bluuebunny/crossref_metadata_2025 huggingface dataset:
Remote Operations Center - An Efficient and Highly Competent Environment to Optimize Operational Performance and Reduce Risk
Authors: Thorsen Arve K. , Sæverhagen Erland , Dagestad Jan Ove
Published: March 2013

Since the late 1990s, remote operations centers have focused on infrastructure and remote data gathering as some of the key resources in the intelligent oil field. Data gathering has low direct value unless used to mitigate risk and enhance operational efficiency. Rigsite experts work under the framework of health safety and environment (HS&E) and operational progress, with limited ability to analyze data. There is limited value in data gathering without real-time analysis of the information. This analysis is becoming one of the most important factors of daily work in remote operations centers. Real-time analysis is performed by multi-disciplinary teams, and remedial action can be taken immediately to mitigate risk. This is the strength and force of the operational centers; available interpretation technologies and time to perform the tasks in an environment without the rigsite stress factors.

During traditional operations, the wellsite personnel are responsible for the well and for ensuring nothing hazardous occurs, or taking action before or after an unwanted occurrence. In many cases, this is too late. Operations center planning, modeling and analysis – to avoid unwanted situations - are all part of the operational procedure, providing trends and thresholds for procedure change prior to an incident.

The wellsite personnel determine indications of well instability with potential to lead to extensive use of resources to ensure stable conditions. This is often based on experience and local knowledge.

The onshore team focuses on proactive processes to ensure the overall operational progress is conducted in a safe manner.

To illustrate data gathering and risk mitigation of a remote operational center, the BEACON center concept is used to display rigsite workflow, data analysis and feedback for maximum progress and minimum risk. Subsurface knowledge through drilling optimization and BHA reliability will be covered.
A Breakthrough Performance for an Inland Application with a Hybrid Bit Technology
Authors: Di Pasquale M. , Calvaresi E. , Pecantet S.
Published: March 2013

This paper describes the field experience of a new hybrid bit based on proven polycrystalline diamond compact (PDC) bit designs with rolling cutters on the bit periphery. A hybrid bit can drill shale and other plastically behaving formations up to three or four times faster than a roller-cone bit by being more aggressive and efficient.

The penetration rate of a hybrid bit responds linearly to revolutions per minute (RPM) unlike roller-cone bits, which have an exponential response with an exponent of less than one. In other words, the hybrid bit drills significantly faster than a comparable roller-cone bit in motor applications. Another benefit is the effect of the rolling cutters on the bit dynamics.

Compared to conventional polycrystalline diamond cutter bits, torsional oscillations are as much as 50% lower; stick/slip is reduced at low RPM, and whirl at high RPM. This gives the hybrid bit a wider operating window and greatly improves toolface control in directional drilling.

The hybrid drill bit technology combines roller-cone and PDC bits into a single patented design, employing the best attributes of each bit type to improve reliability and efficiency, while ensuring performance consistency in the most problematic applications. This revolutionary technology has a large spectrum of applications, excelling in typically troublesome formations for PDC and roller-cone bits, such as interbedded hard and soft stringers or hard nodular inclusions.

The results of a field test in an inland application will be presented, comparing the performance of hybrid bits with conventional PDC and roller-cone bits used on offset wells.

A planning and engineering process was applied, ensuring high-quality support to the operator in the office and at the rigsite. The client saved multiple conventional tungsten carbide insert bit runs and drilled 100% farther, ultimately achieving a rate of penetration (ROP) two times faster than the best tungsten carbide insert (TCI) bit run in the same well.
Analysis of Potential Bridging Scenarios During Blowout Events
Authors: Willson S. M. , Nagoo A. S. , Sharma M. M.
Published: March 2013

This paper demonstrates how simulation of wellbore pressures during different blowout scenarios; borehole stability analysis and solids transport can be applied to the problem of blowout risk assessment. This is a technology area that previously has been overlooked by petroleum geomechanics practitioners. The proposed analysis methodology emphasizes the importance of understanding the transient evolution of the kick within the borehole, as this is a key factor in assessing whether bridging is likely to occur during the events leading up to a blowout. Three representative situations are analyzed and conditions leading to self-killing are reviewed. Analyses of a shallow-gas kick and blowout reproduce the numerous field observations that self-killing is likely from the combination several possible mechanisms – borehole collapse of soft shales, sand erosion leading to cavity collapse in the initially-overpressured aquifer zone, gas depressurization and brine influx. For deeper water scenarios a sudden failure of the marine riser while drilling-ahead is expected to result in conditions where self-killing occurs. The rapid reduction in wellbore hydrostatic pressure following the loss of the riser margin is considered sufficient to initiate borehole failure that causes a cavings-loading that chokes the hydrocarbon influx, so allowing settling of the entrained solids and plugging of the borehole. In contrast, a more slowly-evolving swabbed kick is not expected to be self-killing. Here the slow progression of borehole instability is not expected to impede the increasing kick flow-rate. It is hoped that by presenting these analyses the industry may become better informed of the geomechanical and borehole stability aspects of kicks and blowouts, and that as a consequence well designs in deep-water can become more robust and inherently safer.
Design Aid for Charting a Drilling Automation Roadmap
Authors: Zamora Mario , Hildebrand Ginger
Published: March 2013

1202 PROGRAM ALARM This disturbing alarm, displayed to the men on location and in a remote center during the most critical part of the operation, signaled that the onsite computer system was no longer able to handle its automated multitasking requirements. The crew was forced to assume manual control to complete the operation, but not without continued assistance from onsite computers and engineers monitoring the event in the remote center. A short time later came the announcement heard by 600 million people around the world - "Houston, Tranquility Base here. The Eagle has landed. " Neil Armstrong had safely landed the Apollo 11 Lunar Module on the Moon.

Automation, perhaps the most game-changing opportunity in drilling today, is improving operational safety, efficiency, quality, and economics. More importantly, automation is making possible the execution of operations and activities difficult or even impossible for rig crews to complete using traditional methods. Notable recent success notwithstanding, the uptake of automation could be accelerated by the creation of industry-wide and segment-specific technology roadmaps to define short- and long-term goals and track progress. While most technology roadmaps are extensive and detailed documents, they must be built on a solid foundation that represents an overall view of the technology. Presented in this paper is a new design aid developed precisely for creating and displaying this view. For drilling automation in general and any number of specific operations and supporting technologies, the design tool can visually illustrate current and future (desired) states and the path(s) connecting the two. This visual approach also serves to catalyze discussion of this important topic.

The design tool presented here is a radically different way to create a technology roadmap overview. It is based on the common ternary chart, a triangular diagram that graphically depicts the composition of three-component systems. For drilling automation, the three components are rig equipment automation, rigsite manpower, and engagement from remote operation centers. Proportions of the three variables total 100% by definition. Simply stated, this means that a reduction of personnel on board, for example, must be balanced by increased automation of rig equipment and/or a higher level of engagement from remote operation centers.

The primary objective of this paper is to describe the underlying technology of this drilling-system automation design aid and to demonstrate how it can be used for real-world applications. There is no intent to present hard data that could be used directly to generate automation roadmaps for drilling.
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

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

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

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

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

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

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

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

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

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

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

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

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

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.
Automatic Mud Mixing
Authors: Nafikov R. R. , Glomstad M. S.
Published: March 2013

The current paper represents an overview of the automation model for drilling fluid mixing and is based on thesis works of (Nafikov 2011) and (Glomstad 2012).

The first part of investigation is based on a model developed with the help of MATLAB® and SIMULINK® softwares. The simplified mud circulation model consists of downhole and mud mixing systems. The well is divided into control volumes to imitate the moving of drilling fluid inside the drillstring and the annulus and to include disturbances such as production of cuttings and mud losses to the formation. The possibility of monitoring the downhole pressure is included as well. Mud mixing system is represented in a way of addition of chemicals for mud treatment, i.e. viscosifier (bentonite), densifier (barite) and the mud dilution property with the help of water addition. The addition of all chemicals is controlled by PID controllers. Mud mixing and downhole systems interact between each other during simulations. When fluctuations in a form of cuttings or mud losses occur in the dowhole system, the mud mixing system adapts all PID controllers to keep the desired mud properties. The performance of the model is shown in the case of closed-loop simulations. Obtained results show the expected behavior of all variables and the possibility of automatic control.

The second part of investigation will look at two principles for control of the mud mixing: cascade control and model predictive control. Compared to conventional PID-controllers with a single feedback loop, the cascade structure can utilize measurements both in the mixing tank and where the mud flows out of the well together. Continuous measuring of the mud properties is assumed. Also a controller based on model predictive control has been designed and tuned by using SEPTIC, an MPC tool developed by Statoil. The MPC controller calculates optimal inputs by minimizing a cost function subject to process constraints, defined priority levels and deviation penalties. Calculations are based on density and viscosity models found by looking at open-loop simulations of system responses to a change in different input variables. Closed loop simulations have been performed using both MPC and cascade controllers. A model for the well, "WeMod", is provided by IRIS and simulates the behavior of an actual well so it is seen how downhole conditions influence the density of the mud.
Instrumented Internal Blowout Preventer Improves Measurements for Drilling and Equipment Optimization
Authors: Wylie Robert , Standefer Jim , Anderson Jason , Soukup Ian
Published: March 2013

An optimized drilling system is only as efficient as the quality and accuracy of its supporting instrumentation. An increase in drilling performance, efficiency, reliability, and safety follow each new generation of measurement technology, all of which are invaluable to drilling operators and the industry.

A new system, the Instrumented Internal Blowout Preventer (IIBOP), is designed to provide accurate drilling parameters directly from the drillstring. Like other instrumentation, the goal is to allow for better decision making with regards to well construction, and to provide early warning signs of system failure or well control situations. However, other instruments are not effectively positioned to measure the load with the high degree of accuracy demanded by today's drilling operations. Reducing this error by measuring the load directly at the drillstring provides a measurement that is highly refined for today's modern control systems.

The IIBOP makes direct-load measurements along the drillstring just below the main shaft of the top drive, thereby circumventing the errors of the traditional measurements. The sensor package enables real-time streaming of data, within milliseconds, at sample rates up to 500 Hz, providing a timely series of direct measurements needed to characterize drillstring phenomena required for drilling and equipment optimization purposes.

In the IIBOP field testing, real-time string weight measurements exhibited 65% signal noise reductions compared to deadline anchor load cells, allowing for better representation of string dynamics previously undetectable. Noise was reduced in the IIBOP pressure measurements even further, by 90% when compared to the rig-supplied standpipe pressure transducers, permitting higher fidelity data for dynamic pressure event analysis. IIBOP-measured rotational velocities were also subject to less noise, while capturing both speed and direction, typically not provided by the top drive. Along with conventional measurements, the IIBOP provided entirely new parameters—bending moment and main shaft acceleration—both of which have great potential to correlate data with downhole instruments or to schedule preventative maintenance. This paper discusses the IIBOP capabilities, each parameter it measures, and test performance data compared to traditional sensors.
Drillstring Analysis with a Discrete Torque-Drag Model
Authors: Mitchell Robert F. , Bjørset Arve , Grindhaug Gaute
Published: March 2013

The only standard drillstring model in use today is the torque-drag model because of its simplicity and general availability. Field experience indicates that this model generally gives good results but sometimes performs poorly. For example, some friction loads predicted for casing running in horizontal wells have not been consistent with field data.

In the standard torque-drag model, the drillstring shape is taken as the wellbore shape. However, given that the most common method for determining the wellbore shape is the minimum curvature method, this assumed wellbore shape forces the bending moment to be discontinuous at survey points. This defect is dealt with by neglecting the bending moment.

A different approach assumes that the drillstring position corresponds with the minimum curvature wellbore only at discrete points. The obvious choice for these discrete points is at the positions of the tool joints in the drillstring. While these tool joints are fixed in position, they are allowed to rotate within the wellbore. These extra degrees of freedom allow solution of the bending moment problem, for continuity of bending moment can now be assured at each tool joint. Further, experimental studies of actual drillstrings have shown the potential to develop contact forces for lateral buckling that are significantly larger than predicted by smooth-pipe models. Thus, by the discrete-point assumption, we resolve two problems: bending moment continuity and underprediction of lock-up.

This paper gives a complete description of the drillstring calculation. Typical torque-drag problems are studied to compare the two torque-drag formulations. These studies give comparisons in drag forces and torques for the two models, and for the new formulation, the magnitude of the bending moments.
Analysis of Torsional Shock During Drilling
Authors: Collins Tony
Published: March 2013

Recent developments in drilling techniques such as Rotary Steerable tools, aggressive diamond drill bits, and dual-diameter drilling tools have greatly improved the speed of drilling wells, and have allowed efficient drilling in very difficult environments. These have created a new set of conditions that the bottom hole assembly (BHA) must withstand: a combination of high rotary speed and high, unsteady reactive torque, which have given new importance to an understanding of drillstring dynamics.

Dynamic loading of drill strings has previously been studied using application-specific models and numerical methods. This paper demonstrates the application of some simple methods borrowed from acoustics which allow approximate but very general solutions to the dynamic effects of torsional shock loading.

The results are illustrated with a case study from a well where unexpected geological features led to very high torsional shock, which caused severe equipment damage, indicating dynamic loading well beyond the accepted design parameters.

The new methodology can account for this loading as well as providing the design tools to withstand it.

The same methodology can be extended to the forces on stabilizers from transverse impacts and on bit and motor bearings from hard landings, and these are largely independent of formation properties.
Sakhalin Gas Shut-off Workovers: A Case History of Zonal Isolation at Record Depths
Authors: Molloy Richard
Published: March 2013

Exxon Neftegas Ltd., as operator for the Sakhalin-1 project, recently completed gas shut-off workovers on two extended reach, horizontal wells at the Chayvo Field, Sakhalin Island, Russia. The targeted oil producers were initially completed in open hole with predrill liners, standalone screens, inflow control devices, and swell packers across multiple zones at depths in excess of 9,000 m measured depth (MD). During production life, increased gas oil ratios (GORs) were observed, requiring the wells to periodically shut-in to manage gas-handling capacity at the Chayvo Onshore Production Facility. Production logs were used to identify the location of the high gas producing intervals, and a workover campaign was initiated in 2011. Relying on the learnings from similar successful workovers conducted on shallower MD wells in the field, a plan was developed to install straddle liners with swell packers inside the existing lower completion to effectively shut off the gas producing zones. The extension of previously proven practices to significantly greater depths introduced numerous technical challenges, including precise placement of small tubular straddles and mitigation of drag risk while conveying these tubulars through tight clearances. Additionally, these challenges had to be overcome while operating with new service companies and startup of a cold-stacked rig. Through a combination of planning, design, and flawless execution by a multi-functional team, the workovers were completed successfully, and post-workover production results showed significant reduction in well GORs. This paper will recap the results of this successful gas shut-off workover campaign, and the learnings obtained from straddle liner installations at world record depths.
Offshore West Africa Deepwater ERD: Drilling Optimization Case History
Authors: Jerez Hernando , Dias Rafael , Tilley Jim
Published: March 2013

Extended reach step-out wells provide challenging opportunities for the drilling team. A deepwater extended reach well for a major operator in West Africa required a tangent section in a soft formation maintaining an 85° drift angle for ~3,400 m (11,150 ft) in a single interval. The production section required steering the well into the best section of the pay-zone. To accomplish the drilling objectives, an exhaustive, detailed plan with multiple scenarios was required before the well was drilled.

The detailed drilling plan included the use of a tailored bottom-hole assembly (BHA) with a point-the-bit rotary steerable system and an extended gauge bit. The BHA had to overcome the natural tendency of the formation to drop inclination while creating a high quality wellbore to provide sufficient hole cleaning capacity in the deeper sections. The use of a state-of-the-art modeling tool enabled the team to balance the dynamic BHA forces while drilling to avoid common drilling problems.

The five sections required for the deepwater extended reach well were drilled with only six BHAs. The challenging 12 ¼-in. tangent interval was drilled in one run with the modeled BHA, reaching a total length of ~3,400 m (11,150 ft). This paper highlights the accuracy of the BHA modeling performance in the planning stage as this process was key to delivery of the actual results. The approach used to overcome the challenges enabled the drilling team to drill the longest 12 ¼-in section in an extended reach well in the area. This approach follows the service companies' model-measure-optimize process, which is being used to improve drilling efficiency.
Analytical Model to Characterize ‘Smear Effect’ Observed while Drilling with Casing
Authors: Kumar Aniket , Samuel Robello
Published: March 2013

The ‘Smear Effect’ observed during a casing-while-drilling operation helps reduce lost circulation, provides wellbore strengthening, and improves the fracture gradient so we can drill more effectively through depleted reservoirs. Several case studies have been reported confirming the formation of a smear zone around the wellbore wall, due to the plastering of cuttings and added lost circulation materials. However, even after successful application in a number of cases, a thorough understanding of the parameters affecting the formation of the smear zone and the subsequent increase in the fracture gradient is not available.

This study analyses the theory behind the phenomenon of the smear effect mechanism using case studies and existing literature, and then applies analytical models to estimate the improvement in the fracture gradient based on the drilling parameters and reservoir properties. The formation of the smear zone has been investigated by modelling the mechanism of initiating micro-fractures around the wellbore wall due to high ECDs occurring during casing while drilling. The effect of plugging these generated micro-fractures by drilled cuttings and lost circulation material has then been modelled to estimate the resultant improvement in fracture gradients expected along the wellbore open hole section. In addition, the appropriate particle size distribution required to successfully plug the micro-fractures has also been presented.

These analytical models have then been applied to a simulated field case study and the results have been analysed in the context of recorded field observations to simulate the smear effect using the proposed models. The contribution of the casing size and length, formation properties, and operating parameters on the initiation of micro-fractures and the increase in fracture gradient has also been presented to better demonstrate the mechanism of the formation of the smear zone. This study can be suitably applied to enhance our understanding of the smear effect and to use it better to our advantage.