the combination of HFLS LCM and different-sized reticulated foam LCM was successful in sealing a 31,700 micron opening. An industry standard test setup [permeability plugging apparatus (PPA)] was used to evaluate the LCM. The same LCM combination was mixed in different bases, such as water, diesel, mineral oil, and brines; further, the LCM combination was weighted to determine if the sealing performance was consistent. For the aforementioned variations, the LCM combination was successful in sealing the 31,700 micron opening. The LCM plug was also evaluated for the maximum differential pressure it can withstand in wet conditions and for its compressive strength. Under wet conditions, the plug withheld 4000 psi differential pressure and yielded a compressive strength of approximately 400 to 2,800 psi. The latest test data were generated using industry standard PPA equipment with minor modifications. Hence, this helps provide an opportunity for end users to evaluate such LCMs in their own facilities to qualify and generate technical confidence in the LCM combinations before field application.
The combination of HFLS and reticulated foam LCM can provide a technically efficient alternate to particulate solutions for managing severe to total losses in naturally fractured/vugular formations. Test data presented in this work are a first-of-its-kind reported in the petroleum industry literature for any comparable LCM, which further provides confidence in such LCM combinations and can help reduce well costs related to time and mud.
Hole Cleaning in Horizontal Wells Using Viscoelastic Fluids-An Experimental Study of Drilling Fluid Properties on the Bed Erosion Dynamics
Authors: Hirpa Mehmet Meric , Kuru Ergun 
Published: February 2020

Abstract
An experimental study was conducted to investigate how the fluid elastic properties would influence, the frictional pressure drops, the critical velocity for the onset of the bed erosion, and turbulent flow characteristics (i.e. Reynolds stress, axial and radial turbulence intensity profiles) of the polymer fluid flow over the stationary sand bed deposited in horizontal pipeline.
A 9m long horizontal flow loop (pipe ID: 95 mm) equipped with particle image velocimetry (PIV) system was used for the experiments. The polymer fluids, which had almost identical shear viscosity characteristics while showing significantly different elastic properties (quantified in terms of relaxation time) were used together with 30/50 mesh size industrial sands in the bed erosion experiments. Polymer fluids were prepared by mixing three different grades (i.e. 5×105, 8×106, 20×106 g/gmol) of partially hydrolysed polyacrylamide (HPAM) polymer.
After determining the critical velocities for the onset of the bed erosion using both fluids, the frictional pressure drops at critical and several subcritical velocities were recorded for both fluids. Additionally, instantaneous near bed velocities were measured by using the PIV technique. Further analyses of the velocity data obtained by PIV technique, we were able to determine the turbulent flow features such as Reynolds stress, axial and radial turbulence intensity profiles.
Results showed that the fluid elasticity affects the bed erosion dynamics significantly. Generally, frictional pressure drops, and critical velocities for the bed erosion all increased with the increasing fluid elasticity.
This paper presents results of an experimental study where the PIV technique was used to investigate the bed erosion dynamics due to the turbulent flow of elastic polymer fluid over the stationary sand beds. Fluids were prepared using a special technique, which allowed us to alter the fluid elastic properties while keeping the shear viscosity constant. By conducting experiments under controlled conditions, for the first time in drilling literature, we were able to quantify the individual effect of the fluid elasticity (independent from shear viscosity) on the critical flow rate for bed erosion and the turbulent flow characteristics of polymer fluid flow over the stationary sand bed.
Time, Pressure and Temperature Dependent Rheological Properties of Drilling Fluids and their Automatic Measurements
Authors: Cayeux Eric 
Published: February 2020

Abstract
The rheological properties of drilling fluids are very important for the precise estimation of the frictional pressure losses during drilling operations. The first experiences of inline rheometers at the rig site have shown that the rheological properties vary substantially with time. Yet, most inline instruments measure these properties at only one condition of pressure and temperature. This paper describes how the pressure, temperature and shear history dependence of the rheological behavior can be measured continuously.
The measurement of rheological properties of drilling fluids is complexified by the fact that they are thixotropic, i.e. the rheological properties depend on the shear history applied to the fluid. For an inline rheometer, any change of pipe diameter, or the introduction of a fluid sample in a cavity, introduces a shear variation. Therefore, inline rheometers need to account for the side effects of thixotropy on the results. Instead of trying to reduce the thixotropic effects, the new rheometer focuses on measuring these thixotropic properties so that steady state values can be extrapolated.
Most published studies of thixotropic fluids indicate that thixotropic fluids need a long recovery period to reach steady state conditions after a change from high to low shear rates, but that a change of shear rates from low to high is recovered very quickly. However, the thixotropic behavior of drilling fluids differs from other thixotropic fluids, as it needs considerable time to recover both from high to low and low to high shear step changes. The measured time constants for these effects are long (several minutes), therefore making it difficult to design an inline rheometer that eliminates thixotropic effects.
Furthermore, gel duration has not only an impact on the stress overshoot when an increasing shear strain is applied to a gelled fluid, it also impacts the rheological behavior for several minutes after viscous flow is established. The new inline rheometer is designed to exhibit explicitly these effects in order to measure directly the gel strength as a function of gel duration and the time constants that characterize the remnant effects of gelling on viscous properties.
The impact of the shear history on rheological measurements is important to obtain precise estimations of the rheological properties of drilling fluids. With an automatic inline rheometer that can provide time, pressure and temperature rheological properties, it is then possible to obtain more precise results from advanced drilling hydraulic models running in real-time, with less manual configuration efforts.
Dynamic RT Modelling and 3D Visualization of Critical Safety Parameters on Drillfloor During Drilling, Running Liners & Screens and Cementing of Challenging Offshore Wells
Authors: Rommetveit Rolv , Nabavi Josef , Ødegård Sven Inge , Gholami Mayani Maryam , Syltøy Svein , Lauve Marit , Jordal Ole Henrik , Kolltveit Tore 
Published: February 2020

Abstract
As part of the digitalization and utilization of Automated Monitoring during drilling operations, real-time dynamic modelling of downhole combined with 3D dynamic visualization have been implemented on the drillfloor in offshore rigs. The objectives have been to give the driller instant feedback on the ECD and other effects of the operations and allow for a safer and smoother operation within the limits of the well.
The basic elements of this technology are
A digital twin of the well with all relevant data and properties included. A set of integrated transient models (hydraulics, surge & swab, displacement, mechanical friction). These models are driven by the RT data from operation and compute critical safety parameters which are presented for the driller. A diagnostic module analyzing differences between measured and modelled parameters and trends. A 3D Virtual Well which visualize the downhole well, the risk matrix, the diagnostics and messages as well as the ECDs at critical positions in the well.
The 3D System has been utilized during drilling of several very challenging ERD and Multi-Lateral wells on two platforms in the North Sea. The system was also used during tripping in and out of the well, and during running of casing and liners. During these operations there is no PWD data available, and the modelled ECD values proved especially useful. The Trip-risk log from the Geologist was included in the 3D View during these operations, and the Driller could then see on the 3D when a risk was coming up.
This paper will present the experiences from using the dynamic 3D & modelling system on several wells. The feedback from the Drillers and Drilling manager have been positive, and the results are very promising.
Automated Sliding: Efficiencies Achieved in the Next Stage of Drilling Automation
Authors: Hausher Aaron , Kern Sarah , Chmela William , Cantwell Jeremy , Mims Kevin 
Published: February 2020

Abstract
In the current drilling climate, efficiency is king: do more with less. This motivation drives disruptive technological innovations in automation of the drilling process. Drilling automation can contribute to this efficiency specifically by automating the sliding process. The paper discusses a case history involving one operator's deployment and results of an automated sliding system.
The goal for automating the sliding process was to reduce personnel on location, drive consistency, increase wellbore quality, and shift the focus from an ROP-focused mindset. The operator had initially used bit guidance software for approximately one year, which was a significant backbone component of the automated sliding system. The automated sliding software was installed and tested on the rig, and then deployed on a six-well pad for initial observation and analysis.
After deployment, the automated sliding system successfully completed slides in all four surface sections on the pad. The first complete well on the pad, drilled to total depth, successfully completed slides in the vertical, curve and lateral sections. The rate of automated sliding exceeded initial goals, and the rig proceeded to drill several more wells at near-100% utilization rates. The automated decision-making system compiled detailed drilling set points and specifications used to form the most consistent and efficient method to drill the well, formation by formation. The total number of third party directional drillers was reduced, increasing overall safety and lowering costs.
Automating the sliding process, with this degree of accuracy and lack of human intervention through automated decision-making, represents a significant step change in the drilling industry milestones on the road to full automation. Best practices regarding adoption and deployment of automation technology will contribute to ensuring success in the ever-increasing field of drilling automation.
Revisiting the Classical Problem of Transient Temperature Prediction in Complex Deepwater Wellbores with a New Semi-Analytical Approach
Authors: Chandrasekhar Sharat 
Published: February 2020

Abstract
Transient temperatures in arbitrarily complex wellbores are preicted by using a semi-analytical approach based on the Laplace Transformation of the set of governing equations from the flowing stream across the multiple layers of the wellbore and out into the formation. We investigate flowing and shut-in (static) scenarios consider sequentially linked thermal operations. The methodology can be applied to subsea deviated wellbores with variable lithology and geothermal gradients, and without invoking any of the several simplifying that have characterized previous studies.
Wellbore temperatures are extracted from the solutions of the coupled heat transfer equations in the wellbore and the formation by inverting a set of Laplace transforms with sequential updating to capture the temporal variation of natural convection in fluid-filled annuli. Natural convection in these annuli and in the static fluid conduit during a shut-in period is explicitly modeled by taking considering the non-Newtonian behaviour of typical annular fluids. The transient heat transfer in the formation is determined by a time dependent temperature boundary condition at the wellbore-formation interface, and a zero heat flux boundary condition at a farfield location that is spatially consistent with the duration of the specified thermal operation. The former boundary condition is analytically treated by the Duhamel superposition principle. Having obtained the analytical solution to the formation heat transfer, the efficiency of the Gaver-Stehfest function sampling algorithm to invert the Laplace transforms is demonstrated.
The methodology is demonsrated by applying it to a complex deepwater 30,000 ft MD deviated well in the Gulf of Mexico. The S-shaped trajectory traverses a thick salt layer with variable geothermal gradients. We show that in comparsion to finite-difference methods, the semi-analytical approach (using Laplace Transforms) can use much larger time sub-intervals to provide a given level numerical accuracy. This aspect of numerical efficiency arises as a consequence of the inherent numerical stability of the approach. This results in a reduction in computational time by several orders of magnitude without a corresponding sacrifice in accuracy. Production, Injection and Shut-In operations are modeled. The advantages of the present approach are more pronounced for short term scenarios such as drill-stem tests where the transients have not yet decayed to a steady state. Even though complex subsea wellbores are the focus of the approach, the formulation can be applied to an arbitrary wellbore configuration including land-based and platform wells.
Using MPD and Conventional Methods to Address a Well Control Event in a Deepwater Exploration Well
Authors: Moghazy Sharief , Van Noort Roger , Kozlov Anton , Haq Inam , Silva Thiago , Hester Clayton , Gabaldon Oscar 
Published: February 2020

Abstract
This paper presents a case where Managed Pressure Drilling (MPD) was used to drill a challenging exploration well through a pore pressure ramp and to address a well control event in conjunction with conventional methods when an influx was encountered
The MPD system was used to drill using primary and secondary indicators, such as background gas, cuttings shape, and changes in ROP to determine if onset of the pore pressure ramp was imminent. The MPD system provided a means to measure the flow in versus the flow out of the well and chokes to add surface back-pressure (SBP) to adjust the bottomhole pressure. The MPD operators monitored the trends as drilling continued and reacted if any indications of a pore pressure ramp were experienced.
The pressure ramp was encountered, and the flow out exceeded the flow in. The driller applied more surface back pressure to control the influx and reduce the influx size. The well could not be controlled within the allowable back pressure limitations as outlined by the MPD Operations Matrix, so the well was shut in on the Subsea Blow-Out Preventer (SSBOP). The well was controlled with conventional well control methods, using the Driller's Method. The mud weight was increased to the extent that it was not enough to hydrostatically kill the well, but sufficient to allow operations to resume within a new MPD Operational Matrix adding back pressure to keep BHP overbalanced to the formation. This application of MPD reduced the impact of the influx event and allowed the rig to safely continue drilling and meet the well objectives without losing the hole section.