bluuebunny/crossref_metadata_2025_split huggingface dataset:
Designing and Qualifying Equipment for a Potential World-Record Deepwater Casing Landing Operation
Authors: Chase Thomas , Garcia Aaron , Marchman Kellon , Mendoza Manuel , von Eberstein Chris , Tritz Jacob , Tritz Noah , Jordan Chris , Smith Logan 
Published: March 2023

Abstract
As the design of deepwater wells continues to evolve for unlocking new reserves from deeper and challenging reservoir conditions, longer and heavier casing strings are required to achieve various well objectives and operational efficiency. The mechanical requirements resulting from the landing and cementing of these heavy casing strings pushes the limits on current equipment. Landing and cementing such heavy casing designs presents numerous challenges to conduct the operation safely and efficiently, requiring the implementation of non-conventional alternatives to manage the loads for enabling the existing rigs to step-out of the normal drilling envelopes.
For drilling the first deepwater 20,000 psi development well in Gulf of Mexico, the Operator required the large diameter nested liner strings to be deployed deeper than any offset well, for ensuring pressure containment while drilling and sufficient diameter for the larger production casing / completion equipment. As a result, the load of landing the 16″ nested liner string was expected to exceed 2.5 million lbf, which was outside of the operational capability of any existing equipment, including drilling rig, landing string and cementing head. The planning team assessed alternatives for running the liner with an existing drillship and the landing equipment available including pipe, cementing head and handling equipment. Rigorous measures had to be put in place in order to determine the technical requirements to qualify the equipment for the operation and better understand and mitigate the risks involved.
These challenges were overcome by considerable planning in landing string design, handling equipment implementation, assessing rig load path and shearing capability for the heavy landing string, equipment design review and testing, and equipment inspections and qualifications. Specific areas of focus included: the use of heavy-duty, high yield, thick wall landing string through the BOP stack, upgrading the shearing and sealing capability of the rig's BOP stack, use of buoyed landing string above the BOP stack and the associated handling equipment, an increased load rating of cementing equipment by re-evaluating design and material, customized inspection criteria for all equipment to be used, and a thorough evaluation of landing string accessories to validate structural integrity. All parties involved provided significant effort to ensure that the equipment used in this string was fit for purpose.
The stringent planning, ratings re-evaluation, and equipment qualifications helped ensure the successful landing of a potential world-record 2.49 million lbf hookload 16 in. liner string under challenging weather conditions. The successful landing of this string paves the way for future wells where similar design challenges will be faced.
Engineers’ Trilemma: Use and Limitation of Torque and Drag Models
Authors: Samuel Robello 
Published: March 2023

Abstract
Different methods to calculate torque and drag have been used by the oil industry for years. Various assumptions are used in formulating these models. Opinions have often varied as to which model is better and whether the assumptions are valid. This paper discusses the trilemma considerations for an engineer 1. Soft string model vs stiff string model 2. Survey calculation method based on minimum curvature 3. Appearing and vanishing tortuosities after the casings have been run.
Because of various underlying assumptions, the friction factor calibration is done often to match the calculated results with the actual results. This results in a wrong conclusion due to the change in the drag forces but on the contrary, it may be due to the exacerbation of the assumptions. The paper presents the pitfalls of the drillstring models, borehole curvature, appearing and vanishing tortuosities and their relationship with related well engineering calculations. Mathematical underpinnings are provided for all the trilemma considerations.
Results demonstrate that a string with a large-size section can be very soft in a straight wellbore, and a string with small-size section can be very stiff in a wellbore with severe tortuosity, which is better fit for a stiff string model. Results also confirm that the soft string model is a better choice when the string is slimmer, the wellbore is in a lower curvature shape, and the clearance is larger. It has been observed that the absence or the discontinuity of bending moment results in the underestimate of forces, torque, and stresses when the minimum curvature method is used. This vanishing tortuosity alters the apparent wellpath and the new tortuosity representative of the cased hole path may present new appearing tortuosity and results in over and under estimation of the torque and drag calculations. To accurately estimate the drag force, the stiffness, as well as the wellbore shape and its clearance, should be considered.
Evaluation of Stress Distribution in Subsea Wellheads Installed in Caisson
Authors: Cantinelli Sevillano Lucas , Sangesland Sigbjørn , Gjersvik Tor Berge , Faanes Audun 
Published: March 2023

Abstract
The wellhead is a pressure containing vessel at the top of well and acts as the mechanical connection between well and blowout preventer (BOP), or Christmas tree. Wellheads in subsea wells are subjected to dynamic loading, and consequently fatigue damage, whenever a riser connects a well to a floating vessel. This paper investigates the load distribution and stresses along the components of subsea wellheads installed in a caisson, as an alternative to mitigate wellhead fatigue.
To prevent fatigue-related incidents, operators, suppliers, and classification societies have collaborated to improve the evaluation of wellhead fatigue. A detailed finite element model (FEM) of the wellhead is used to simulate the mechanical response of the system and calculate stress levels at relevant spots. The simulations presented in this study follow the industry's recommended practices to investigate the potential of reducing the loading on wellhead fatigue hot spots by having a caisson installed around the conductor. Different parameters were established to evaluate the sensitivity of the system's response and determine the optimal mechanical configuration.
Caissons have been used to place the wellhead and the Christmas tree below the mudline level, as a protective measure against icebergs in Arctic regions and trawl nets in fishing areas. The results of the presented study case indicate that this practice may be of benefit to subsea wellheads in general. The interactions with the caisson and the thick cement ring between conductor and caisson near the mudline may alter the response of the wellhead to the environmental loads transferred by the riser. While the magnitude of the loading itself is not reduced, its distribution along the wellhead components is. As a result, stresses on wellhead spots particularly vulnerable to fatigue failure, such as welds, may be reduced, while stresses on other, less vulnerable, locations of the wellhead may increase, which still results in a net gain to the overall service life of the product.
Installation of a subsea wellhead in a caisson is a potential fatigue mitigating measure applicable to new wells, either in satellite or clustered configuration. The industry's established experience with similar equipment may expedite the adoption of this measure.
Pressure On-Demand - Hybrid Electric BOP Control Systems
Authors: Givens Matthew , Olson Matthew , Hope Joseph , Beim Samantha 
Published: March 2023

Abstract
Changing well control requirements have increased accumulator volumes for the operation of Blow Out Preventer (BOP) stacks and diverters, challenging the space available for the BOP control system equipment on today's rigs. Koomy or Land Closing Units (LCUs) use potential energy stored in accumulators to control the hydraulically actuated BOP Stack and diverter systems. Accumulator systems are limited in their operational capacity because of the inefficiencies created by rapid adiabatic gas expansion and the pressure and flow decay over the function stroke. By changing the approach from stored energy in accumulators to energy on-demand, the hybrid electric BOP control system will expand the operational capacity drilling rigs.
The implementation of a hybrid-electric pressure on-demand BOP control system can reliably address this challenge by providing indefinite usable volume and a more reliable platform with a smaller footprint and value-added performance. Feedback loops will provide on demand flow to better match the operation and shear curves of the individual functions, eliminating the BOP closing time and response constraints that challenge traditional accumulator systems. This paradigm shift will remove the usable volume constraint as the pump on-demand system provides an indefinite amount of flow at the maximum rated working pressure of the operating piston.
Stringer Detection and Drilling System Significantly Reduces the Invisible Lost Time (ILT) Caused by Reaming
Authors: Hohl Andreas , Houghton Glen , MacFarlane Danial 
Published: March 2023

Abstract
Drilling hard stringers that are erratically distributed in an underlying rather soft formation is challenging from different perspectives. An unforeseen change of the drilled formation from soft to hard and dense rock can cause impact damage to the bit, deflect the bottom-hole assembly (BHA), result in high bending loads, increase vibration, and cause wear/tear on BHA components. If not properly managed, this leads to non-productive time (NPT) and increased maintenance costs. Further, a deflection caused by a stringer away from the planned well path that is detected late results in high local doglegs (HLD) and requires time-consuming correction through reaming with invisible lost time (ILT).
Recently, a stringer detection method based on vibrations, namely high-frequency torsional oscillations (HFTO), has been presented. A case study with 21 sections in the North Sea based on this solution is shown that demonstrates a reduction in ILT by 80%.
The system is based on a timely and reliable detection of stringers, an optimized mud pulse telemetry scheme, and an automated advisory system. The downhole algorithm embedded in a measurement while drilling tool is consistently interpreting HFTO based on tangential acceleration and dynamic torsional torque measurement. By defining thresholds for the amplitude and the localization with respect to frequency content of HFTO, the algorithm results are translated into a binary value with 1 – stringer currently drilled or 0 - no stringer is drilled. The low bandwidth consuming 1-bit value and downhole measured bending moment are sent in 10 to 15 second intervals to the surface by mud pulse telemetry. Once the stringer is detected, the bending moment data is closely monitored to react correctly and efficiently to a stringer in different scenarios.
This solution is discussed in a case study in Norway covering 21 sections with and without the system deployed. The offshore application is challenged by frequently occurring stringer layers and nodules of different geometry. Based on the stringer content, the reaming time has been typically high in this application. The system, however, enabled a timely detection of the stringers and an optimal stringer drilling enabled by the frequently sent bending moment information. Therefore, stringer drilling was done without having to pull off-bottom frequently and ream the transition area between soft and hard formation thereby saving time and reducing wear on the BHA and drill pipe, ultimately ending up with a smoother/straighter wellbore.
By using the system, a faster reaction to any stringer and the use of appropriate parameters to avoid costly HLDs are achieved. The case study demonstrates a significant and consistent improvement in ILT. The reaming hours per 1000 m as a benchmark have been reduced from 2-5 hours without to 0.3-0.6 hours with the system resulting in an average saving of 12 hours per reservoir section.
Fluid Circulation Effects on Torque and Drag Results, a New Take on an Old Subject
Authors: Mahjoub Mohamed , Dao Ngoc-Ha , Summersgill Matthew , Menand Stéphane 
Published: March 2023

Abstract
The hydraulic effects on torque and drag modelling have been thoroughly studied in the past, yet their interpretation still causes a lot of misunderstandings and confusions. Historical models disregard the circulation effects and focus on the fluid mass by employing buoyancy forces based on Archimedes principle. On the other hand, the reference model including the fluid circulation effects, introduced by R. F. Mitchell in the 1990s, consists in computing the forces due to internal and external fluids along the drill-string. The first type of models called Archimedes method directly produces an effective tension, while the second one generally called pressure area method produces a true tension that must be further transformed to get the effective tension. These different forms of tensions add even more confusion.
By returning to the basic equations of the fluid effects on the drill string, an equivalency between Archimedes and pressure area models has been found for the case with no circulation. Furthermore, with the same principle, an Archimedes-like model is deduced for the case of fluid circulation, where the effects of fluid pressures, frictions, and flows could be more easily interpreted. These two hydraulic models, after implementation in a true stiff-string 3D model enable then to fairly compare the two approaches in terms of forces applied on the structure.
The comparison of this Archimedes formulation with pressure area model gave sensibly the same results for various scenarios, proving the equivalency of the two approaches even with the case of circulating fluid. In addition to the model-to-model comparisons, torque and drag results are compared to field experiments at different depths. Flow rate was varied while reciprocating the drill string up and down, and the hook load was recorded for each flow rate and each tripping direction. The model-to-data comparisons showed a good agreement between the theoretical results and experimental data.
An advanced Archimedes method with all fluid circulation effect has been developed. By tackling the problem of circulating fluid in the drill string using two different approaches and proving their equivalency, a better understanding of the hydraulic effects can be achieved, which in terms can help settle the possible debates and confusions that might arise by drilling engineers.
Performance Analysis of a Downhole Regulator on Rate-Of-Penetration and Drilling Efficiency: An Autonomous Load Management at Bit
Authors: Aribowo Arviandy G. , Aarsnes Ulf Jakob F. , Detournay Emmanuel , Van de Wouw Nathan , Reimers Nils 
Published: March 2023

Abstract
Over the last years, the use of autonomous solutions for balancing the loading on the drill-bit has increased annually. By 2021, downhole tools for this purpose have been used for more than 1,500 wells and these become possibly the fastest growing trend in drilling. Polycrystaline Diamond Compact (PDC) drill-bits represent a great potential for drilling economics when steady cutting is attainable. Deep drilling, however, typically involves long drillstring causing an array of dynamic instabilities preventing steady cutting conditions at the bit. Such behavior affects drilling performance in terms of the rate-of-penetration (ROP) and system damage and failure. This leaves a big potential for improvement of drilling performance. The first experiments with an autonomous downhole regulator constructed were completed at Ulrigg in Stavanger almost twenty years ago to tap into this potential. Several versions of similar tools have since developed using a variety of mechanical and hydraulic functions to modify and shift the forces acting on the drill-bit in order to improve drilling performance.
The Norwegian operator Equinor has participated from the very start of this new automation trend. By 2020 they had deployed downhole regulators to a total of 93 well sections on the Norwegian Continental Shelf alone. In this paper, Equinor shares statistic plots from comparing these first 93 sections to well section with conventional BHA's. The data show how the continuous improvement of the regulator eventually led to gradual improvement of both ROP and footage - in addition to its initial task of reducing vibrations. By utilizing a variety of dynamic models, predictions and sensitivity analysis, it has been revealed that the downhole regulator could change the dynamic response of the bit such that the friction losses at the bit are reduced and the rock cutting efficiency is improved. In this paper, it is shown that such benefits can also be expected in real-life scenarios in which two key aspects play a role: 1) a PDC bit penetrating heterogeneous layers of rock formations, and 2) involving two frictional losses due to borehole - drillstring contact in deviated wells.
This paper brings a unique insight to the fundamentals, advanced mathematical models, and statistical results from a new line of drilling technology. The autonomous regulators bring a combination of reduction in risk and time to drill that makes a significant impact on cost.
Field Validation of Scalable Condition-Based Maintenance (CBM) of Mud Pumps
Authors: Yoon Dongyoung , Ashok Pradeepkumar , van Oort Eric , Annaiyappa Pradeep , Abe Shungo 
Published: March 2023

Abstract
Although mud pumps are critical rig equipment, their health monitoring currently still relies on human observation. This approach often fails to detect pump damage at an early stage, resulting in non-productive time (NPT) and increased well construction cost when pumps go down unexpectedly and catastrophically. Automated approaches to condition-based maintenance (CBM) of mud pumps to date have failed due to the lack of a generalized solution applicable to any pump type and/or operating conditions. This paper presents a field-validated generally applicable solution to mud pump CBM.
Field tests were conducted during drilling of an unconventional shale well in West Texas and a geothermal well in Japan, i.e., two very different drilling operations, to verify the feasibility and general applicability of the developed pump CBM solution. An accelerometer and an acoustic emission (AE) sensor were attached to pump modules, and data was collected during drilling operations. Anomaly detection deep-learning (DL) models were trained during pump run-time to pinpoint any abnormal behavior by the pump and its elements. The models were trained only with normal state data, and a damage score characterizing the extent of damage to the mud pump was calculated to identify the earliest signs of damage.
The system correctly identifies the degradation of the pump and produces alerts to notify the rig crew of the damage level of key mud pump components. During the field tests, different hyper-parameters and features were compared to identify the most effective ones for identifying damage, while at the same time delivering low false positive rates (i.e., false alarms during normal state pump operation). The developed CBM system provides a generalized solution for pump monitoring, capable of working for different pumps and different operating conditions, and only requires several hours of normal state data with no prior pump information. This system eliminates the environmental, health and safety (EHS) concerns that can occur during human-based observations of mud pump health, and avoids unnecessary NPT associated with catastrophic pump failures. The final version of this system is expected to be a fully self-contained magnetically attachable box containing sensors and processor, generating simple indicators for recommending pro-active pump maintenance tasks when needed.
This is the first successful attempt to validate a universally applicable DL-based CBM system for mud pumps in the field. The system allows more reliable continuous and automated pump monitoring by detecting damage in real-time, thereby enabling pro-active mud pump maintenance and NPT avoidance.
Gas Tight Mechanical Casing Anulus Packer Enables Compliance with Well Design and Barrier Requirements for Re-Entry Multilateral Application in 20+ Year Old Well on Norwegian Continental Shelf
Authors: Hrabovsky Brett , Koberg Ulrich , Roxman Keino , Fagna Jan Ove 
Published: March 2023

Abstract
With continually increasing drilling costs, the importance of utilizing existing slots in offshore platforms has never been higher in increasing average rate of recovery from the Norwegian Continental Shelf. Utilizing existing slots for new targets that were once inaccessible due to a multitude of reasons including technology limitations, value justification, among others pose many challenges for the operator.
One of these challenges specifically relates to compliance with current well design criteria and barrier requirements. As our industry has evolved, more stringent design criteria and additional well barrier requirements ensuring well integrity have become commonplace. In addition, integrity reduction of previously installed downhole components must be accounted for. Utilizing casing strings and polished bore receptacles (PBR's) that have been installed and exposed to harsh downhole environments for 20 + years create a need for innovative solutions
Through this paper we will demonstrate how through proper planning and equipment selection the operator was able to successfully install a gas tight mechanical casing annulus packer in a tieback string. This provided mechanical isolation of the previous casing string that had been exposed to years of wear. Traditional solutions of a tieback seal stem stung into a PBR were not possible due to expected condition of the seal surface in the PBR from years of down hole exposure. The rigorous qualification and validation program of the packer led to its selection in this application. Acceptance criteria of ISO 14310: V0 was used as the basis for testing. This included testing in a casing joint that had been previously installed in a well for 25+ years, mimicking downhole environments for this application.
The annulus packer was installed integral to the tieback casing and activation was combined with subsequent installation of multi-lateral junction equipment. Requiring no dedicated runs for installation or activation provided additional value for the operator. The packer was tested as per well design criteria which allowed the operator to proceed with well construction and continue to new target with upmost confidence in barrier compliance and well integrity.