bluuebunny/crossref_metadata_2025_split huggingface dataset:
Toward Drilling Automation: On the Necessity of Using Sensors That Relate to Physical Models
Authors: Cayeux E. , Daireaux B. , Dvergsnes E. W. , Florence F. 
Published: March 2013

Abstract
Current top-side and downhole instrumentation at the well site has been developed for the purpose of manually conducted drilling operations. The emergence of automatic drilling analysis software shows the limitations of today's measurements capabilities. It is therefore time to analyze the requirements for onsite instrumentation in order to implement new, efficient drilling automation technologies.
On one hand, drilling is facing more and more difficult conditions with narrow geo-pressure windows, deep water or high-pressure and high-temperature (HPHT) conditions. On the other hand, unconventional hydrocarbon reserves may require a considerable amount of wells to be profitable. Drilling automation, by means of smart safeguards, automatic safety triggers, managed pressure drilling (MPD) and ultimately complete or semi-autonomous drilling rigs can provide the solution to safely construct wells in these challenging settings.
The common denominator for the vast majority of drilling automation solutions is the use of physical models of the drilling process in the form of heat transfer, mechanical and hydraulic models. By analyzing the requirements of those models for necessary boundary conditions, it is possible to derive which measurements should be made both at surface and downhole in order to obtain stable and accurate calculations. This analysis also provides a way to estimate the necessary accuracy of the boundary conditions to ensure reaching the target control tolerance.
Using the boundary condition analysis, it is possible to derive precisely which measurements should be done and where they should be performed. As a result, a typical organization of sensors that is compatible with the implementation of drilling automation solutions is derived.
First Oil Requirements Drive Simultaneous Drilling and Subsea Construction Operations on UK Central North Sea Development
Authors: Allan R. M. , Arain Z. , Fraser B. , Short S. , Davidson S. 
Published: March 2013

Abstract
Accelerated production targets in the field development plan of this United Kingdom Continental Shelf (UKCS) project drove the requirement for design and drilling of four production and two injection wells with concurrent subsea construction and planned production start up. The paper's objective is to demonstrate that the use of a jack up with subsea template and high pressure riser is a worthwhile subsea well development method. The individual technical solutions brought together during the well construction process are described with reasons for their selection. The Performance Improvement Process that was developed and used to allow continuous improvement and facilitate change both on and offshore is reviewed. The paper focusses on well construction and will not consider the specific detail of the project's subsea infrastructure and production units.
The project brought together the following technical elements to deliver a successful campaign: Mobile Offshore Drilling Unit operations with modifications to allow tree running from deck, high pressure riser design and analysis, subsea wellhead operations, modifications to existing subsea trees, use of Riserless Mud Recovery system during batch drilling operations, template design and reservoir steering technologies.
Results are that activities improved from well to well with little impact on subsea construction and this can be demonstrated by performance data. The conclusions are that jack up operational efficiency was achieved on the subsea development and delivered cost effective well construction during simultaneous operations. A change in operational mindset can be achieved to allow subsea activities and equipment to be run from a jack up unit. Rigorous application of a Performance Improvement Process can enable change and help to manage project complexity.
The activities described in the paper can be applied to marginal developments where accelerated production is a driver or rig market constraints are a factor during rig type selection.
Feasibility Study of Applying Intelligent Drill Pipe in Early Detection of Gas Influx during Conventional Drilling
Authors: Karimi Vajargah A. , Miska S. Z. , Yu M. , Ozbayoglu M. E. , Majidi R. 
Published: March 2013

Abstract
Conventional well control procedures rely merely on the pit gain and variations in pump pressure as the primary indicators to detect and handle the influx. These indicators are rudimentary and unreliable for drilling costly offshore wells while advanced well control techniques demand more reliable indicators for early detection of gas kicks. Having access to continuous pressure data along the wellbore, offered by intelligent (wired) drillpipes, can be very helpful in detecting and handling gas kicks.
This paper proposes a technique for early gas detection during conventional drilling by utilizing the intelligent drill pipe. For this purpose, different flow regions in the annulus are identified and modeled based on the conservation equations. A numerical scheme and transient gas kick simulator are developed to solve the equations. Sensitivity analysis is conducted for various parameters such as influx sizes, mud flow rates and wellbore geometry.
The results indicate that when gas influx enters the wellbore, pressure at all sensors increases simultaneously. This criterion can be used for early detection of gas kicks; In addition, when top of gas influx passes a certain sensor, pressure curve at that sensor declines. This fingerprint can be utilized in determining the location of the gas kick. This can be done even more precisely when pressure derivative curves are plotted to determine the time that a gas influx reaches a certain sensor.
Using intelligent drill pipes in modern well control operations can reduce kick detection time to less than half, which results in significant reduction in non-productive time and enhancements in safety. The developed simulator provides a powerful tool that can contribute to well control practices and real-time decision making.
RFID. A Key Enabler In Drilling Automation
Authors: Grinrod Mads , Vonlanthen Manfred , Haaland Arne Thomas , Gaasoy Rune 
Published: March 2013

Abstract
Drilling automation is gaining momentum and is a topic of high interest in the drilling community. In present drilling operations automation is still in its early phase. Several technology gaps have to be closed.
Use of technology to automatically identify various equipment and tools used in the drilling process and automatically deliver this data to control systems and to real time predictive modeling equations is considered to be a key enabler in drilling automation.
Radio Frequency Identification (RFID) for drill pipe has been developed to withstand temperature and shock/vibrations encountered in most wells. This paper outlines the technology development of RFID tags and status for application on drill pipe. Key challenges have been temperature limits, vibrations, wear and max tripping speed to pick up radio signals. Further the paper outlines present software applications and future possibilities in software development using RFID data as input. It will be presented how RFID helps in avoiding drill pipe failures, and how RFID will be used as an enabler in the future in drilling automation, predictive modeling and in real time decision making.
A Collaborative Approach for Planning a Drilling With Liner Operation
Authors: Rosenberg Steven M. , Cummins Tracy J. , Dunn Timothy P. , Tan Ming Zo , Winchell Rex L. 
Published: March 2013

Abstract
This paper will illustrate the collaborative approach an international integrated oilfield service company used for planning a Drilling with Liner (DwL) operation to isolate a 6.5 ppge depleted sand interval in a deepwater block of Mississippi Canyon in the US Gulf of Mexico (GoM). Early collaboration between the service company and operator identified DwL technology as the core technology to meet the operator's well objectives. The DwL process allows a hazard interval to be isolated in a single trip resulting in less risk and wellbore exposure compared to the use of conventional drilling methods. Since DwL technology encompasses multiple engineering disciplines, these disciplines must be integrated in a seamless manner, and not be treated individually, to ensure the DwL objectives are met. To accomplish this, the service company formed a dedicated well engineering team to collaborate early on with the operator in their well planning process.
The technical disciplines identified to ensure the planned 9-7/8 -in_liner string reached its planned depth while also providing a secure wellbore over the entire life of the well included:
Torque, drag and hydraulics modeling of the liner running and drilling operation, Connection cyclic fatigue analysis, Directional tendency modeling Casing cementation hardware Formation drillability analysis
The aforementioned analyses and modeling resulted in the selection of optimum liner related equipment with the associated DwL procedures that would best deliver a high-integrity wellbore to the operator over the life of the well.
During the planning phase, regular operator-service company communications along with project scheduling software gave the operator assurance that agreed upon deliverables would be completed in the allotted time frame with the intended well objectives met. This paper will present the DwL planning process, description of mechanical and hydraulic concerns, and the associated risk assessment modeling to ensure that safety, environmental and DwL objectives were met.
On the Path for Offshore Drilling Automation
Authors: Martins A. L. , Gandelman R. A. , Folsta M. G. , Resende E. L. , Vega Marcia , Aguiar Romulo , Pirovolou Dimitrios , Gullo R. March 
Published: March 2013

Abstract
This article summarizes efforts conducted by PETROBRAS and partners aiming offshore oilwell drilling automation. The first step includes the implementation of a drilling problem detection software which operates with online real-time data analysis. The second step includes the concept of an integrated model to represent the process of drilling and the third an experimental pilot scale facility constructed to test control algorithms for MPD and influx control operations.
Calibrating Automated Event Detection Algorithms for Real-Time Wellbore Stability Applications
Authors: Wessling Stefan , Bartetzko Anne , Tesch Philipp , Dahl Thomas 
Published: March 2013

Abstract
Improvement and automation of real-time drilling operations obtained significant attention during the last few years, aiming to substantially reduce non-productive time and increase safety. Wellbore instability is one of the operational challenges that can be mitigated by proactive analysis and interpretation of logging-while-drilling (LWD) and measurements-while-drilling (MWD) data. That data can be used to detect events such as kicks or losses as potential drilling complications. Successful implementation of supportive automated systems requires proper management of generated alarms to deliver reliable results. Minimization of false alarms and the classification of alarms according to their severity are necessary to provide a capable system. Following an introduction into drilling automation and wellbore stability analysis, this paper presents different approaches for the automatic analysis and interpretation of formation evaluation logs for the detection of drilling events. These algorithms were extensively tested on more than 30 data sets. The approaches are beneficial for monitoring the wellbore conditions and to alerting workers about potential overpressure regions and breakouts in the formation around the borehole. Test observations were used for developing an automated alarm and advice generation system. Alarm generation experience from within other communities and its comparison to the oil and gas industry is highlighted. Automated algorithm and alarm generation test results provide insight into the possibilities and limitations currently encountered in the application of LWD / MWD logs for the automated detection of drilling challenges. Testing has proven to be essential for identifying operating constraints that must be addressed to minimize erroneous alerts.
Casing Design for Dual Gradient Wells
Authors: Cantrell Andre J. , Duan Mingqin 
Published: March 2013

Abstract
When planning dual gradient wells, it is important to understand the details of dual gradient drilling (DGD) operations and the resulting loads exerted on the casing strings in the wellbore. Standard casing design loads for conventionally drilled wells must be modified so that they apply to dual gradient drilling, and there are additional load cases specific to DGD that must be considered.
This paper outlines those factors that should be accounted for in dual gradient casing design as compared to conventional deepwater casing design, including:
Internal and external pressure profiles for typical deepwater casing design load cases for drilling and production strings. Additional load cases that should be considered for dual gradient drilling, such as running/cementing casing with an air gap in the string and tension/collapse combined loading when running in the hole. Application of dual gradient pressure profiles to worst-case discharge load cases. Annular pressure buildup analysis for dual gradient wells. Negative test magnitudes and procedures.
While the dual gradient casing design loads are generally less severe than the corresponding load cases considered in conventional deepwater casing design, there are instances in which this does not hold true. Additionally, the collapse loads can be much greater than conventional due to the u-tube that exists during dual gradient operations. A thorough understanding of dual gradient operations is required to conduct a proper, diligent casing design that ensures a safe and efficient well plan and execution.
Dynamic Cementation: A Solution to Well Integrity Problems
Authors: Holt Calvin , Lahoti Nilesh , Fortier Vince 
Published: March 2013

Abstract
Whether operators are drilling extended reach wells in prolific shale plays or offshore HPHT wells, well integrity remains the critical concern. Effective zonal isolation using cementing techniques is essential to mitigate risks and non-productive time associated with leaks, corrosion and contamination.
Although well researched and considered a mature discipline, effecting cement placement in the annulus still has a significant degree of uncertainty. As global regulatory agencies respond to public concerns with drilling operations either in deepwater or unconventional plays, the industry is reviewing well construction best practices to reduce risk. The discipline of cementing has been given renewed focus.
In spite of the industry's detailed understanding of the advantages of reciprocating and rotating casing during cementing operations it is applied to less than 10% on wells globally. This mechanical method, although proven to be the most cost effective remains the least applied. Why?
A proven emerging technology, drilling with casing (DwC), developed the modern casing running tool (CRT). Using tools and drilling engineering methods developed from over 4,000,000 feet of drilling with casing; rotating casing to ream and while cementing is now a low risk activity.
Employing the CRT on conventional casing running jobs delivers a measurably higher degree of probability that casing while reach bottom and effective zonal isolation by cement has been achieved.
A new method of dynamic cementation, where pipe movement is maintained until cement begins to set maximizes the mud-cement displacement process. It can achieve a high quality completion using a combination of modern cementing software, real-time rig instrumentation and casing rotation/reciprocation with a CRT monitored to planned torque and weight levels while cement is pumped in the annulus.
In this paper, barriers to change, a new methodology with its classification of dynamic cementation levels and field examples are presented. It investigates the positive effect of casing movement during cementing and reviewing cement bond logs.
LWD Sonic Cement Logging: Benefits, Applicability, and Novel Uses for Assessing Well Integrity
Authors: Blyth Matthew , Hupp Douglas , Whyte Iain , Kinoshita Toshihiro 
Published: March 2013

Abstract
With the ongoing changes affecting the global drilling industry, well integrity has become an area of great engineering focus and development. Cement bond analysis is of key interest as the consequences of failed, or partially complete, cementing operations can, at best, be a costly delay in drilling operations and, at worst, an extremely hazardous safety issue. Traditionally, wireline acoustic tools have been used to analyze the quality of the cement bond between the casing and the formation. Wireline tools have been developed over many years to produce high-quality assessments of cement bond, which can then be confidently used to confirm well integrity. However, the conveyance method requires that the analysis be performed on the critical path and also that additional methods be used in high-angle wells. Logging-while-drilling (LWD) technology offers a potential alternative without these issues, provided the current limitations of the technology are understood and its applicability properly assessed as a fit-for-purpose solution. As a minimum, the LWD logging technique can provide a trigger as to whether more advanced logging techniques must be deployed or can be avoided.
This paper explores the applicability of LWD sonic tools to the analysis of cement behind casing. It considers both the currently accepted deliverable of top of cement (TOC) analysis, along with examples of more advanced processing techniques and their comparison to wireline cement evaluation, providing case study examples in each case. The benefits and limitations of these methods will be discussed, along with operational considerations to aid in successful logging, including the use of repeat logging passes to indicate changes in cement quality with time. The use of LWD sonic tools to identify casing collar connections on driller's depth, enabling the safe positioning of cased-hole whipstocks, is also covered, demonstrating a novel and little-used application of LWD technology.
Pre-Job Modeling/Resulting Integrated BHA System Solution Sets Multiple ROP Records, North Field Qatar
Authors: Kieschnick Michael L. , Jacob Tony , James Biju , Karuppiah Venkatesh , Hamilton Rob , Bits Smith 
Published: March 2013

Abstract
Drilling the 12¼-in tangent section (55-60°) through thick carbonate lithology in Qatar's offshore North Field is exceptionally challenging. In spite of bottom hole assembly (BHA) and parameter adjustments, the operator regularly experiences severe impact induced PDC cutter damage resulting in reduced bit life. Lithology (Hith to Khail) is predominantly interbedded carbonate/anhydrite, dolomite/argillaceous limestone with unconfined compressive strength (UCS) ranging between 9000-30,000psi. The operator wanted to improve rate of penetration (ROP) by stabilizing the bit body and reducing micro-balling tendencies. The objective would be to complete the 6000ft section in one bit run at a minimum ROP of 2000ft/24hr.
An FEA-based modeling system, rock strength identification program and computational fluid dynamics (CFD) analysis was used to investigate several 12¼-in PDC bit designs. The results of the simulations led to a new MSi716 design with back-up cutters strategically positioned on all blades to provide maximum durability in critical wear areas. After reviewing the results of the analysis, the operator requested additional bit design changes including a 6-in tapered gauge and managed depth-of-cut in the cone/nose areas to reduce reactive torque. A parameter sensitivity study was conducted to determine the optimal operating window (WOB/RPM) and to ensure the new PDC design would be compatible with a unique high-torque RSS which allows for higher weight on bit than standard rotary steerable systems to maximize rate of penetration potential.
The new design was run on the high-torque RSS/motor system and drilled 6,001ft of 12¼-in section at a high ROP of 139.4ft/hr setting a new North Field record. The average daily footage was 2572ft besting the old mark by 38%. Additionally, the run set a single 24hr footage record of 3100ft/day, 29% better than benchmark. Based on this outstanding bit performance the operator made these design changes a standard requirement for PDC bits in this application. The new design also helped standardize mechanical specific energy (MSE) values for future ROP gains.
New Directional Drilling Simulation Tool Reveals Link between Dynamic Stability and Tool Face Control
Authors: Spencer Reed , Hanson Jonathan , Hoffmann Olivier , Kulkarni Ajay , Allison Cliff 
Published: March 2013

Abstract
The development and use of enhanced directional drilling software modeling tools are outlined. A fully dynamic drill bit software simulator is introduced with the capability of modeling rock removal done by cutters as well as gage pads, bit blades, and non-cutting elements which can wear and crush the rock. Side-cutting simulations with gage pad/rock interaction are presented and compared to side-load lab test data at atmospheric pressure. Good agreement between the simulation and the lab is demonstrated.
Using this dynamic drilling simulation software, a common directional drilling challenge—holding tool face orientation—is investigated. The case is made that tool face control problems can be caused by dynamically unstable drill bits in addition to commonly cited causes. The software is used to simulate the dynamic behavior of 21 bits from the field that had been used on motors with bent AKO. Bits with excellent tool face control in the field are found to be more dynamically stable than bits with poor tool face control. The link between instability and tool face control problems is shown to be the increased torque that accompanies dynamic instability, or bit whirl. The relationship is illustrated with two case studies—one in southern Texas and one in central Oklahoma. Both case studies examine tool face performance in the field using the enhanced simulation software.
Design, Development, and Field Testing of a High Dogleg Slim-Hole Rotary Steerable System
Authors: Hawkins Richard , Jones Steve , O'Connor James , Sugiura Junichi 
Published: March 2013

Abstract
High dogleg rotary steerable systems (RSS) were introduced for general industry use in 2011. These systems were developed for high dogleg shale applications in North American land operations. The initial systems were 6 ¾-in. These tools were designed to produce up to 15°/100 ft in 8 ½-in. to 8 ¾-in. hole size. High dogleg tools for different borehole sizes followed. The requirement for high dogleg RSS is now global, and the systems are being used to drill in areas where steerable motors previously dominated because of their higher dogleg capability. A new 4 ¾-in. RSS has been designed for high dogleg (15°deg/100 ft) and dogleg assurance applications. Additionally, a new high dogleg RSS for 5 7/8-in. to 6 ¾-in. hole sizes has been developed and field tested. The new slim-hole high dogleg RSS has proven to perform well and be a cost-effective solution in specific applications, such as difficult formations and multilateral well construction.