bluuebunny/crossref_metadata_2025_split huggingface dataset:
Offshore Drilling Improvement Through Automating the Rig State Detection Process - Implementation Process History and Proven Success
Authors: de Oliveira Gabriel L. , Zank Cristiano A. , Costa André F. , Mendes Henrique M. , Henriques Luiz F. , Mocelin Márcio R. , de Oliveira Neto Jorcy 
Published: January 2016

Abstract
A rigorous initiative was undertaken in Brazil 3 years back to identify invisible lost time with the objective to improve safety and performance of the pre-salt drilling program.
This was only possible by combining the following:
Rigorous drilling data quality assurance and recording. Use of automation to correctly identify the rig state using a proven known product. Using an appropriate commercial algorithms and web reporting systems to clearly help analyze the results on both safety and invisible lost time. Building a team of performance engineers to analyze and work with the contractor to help identify areas of safety and performance improvement – the data shows that these two items go hand in hand. A safe crew works consistently well that directly affects performance. Constant re-training and interacting with contractors to ensure that they get to see and understand the variability in their routine operations and perform route cause analysis with the aid of the automation tool.
Among many of the examples presented in the paper will be one on weight to weight connection time of an entire fleet of rigs (23 rigs) that reduced in 19% from 2012 to 2014 through the elimination of unnecessary reaming (that wasn't clearly measured before this effort). Also the variability among contractors is 50% in a wellbore conditioning time per connection that is a huge difference when comparing how similar these operations really were. The paper will also present actual total savings considering several KPIs of about 350 offshore rig days that translates in more than ¼ of a billion dollars.
The conclusion is that a lot can be saved by combining automation, processes, and management commitment at the appropriate mix level – just throwing money at problems isn't necessarily the solution.
Effective Operational Collaboration Delivers Substantial Real-Time Service Quality Improvements
Authors: Sadlier Andreas , Blue Duncan , Halland Thomas 
Published: January 2016

Abstract
Real-time solutions provide a critical decision support and collaboration platform that enable better decisions throughout the well construction and production lifecycle. Operators, drilling contractors, and service companies use these real-time capabilities to improve operations service quality, monitor efficiencies, understand formation geology, and enhance overall reservoir knowledge.
Real-time operating centers are typically staffed with domain experts; they can provide surveillance to support less experienced wellsite personnel, provide advice and guidance, and support remotely performed operations. Data systems must acquire, process, aggregate, distribute, and present relevant real-time information quickly and accurately to ensure a rapid assessment of the current situation. However, their effectiveness depends on adequate real-time service quality and standardized data delivery.
Many factors can contribute to either poor data quality or inconsistent, untimely data distribution. In addition to the most obvious technology limitations, such as available bandwidth, latency, or overall system performance, many nontechnical influences can also negatively affect performance. All too often, technology is relied upon to provide these solutions, and the human factor is taken for granted or ignored. These human factors can include failing to set pre-job expectations, setup and configuration, monitoring protocols, or communication protocols. Other human factors issues can include a lack of data standardization or established governance regarding the management of the data and its underlying quality.
This paper presents a case history that describes how the collaborative effort between a major NOC and service company was used to substantially improve the value delivered from consistent real-time data and service quality. Specifically, this paper addresses the identification of the problem, root cause analysis, and specific remedies that were implemented, as well as clear real-time key performance indicators that could be used to measure and monitor improved performance.
Enhanced Extended Reach Well Design in Saudi Arabia Leads to Optimized Drilling Performance and Significant Cost Reduction
Authors: Muñoz German , Balseiro Prudencio , Dhafeeri Bader , Im Ahmad Ba 
Published: January 2016

Abstract
The Saudi Arabian Oil Company (Saudi Aramco) operates one of the principal high profile extended reach drilling (ERD) projects in the world. This is accomplished through the development of a sizable number of horizontal wells categorized according to the total depth. Wells with the shortest vertical displacement have been significantly optimized during the project execution thereby reducing the room for enhancement. The drilling engineering team conducted a comprehensive evaluation of the existing casing scheme and problematics along the M field. A new approach was devised to redesign wells with a total depth up to 17,600 ft. The aim was to achieve a substantial improvement in drilling performance and potential savings for the remainder of the project.
ML-1 and MO-1 were selected as candidates to implement the novel alternative; both drilled from different platforms where several wells have been previously completed using the standard design. Drilling troubles, such as loss of circulation and hole instability, occurred during the execution of such wells leading to major lost time. The solution comprised the optimization of the well trajectory, slim-down the upper hole sections and combine the lower ones, drill longer intervals and set casings deeper to cover problematic zones without compromising the well integrity. The detailed engineering study included a probabilistic analysis to evaluate the economic viability of the landmark application.
Two wells were successfully drilled and completed applying the downsizing strategy. The impact of anticipated challenging events in both 12 1/4-in and 8 1/2-in holes was decreased as a result of the new design. The implemented preventive plans led to a rapid elimination of encountered challenges. This optimization produced a combined 27% reduction in drilling time, and minimal non-productive time (NPT) with associated global cost savings of 39% compared to a large hole string design.
Finally, this new approach in a still ongoing project along with the feasibility of extending it to other areas will lead to potential improvement in well delivery and operating cost.
Fully Mechanical Vertical Drilling System Delivers RSS Performance in Vertical Drilling Applications While Providing an Economical Alternative to Conventional Rotary Steerable Systems Set-Up for Vertical Hold Mode
Authors: Jones Steve , Feddema Chad , Castro Juan , Sugiura Junichi 
Published: January 2016

Abstract
Deviation control in a vertical well (or the vertical portion of a directional well) can be challenging, especially when pushing the limits for maximum penetration rate. Over the years rotary steerable systems (RSS) have been adapted to fit the vertical drilling market. These electro-mechanical directional control systems are set-up to seek low-side but they come at a relatively high cost of RSS.
This paper describes a purpose-built 100% mechanical vertical drilling system. The vertical drilling system has been developed to drill vertical wells economically with the accuracy and borehole quality of a rotary steerable system. The intelligent mechanical control system has been instrumented to analyze response in different drilling environments throughout North America land. Compact measurement sensors embedded into key components of the tool record system behavior and response.
Through case studies, the effectiveness of the mechanical control system to eliminate deviation on vertical wells will be demonstrated. Onboard memory data from the sensors will be used to examine the stability of the system and prove that simple mechanical control is an efficient and effective method for vertical drilling.
Modeling Real-Time ECD during Transient Pumping and/or Tripping Using Time-Dependent Fluid Properties
Authors: Kulkarni Sandeep D. , Jamison Dale E. , Pereira Vitor Lopes , Porter Aidan 
Published: January 2016

Abstract
Drilling operational parameters, such as pump rate, pipe tripping speed, and drilling fluid time-dependent rheological characteristics can impact wellbore pressure management and equivalent circulating density (ECD). It is important that ECD at any instant remain between fracture and pore pressure gradients (drilling window). This paper presents modeling ECD for transient wellbore conditions, which demonstrates the model predictions match pressure while drilling (PWD) measurements obtained from several wells.
Drilling fluids exhibit time-dependent rheological response particularly at static or low-shear conditions. The fluids develop gel microstructure attributed to interaction between polymers, colloidal particles, and emulsion droplets. As pumping is initiated or pipe moved, ECD spikes occur because of the developed gel microstructure; then, the microstructure breaks down gradually with shearing. Understanding the mechanism of gel formation and breakdown under various shear, temperature, and pressure conditions improves accuracy of the ECD modeling for transient fluid characteristics.
Pump rate can accelerate or decelerate during several operations (e.g., during pipe connections). Another operational parameter, tripping speed, can exhibit variation. For example, pipe speed can accelerate from static to the highest speed; then, decelerate to static. Furthermore, the fluid can be pumped during tripping operations to help manage wellbore pressure. In addition, such pumping helps speed up tripping; thus, saving rig time. The coupled effect of momentum change during these transient operational parameters in addition to time-dependent fluid properties on ECD response is investigated, exhibiting improved understanding of transient effects improves ECD modeling accuracy for such conditions.
The developed models for ECD response were validated on several wells. Fluid properties, real-time pump rate, and tripping speed information were used as model inputs, while outputs were compared with PWD data obtained from the wells. With successful validation, these models can now be used for improved design of operational parameters and fluid characteristics for wellbore management.
A New Friction Reduction Tool with Axial Oscillation Increases Drilling Performance: Field-Testing with Multiple Vibration Sensors in One Drill String
Authors: Jones Steve , Feddema Chad , Sugiura Junichi , Lightey Jeff 
Published: January 2016

Abstract
Weight transfer problems, hanging-up, poor toolface control and diminishing ROP are all problems that are encountered with steerable motors in high angle and horizontal wells. A number of oscillation devices have been introduced to the market over the years to aid these common problems.
Both axial and lateral vibration tools have proven to provide improvements to drilling performance and toolface control. However, as with any device, there are always limiting factors, and oscillation devices could cause unwanted vibrations that interfere with measurement-while-drilling (MWD) systems and even cause component failures.
This paper describes the operation and field-test results from a new axial oscillation tool. The tool uses a mud valve to generate pressure pulses in the string. These pressure pulses are magnified using a specifically designed stroke tool referred to as an amplifier. The mud valve is driven with a short power section from a Positive Displacement Motor (PDM).
The lobe configuration of the power section is directly related to the frequency of the tool, while nozzles in the tool allow for variable pressure regimes of differing applications. The system was tested with specific MWD systems in a flow loop prior to the job to confirm compatibility. Key components in the string were instrumented to gather critical information on vibration frequency levels throughout the BHA in an effort to optimize system performance.
A compact, self-contained 3-axis inclinometers and 3-axis shock sensors (¾-in diameter and 3.8-in length) have been deployed during field testing to capture downhole dynamics. These sensors were strategically positioned in the BHA to gain understanding of vibration propagation distance/pattern and vibration frequency changes over the course of the run.
Downhole instrumented sensors were used to confirm the value of the axial vibration mechanism. The use of multiple compact downhole dynamics recording devices has provided new insights in challenging steerable motor drilling applications, assisted with an axial friction reduction tool.
Implementation of Wired Drill Pipe Saved Multiple Days Per Well, by Addressing Performance Limiters, Increasing Drilling Efficiency
Authors: Teelken Reina , Jaring Colin , Craig Andrew , Allan Roy , Roberts Huw , Hatch Andy , Shepherd Nicol 
Published: January 2016

Abstract
This paper will discuss the implementation of the Wired Drill Pipe telemetry on two wells of the Babbage development project in the Central North Sea and will present the quantified efficiency gains achieved across various drilling operations.
Wired Drill Pipe (WDP) telemetry enables bi-directional, high speed data transmission to and from downhole tools at speeds up to 57,600 bps (Olberg et al. 2008). This enables real-time "recorded" quality MWD and LWD data to be transmitted instantaneously to surface, as well as near-instantaneous commands ("downlinks") to be sent to MWD, LWD and RSS tools while drilling.
The contribution of WDP telemetry to well placement and Geosteering on the Babbage development project has been published previously (Hatch, et al. 2011).
This paper however, will present the efficiency gains and corresponding time savings that WDP telemetry enabled through the instantaneous transmission of data up and down the drillstring. A detailed analysis of the two WDP wells drilled with WDP telemetry will show the quantified time savings when compared to three wells drilled with conventional mud pulse telemetry.
The analysis will compare the time spent on several activities including the transmission of downhole data to surface and vice-versa, the frequency of unplanned bit or BHA trips and on-bottom drilling time. The analysis will account for the differences in BHA designs, well paths and controlled drilling practices.
Compared to the Babbage wells, drilled with mud pulse telemetry, a reduction of multiple days per well can be inferred through the increased efficiency of these operations and activities.
Collapse Strength of Casing Subjected to Combined Load
Authors: Greenip J. F. 
Published: January 2016

Abstract
Triaxial evaluation of loads is used extensively for casing and tubing string design and analysis. The paper presents a method of determining the triaxially based collapse strength of casing and tubing subjected to simultaneous axial and internal pressure loads. The triaxially based collapse strength method was recently adopted by the American Petroleum Institute (API) and an addendum issued to API Technical Report 5C3 (TR 5C3). Casing and tubing subjected to combined loads have higher collapse strength than previous formulas predict.
The triaxially based formula presented incorporates internal pressure and axial load simultaneously into the calculation of casing and tubing collapse strength. The formula is compared to the previous First Edition TR 5C3 uniaxial method of accounting for internal pressure. The paper compares both the uniaxial method and the new triaxially based method with API combined load collapse test data, validating the triaxially based formula. Casing design examples contrast the uniaxial method with the triaxially based method, showing the higher collapse design factors calculated when using the more accurate triaxially based formula.
Innovative Ability to Change Drilling Responses of a PDC Bit at the Rigsite Using Interchangeable Depth-of-Cut Control Features
Authors: Kenneth Evans , Russell S. Craig 
Published: January 2016

Abstract
Bit designers use the well-established practice of placing depth-of-cut (DOC) control features at strategic heights from the cutter profile to selectively manage drill bit aggressiveness and to maximize drilling performance. But, until now, the elements used for depth-of-cut-control were a fixed part of the bit. An innovative new feature enables compact element replacement and/or adjustments at the rig site using a mechanical locking design. The driller can quickly adjust the bit responsiveness before each run, if wanted, to optimize performance factors such as rate of penetration and tool face control. This paper describes the benefits, ease of use, positive results and reliability of this new technology with examples from multiple applications for a variety of bit designs.
The final design was selected and validated based on a number of evaluation methods including concept screening tests, simulated laboratory drilling tests and field tests. The initial screening tests evaluated the ease of compact installation and removal for various concepts using a test block. Full bit testing using a full-scale, high-pressure, downhole drilling laboratory evaluated installation, integrity and aggressiveness response changes using compact height adjustments. Finally, multiple field tests on wells in North American applications of the Eagle Ford, Marcellus, and DJ basin formations provided data to refine the mechanical design and improve manufacturing processes to achieve a robust technology.
Field tests proved the new design to be highly reliable, with drilling performance that matched or exceeded the performance of bits with standard brazed compacts in the same fields. This new design provided the unique ability to rapidly optimize bit responses. This paper describes the technical lessons learned, guidelines for use and tools developed to maximize the benefit from this innovative new feature.
This new method enables compact element installation and removal within fifteen minutes on the rig site for the purpose of repair or aggressiveness modification. In contrast, traditional methods of DOC control include long lead times to alter bit design, manufacturing and delivery. Drillers can reap the immediate benefits of improved bit performance by changing bit design on the rig site using direct feedback of bit aggressiveness and steerability between runs without needing multiple bits on site. Ultimately, this new bit technology provides improved drilling performance and greater efficiency for the operator.
World Record Using the Steerable Drilling Liner Technology to Secure Previously Non Drillable Section in Unstable Shale
Authors: Bossis Vincent , Grindhaug Gaute , Eidem Morten , Fjorden Jan , Ringstad Jim Roger 
Published: January 2016

Abstract
Challenging environments such as unstable clay formation represent high operational risk when running tubular after drilling is completed. Use of Steerable Drilling Liner (SDL) system combines drilling and casing of the hole, thereby mitigating the risk of not being able to run the liner due to time dependent formation collapse.
This case study presents the difficulties encountered with a Semi-Submersible rig on the Åsgard / Midgard field in the North Sea during 7″ liner running operations in unstable clay formation using the conventional approach (drilling 8 ½″ section first and then running the 7″ liner), the planning of a SDL operation, and the execution of the SDL operation as well as results compared to similar operations.
The components of the SDL system will be reviewed and explained. Detailed planning is crucial for a successful SDL operation. The simulation work will be described with focus on ECD management and hole cleaning strategy. Torque and drag will also be covered. Actual drilling parameters will then be compared with the simulations.
Two attempts were made to complete the section using conventional technology. It was decided to plan and execute a sidetrack operation with the SDL system after numerous unsuccessful attempts to run the 7″ liner. Drilling operation with SDL was carried out as planned. No major drag was found over the whipstock despite the high local dogleg. Very smooth drilling operation with steady drilling parameters was experienced during the execution and the rate of penetration was comparable to drilling the section conventionally. ECD was slightly lower than simulated but around 2 points higher than with conventional drilling. Good hole cleaning was achieved despite a challenging well geometry and the liner was left in hole after drilling was completed. The liner hanger was then run and set before the cementing operation started.
The SDL system allowed drilling more than 1000m of the 8 ½″ section, making this operation a new world record and turning the well from an economic disaster to a complete success.
The SDL system is a relative new technology under continuous improvement. The primary application of this system is its use in unstable formation where it is anticipated problems for running the liner conventionally. Indeed, shocks and drilling energy transmitted to the formation is greatly reduced with this system, preventing time dependent phenomena such as hole collapse.
A New Steady Weight-on-Bit Tool Reduces Torque and RPM Variations and Enhances Drilling Efficiency and Bit/BHA Life
Authors: Jones Steve , Feddema Chad , Sugiura Junichi 
Published: January 2016

Abstract
Maintaining steady weight on bit (WOB) while drilling can be difficult at depth due to drill string flexibility, wellbore friction and downhole dynamics. Variable slack-off weights and drill string buckling results in un-steady WOB that generates string- and bit-induced stick-slip and torsional vibration.
Variable string rotation speed in revolutions per minute (RPM) and differential mud motor pressure causes changes in length of the drill string. These changes in length are directly acting on the drill bit and can result is a very chaotic drilling situation that is extracting energy from the drilling process.
This paper describes the operation and field-test results from a new tool designed to maintain steady WOB. The constant weight on bit tool was instrumented with sensors to gather critical information on inclination, sliding toolface, vibration, string rotating speed and erratic RPM events.
The data gathered is presented to show downhole drilling dynamics improvements with the steady WOB tool incorporated into the bottom-hole assembly (BHA).