bluuebunny/crossref_metadata_2025_split huggingface dataset:
Subsea BOP Tethering System as an Alternative for Mitigating Wellhead Fatigue
Authors: Sevillano L. Cantinelli , Morooka C. K. , Lieng J. T. , Sangesland S. 
Published: February 2019

Abstract
More-accurate estimates of the fatigue damage on subsea wellhead might prolong the service lifetime of the equipment. Nevertheless, there might come to a point during the life of a well on which the fatigue capacity is nearly depleted, without the possibility of further interventions being carried out, and thus imposing the abandonment of the well. This paper studies how employing a BOP tethering system may reduce the bending moment load transferred to the wellhead.
A BOP tethering system may be described as an assembly of anchors disposed around the subsea wellhead, which are connected to the BOP by mooring lines. The goal of the system is to reduce dynamic loads transferred to critical wellhead fatigue components and minimize the damage rates by decreasing the bending moment that is transferred from the riser to the wellhead.
The scope of a wellhead fatigue assessment comprises a riser response analysis. This paper presents the expected reduction on the calculated fluctuating bending moment load transferred to the wellhead for a series of possible configurations of the tethering system.
The results of the study conducted have shown that tethering the BOP system during drilling or re- entry operations has potential to decrease accumulated fatigue damage in the wellhead and can be regarded as an alternative for mitigating wellhead fatigue. The gains in petroleum production because of the increased operational life of the well have the potential to surpass the costs inherent to installing the tethering system. The results of simulations for different design options have shown the potential of this approach to increase the remaining service life of a wellhead, potentially doubling it. Even if installation restrictions prevent the optimum design to be used, this approach could still be advantageous.
Mitigating wellhead fatigue may prevent early well abandonment. Approaches considered to mitigate wellhead fatigue by actively reducing the load transferred to the wellhead have been presented before. The BOP tethering system is an alternative to these previous systems and provides operators an additional solution for consideration to their specific needs.
Revitalizing the Bakken With Managed Pressure Drilling
Authors: Parayno Gerard , Peacock Scott , Connolly Brandon 
Published: February 2019

Abstract
The operator has been very active drilling in the Williston Basin including the Bakken for several years now. As development progresses, lateral sections were steadily increased and are now in the 10,000ft range and with this, the average days in completing the section has also increased to 14 days. These wells have been drilled conventionally since the beginning of the campaign and have been plagued with problems such as stuck pipe, mud loses, pressure issues to cite some examples.
A test well was agreed for Managed Pressure Drilling (MPD) to see if this can solve the issues observed. MPD design for an optimized mud weight and surface backpressure schedule were utilized in the whole production section including for tripping and liner run operations. For the test well, a total of 9622ft of lateral was drilled for 7 days including casing run and cementing. Performance-driven application of MPD effectively reduced in half the operating days.
With the successful application of MPD, it has managed to achieve the main objective which is to reduce the operating days for drilling the production section. This was achieved through the ROP improvements due to a lower mud weight and application of back pressure to minimize surface gas and having the MPD package to handle the gas at the surface while drilling.
In the span of three months starting from that first test well for MPD, the campaign continued with using the technology and one more rig was added. So far 5 wells have been completed with improvements from MPD with reduced operating time. Lessons learned and continuous training of the field operating team have enabled for the drilling campaign to utilize this technique further in synergy with the other field service groups.
For this paper, the specific MPD operations will be described including the liner run procedures for the wells drilled so far and the key lessons for the continuous application of MPD to the Bakken drilling campaign in the Williston Basin.
Mitigating and Understanding Stick-Slip in Unconventional Wells
Authors: Dao Ngoc-Ha , Menand Stephane , Isbell Matt 
Published: February 2019

Abstract
Stick-slip is still present in most of the wells drilled today, especially in unconventional wells. Friction is an inevitable and important force along the long lateral section, but it contributes to many types of dysfunctions that lead to drilling inefficiency. Stick-slip is caused mainly by rotational friction induced along the drillstring, from the drill bit cutting the rock formation to the bottom hole assembly and drill pipe that contact the well bore. In the past, much attention has been given the cutting action of polycrystalline diamond compact (PDC) bits to explain and mitigate stick-slip, without much emphasis on the frictional torque. However, it is important to understand that the torque generated on the remaining drillstring accounts for most of the total torque at surface.
This paper presents a case study on an unconventional well where stick-slip modeling was used to explain and understand stick-slip vibrations with or without the presence of active control systems at surface. First, the stick-slip model, including a PDC bit law friction and accurate contact forces calculation along the drillstring and mud damping effect is fully described, with all necessary and field parameters needed. Then, it explains the process to reproduce and calibrate downhole and surface torque, using a sensitivity analysis showing the most important parameters that affect stick-slip results. The results reinforce the importance of drilling parameters, such as the weight on bit and associated torque on bit that define the bit aggressiveness and are key in controlling or mitigating stick-slip vibration. In addition, these results show the significance of string friction along the drill pipe. Next, the use of a downhole instrumented sub, along with wire drill pipe technology, enables a full comparison of the results of the model with downhole and surface data. Last, the affect of other parameters, such as friction coefficient and mud damping, are discussed.
With a better understanding of the initiation and translation of stick-slip from the bit up the hole to surface provided by this case study, engineers can be better informed when making decisions on factors such as drill pipe size and type, bit aggressiveness, and parameter changes in wells with severe stick-slip in unconventional wells application.
Application of Real-Time Fluids Data to Reduce Uncertainty in Casing-to-Casing Time
Authors: Jamison Dale , Williams Robert , Porter Aidan 
Published: February 2019

Abstract
Uncertainties in the drilling process result in safety factors or safety margins sufficient to minimize risks in the drilling process. These safety margins represent inefficiencies in the system. This paper will discuss a method for reducing uncertainty as it relates to well bore pressures and hole cleaning to eliminate or reduce these inefficiencies, quantify the rates of penetration that can be achieved, and illustrate the expected wellbore pressures generated by these rates of penetration.
When data is collected manually, the nuances of fluid changes are lost between property measurements. This paper will illustrate the difference between calculating equivalent circulating densities (ECD) with manually collected mud report data and fluid properties collected in real time and the impact that this can have on optimizing the rate at which the operator can drill and trip pipe.
A patent-based methodology will be presented, in which real-time drilling and fluids data are captured and utilized to model ECD pressure data related to the bore hole. The actual and modeled data are statistically analysed to infer information about how rapid a rate of penetration (ROP) may safely be employed to optimize drilling results.
Data will be presented demonstrating the impact that small improvements in fluid parameters and drilling operations can have over the course of drilling a well.
The role that a real-time hydraulics software model plays in providing predictive analytics for ROP optimization will also be discussed. Predictive analytics enable operators to look several stands ahead of the bit to determine if the ROP drilled will cause issues in the future. This enables the identification of the maximum ROP that can be drilled versus optimizing instantaneous ROP. This enables operators to optimize casing-to-casing time.
A Data Driven Approach to Predict Frictional Pressure Losses in Polymer-Based Fluids
Authors: Gul Sercan , Johnson Mitchell David , Karimi Vajargah Ali , Ma Zheren , Hoxha Besmir Buranaj , van Oort Eric 
Published: February 2019

Abstract
Managing drilling margins in challenging wells requires precise prediction of frictional pressure losses and equivalent circulating density (ECD). Current hydraulic models in the industry fail to accurately predict the frictional pressure losses of certain mud formulations in turbulent flow due to the complex behavior of long-chain polymer additives. These additives facilitate friction reduction in certain flow regimes. This reduction depends on several parameters, such as molecular weight and chemical composition of the polymers, making it difficult to quantify using existing models. In this paper, a data-driven approach is proposed to precisely predict frictional pressure losses for polymer-based fluids.
A flow-loop was constructed to measure frictional pressure-losses of several polymer-based non-Newtonian fluids under laminar, transitional, and turbulent flow regimes. Pressure loss data was obtained for fluids with different polymer concentrations at various temperatures using differential pressure measurement. A database of the experimental data was compiled and used to build a predictive model for frictional pressure prediction using advanced machine learning techniques. The proposed approach has general validity and can be extended to any type of well construction fluid (used in drilling, completion, stimulation, or workover).
Results for frictional pressure loss predictions from the proposed data-driven approach were compared with both the experimental data and widely used industry models. An excellent agreement was observed between the proposed approach and the experimental results, demonstrating the applicability of this approach for hydraulic modeling of polymer-based fluids. The improvements are particularly noticeable at higher polymer concentrations in the turbulent flow regime, where the average percentage discrepancy between the existing models and the experimental data can be as high as 45%.
The proposed approach in this study is particularly valuable for wells with a narrow drilling margin and concerns about the ability to manage ECDs (such as slim hole wells, deepwater wells or extended reach wells). It can assist with better planning and avoiding non-productive time and drilling problems such as lost circulation, stuck pipe, wellbore instability, and well control events. Its adaptability to a wide range of fluids using an expanded database makes it particularly attractive as a practical solution to this challenging problem.
A Drill Bit and Drilling Motor with Embedded High-Frequency 1600Hz Drilling Dynamics Sensors Provide New Insights into Challenging Downhole Drilling Conditions
Authors: Sugiura Junichi , Jones Steve 
Published: February 2019

Abstract
Drilling motors are typically used in every well drilled globally with conventional steerable bottom-hole assemblies (BHA's) and powered rotary-steerable BHA's. Downhole drilling dysfunctions are common when mud motors are pushed to the limit for maximum drilling performance. High-frequency (1600Hz) continuous recording compact drilling dynamics sensors were embedded into the bit, bit box and top sub of the motor to better understand drilling conditions in different shale plays throughout North America land.
In the drilling industry, most downhole measurements for drilling dynamics utilize relatively low-frequency sensors (up to 100Hz). Typically, the measurements are burst and not continuous. These low-frequency burst acceleration devices cannot reliably measure high-frequency torsional oscillations (HFTO) which are known to be problematic while drilling in certain shale basins. Newly developed high-frequency (1600Hz) compact drilling dynamics sensors can now be embedded into the drill bit, mud motor bit box and top sub to record 3-axis accelerations continuously at high-speed sampling rates. The embedded sensors do not add any extra length to the steerable motor and therefore capture the true dynamic response of the system.
Embedding the high-frequency sensors at both ends of the mud motor provides two unique data sets of dynamic measurements. With conventional steerable motors and motor-assist rotary-steerable systems (RSS), HFTO dominant frequencies between 100 and 400Hz were commonly observed. In some cases, HFTO dominant frequencies between 400-700Hz and their harmonics were captured, which have not previously been reported. In most cases, the HFTO amplitudes are between 20 and 200g peak (or 40 and 400g peak-to-peak). On some occasions, ±200g self-perpetuating HFTO were recorded in memory where its calculated angular acceleration is more than 25,000 rad/s2.
The transitions between low-frequency stick-slip and HFTO were captured in high-speed recording. Negative string rotation speeds were commonly observed at the top sub of the motor while in rotary mode. It was noted that the bit would slow down to a stop but never turn backwards, resulting in the backward rotation of the motor top sub. During very high-amplitude multiple-axis shocks at the bit, it was discovered that there was a significant temperature rise due to loss of energy from bit dysfunction.
The newly reported drilling dynamics phenomena, such as multiple dominant HFTO frequency shifts, micro-sticks and micro-slips, will be detailed in this paper. Monitoring and understanding high-frequency drilling dynamics dysfunctions allows us to make systematic changes to bit, BHA and drilling parameters to reduce dysfunction magnitude and improve overall drilling efficiency and minimize component wear.
On the Sealability of Metal-to-Metal Seals with Application to Premium Casing Connections
Authors: Ernens Dennis , Peréz-Ràfols Francesc , Hoecke Dennis Van , Roijmans Roel F. , Riet Egbert J. , Voorde John Vande , Almqvist Andreas , Rooij Matthijn Bas , Roggeband Serge Mathieu , Haaften Willem Maarten , Vanderschueren Marc , Thibaux Phillipe , Pasaribu Henry Rihard 
Published: February 2019

Abstract
Metal-to-metal seals are used in connections of casing in oil and gas wells. This paper describes the mechanisms of sealing of metal-to-metal seals as investigated using an experimental set-up and a sealability model. Experiments were conducted for a variety of thread compounds and applied pin/box surface coatings. The results were used to validate a numerical model for sealability. The stochastic model couples a contact mechanics model with a flow model and takes the influence of all the surface topography features into account. Once validated, the model was used together with the experimental results to explain the sealing mechanisms of metal-to-metal seals.
The sealing configuration is a face seal with an R=80 mm round-off radius pressing against a flat. The face seal specimens were manufactured from P110 tubing. The used test set-up is designed for investigating only the metal-to-metal seal of the connection. The set-up can carry out rotary sliding under constant load to simulate surface evolution during make-up and subsequently perform a leakage test. The sealing limit is determined by applying 700 bar fluid pressure and then gradually reducing the normal force until leakage is observed. The data is subsequently used to validate a previously published model.
The results indicate a strong dependence of the type of thread compound used on the onset of leakage. The thread compound affects the amount of wear and thus changes the surface topography of the interacting surfaces. It is shown that the sealability model is capable to predict the onset of leakage within the experimental accuracy. The model shows further that certain surface topographical features improve the sealing performance. Namely, a turned against a flat surface topography leads to highly localized contact areas, which in turn yields the best sealing performance.
The combination of experimental data with the validated model leads to much deeper insights for the sealing mechanisms than what could be obtained using either on their own.
Rock Customized Shaped Cutters Improve Rock Cutting Efficiency
Authors: Rahmani Reza 
Published: February 2019

Abstract
Failing the rock and removal of failed rock are the two primary actions that control drill bit efficiency. A proper design must address both primary actions while focusing on the major efficiency driver. This has been the basis for development of shaped cutter technology where the geometry of polycrystalline diamond compact (PDC) cutter is designed according to the rock type.
Using the learnings from advanced modeling techniques on cutter-rock interaction, more than three dozen new geometries for PDC cutters were designed, manufactured, and tested. Based on the performance and application needs, three shapes were selected for further development: geometry A designed for shale applications focusing on efficient cuttings removal, geometry B for proper fracture initiation and propagation, and geometry C combines the features from the other two geometries to improve both creation and removal of cuttings.
The geometries were optimized for maximum rock cutting efficiency while maintaining the cutter durability via analytical and numerical modeling, and pressurized drilling tests, which are the focus of this paper. The cutters were then successfully tested in field applications with consistent good performance resulting in several performance records including in North America and the Middle East.
Industry's First PDC Bit Gauge Design for Improved Tracking In North American Horizontal Wells
Authors: Spencer Reed , Pierce Bradley D. , Grimes Robert E. 
Published: February 2019

Abstract
PDC bit gauge pad design parameters are well understood for providing the desired build up rate (BUR), but these designs provide minimal value in the horizontal section. Outside forces, such as bit walk and formation push, can cause deviations in inclination and azimuth. Trajectory corrections on both motor and RSS assemblies can significantly slow the drilling process and result in more tortuous wellbores. Thus, a PDC gauge pad design that provides minimal side cutting at low side loads, while achieving typical BUR at higher side loads should result in a PDC bit that tracks better with fewer unintended deviations and resulting trajectory corrections for improved overall drilling efficiency.
Prototype bits were developed with a tracking gauge pad design. Laboratory tests demonstrated the desired side cutting response at various side loads. Field tests are being conducted across the U.S. on pad wells offering direct comparisons to offsets using conventional PDC bits.
This paper presents the tracking gauge pad design concept, laboratory test results, and field performance improvements. Results show reduced trajectory deviations and dogleg severity, improving overall section ROP and hole quality.
Until now, the role of PDC bits has focused primarily on achieving the intended BUR and instantaneous ROP, leaving tracking performance solely to the drilling system. The tracking PDC gauge design concept breaks this paradigm by providing a PDC bit that tracks better than conventional bits for significant gains in directional drilling efficiency.
Computation of Surge Pressure Wave Propagation During Cementation Process
Authors: Assaad Wissam , Crescenzo Daniele Di , Murphy Darren , Boyd John 
Published: February 2019

Abstract
This paper presents a method of modelling surge pressures and wave propagation that can occur during well execution. The surge pressures have an impact on formations i.e. formation fracture resulting in mud losses and non-productive time. Knowing the amplitude of pressure surges in advance can lead to operation redesign to avoid losses. Pressure waves can occur at numerous points during well execution. For example, during liner operations, pressure waves can occur dart landing or plug shearing, liner hanger setting or clearing a plugged shoetrack component. It is possible that these pressure waves can create fractures in shale and sand layers i.e. when pressure wave amplitude exceeds formation fracturing limit.
A physical model is built to compute pressure wave propagation through drill string, casing and open hole, to predict amplitude of pressure wave and to warn when a fracture may occur in formation to avoid mud losses and non-productive time.
In the model, the continuity and energy partial differential equations are built for a cylindrical fluid element contained in an elastic hollow cylinder. Method of characteristic is applied to transfer the partial differential equations into ordinary differential equations. The ordinary differential equations are solved numerically to compute pressure distribution along well depth and in time. The physical model is implemented as a Graphical User Interface (GUI) tool to be used by drilling engineers at design phase of well to avoid losses. To date it has been used for cementing and perforating operations. Pressure wave computations are performed with the model for a field in Gulf of Mexico where mud losses have occurred, and results are presented in this paper.