bluuebunny/crossref_metadata_2025_split huggingface dataset:
Is There a Place for High Reliability Organisations in Drilling?
Authors: Thorogood J. L. 
Published: March 2012

Abstract
High reliability organisations research was originally carried out with aircraft carriers and nuclear submarines. Essentially, they were relatively closed communities, with a high operational tempo where mistakes could have extremely serious and direct consequences. In these cases, rapid learning was a by-product of personnel rotation and the need to train successors. Recent research suggests that high reliability organisations have five important characteristics: a preoccupation with failure, a reluctance to simplify, sensitivity to operations, resilience and a respect for expertise. It is not immediately obvious that these qualities are an inherent part of the culture of the organisations that manage drilling operations today. The thesis of this paper is that these five traits taken together can prevent drilling operations from drifting into failures caused by the complexity of the organisations involved in conceptualising, planning and executing drilling operations, including the management environment in which they are set.
This paper considers how apparently successful organisations can ‘drift into failure’ in part as a result of the consequences of organisational complexity. These ideas set the scene for a review of high reliability organisation theory and suggest ways in which the principles might be applied to the management of drilling operations.
Drilling Performance is a Function of Power at the Bit and Drilling Efficiency
Authors: Pessier Rolf , Wallace Steven , Oueslati Hatem 
Published: March 2012

Abstract
Today’s sophisticated data acquisition systems for both surface and downhole drilling data have greatly enhanced the understanding of the basic drilling mechanics and helped in the identification of major dysfunctions particularly harmful downhole vibrations. Various methods are now being used to optimize drilling practices by monitoring efficiency indicators such as mechanical specific energy (MSE) and preventing harmful vibrations by adjusting drilling parameters real time. However, focusing on the efficiency of components and the prevention of dysfunctions is only a partial solution. It is the magnitude of mechanical power delivered to the bit that defines the capacity of the system and directly affects efficiencies, operating practices and performance.
This paper will show how the power at the bit and drilling efficiency vary as a function of drill string and BHA configuration, bit selection and drilling parameters. Field examples will illustrate the magnitude of parasitic losses caused by well geometry and the downhole environment. In many cases it is striking how little power is left for the drill bit which in the end dictates the potential rate of penetration and thus the cost per foot and economics of the drilling process.
Particular emphasis has been put on new and intuitive ways to visually display the power at the surface and downhole. It makes it possible to quantify system limits and identify key dysfunctions in one, simple graph that can be used in both pre or post well analysis and real time. The better understanding of the entire drilling system and the functional relationship of its parts can be a strong driver for both short and long-term improvements in system design, drilling practices and bit selection which ultimately results in higher productivity and lower well construction cost.
Automated Drilling Systems for MPD—The Reality
Authors: Saeed Saad , Lovorn Randy , Knudsen Kjetil Arne 
Published: March 2012

Abstract
Managed pressure drilling (MPD) has heralded an era of accurate and precise downhole pressure control. Not only can today’s MPD systems operate in tight operational envelopes, but they, more importantly, provide dynamic real-time well control while drilling. This dynamic precision has directly enabled access to assets that were previously considered virtually “undrillable.” But, how can MPD boast such success? One of the major reasons is automation. Automation can provide levels of functional control that are difficult, if not impossible, for human operators to achieve and maintain. MPD’s inherent closed-loop setup, coupled with conventional methodology, naturally lends to automated applications.
Furthermore, despite all the advancements in MPD automation within the past few years, there is a common misconception that current MPD systems can provide fully automatic control (“cruise control”) of the entire drilling process. This is far from reality, as MPD systems today provide “supervised automation.”
Though there is a lot of material pertaining to the benefits and functionality of MPD automated drilling systems, there is very little technical information on how the systems actually function. The primary focus of this paper is to fill this disparate gap by examining the internals of such a system and, in turn, detailing how it actually works.
The paper will start by developing a generic framework, which is common to all MPD automated drilling systems (independent of the company). The components, technology, and architecture will all be presented in detail, which will be augmented by tracing the information flow through the system to clearly illustrate how the MPD process is actually carried out. Having established the technologies, capabilities, and limitations will become apparent. This will then be followed by examples of concrete implementations.
High Definition Geomagnetic Models: A New Perspective for Improved Wellbore Positioning
Authors: Maus Stefan , Nair Manoj C , Poedjono Benny , Okewunmi Shola , Fairhead Derek , Barckhausen Udo , Milligan Peter R. , Matzka Jürgen 
Published: March 2012

Abstract
Earth’s gravity and magnetic fields are used as natural reference frames in directional drilling. The azimuth of the bottomhole assembly is inferred by comparing the magnetic field measured-while-drilling (MWD) with a geomagnetic reference model.
To provide a reference of sufficient quality for accurate well placement, the US National Geophysical Data Center (NGDC), in partnership with industry, has developed high-definition geomagnetic models (HDGM), updated regularly using the latest satellite, airborne and marine measurements of the Earth’s magnetic field. Standard geomagnetic reference models represent the main magnetic field originating in the Earth’s liquid core, but the new models additionally account for crustal magnetic anomalies, which constitute a significant source of error in directional drilling. NGDC maintains a public archive of global ship and airborne magnetic field measurements. These are compiled into a global magnetic anomaly grid and expanded into ellipsoidal harmonics. The harmonic expansion coefficients are then included in the high-definition models to accurately represent the direction and strength of the local geomagnetic field. The latest global model to degree and order 720 resolves magnetic anomalies down to 28 km half-wavelength, achieving more than an order-of-magnitude improvement over previous models.
A side-by-side comparison of different on- and off-shore regions shows the high level of local detail represented in the new model. Accounting for a larger waveband of the geomagnetic spectrum significantly improves the accuracy of the reference field. This directly benefits the reliability of the well azimuth determination. We further demonstrate that model accuracy is a prerequisite for applying drill string interference corrections. Finally, an accurate reference model facilitates the validation of MWD surveys by keeping the field acceptance criteria centered on the true downhole magnetic field. Together, these factors improve well placement, prevent and mitigate the danger of collision with existing wellbores and enable real-time steering to save rig-time and reduce drilling costs.
Real-Time Drilling Fluid Monitoring and Analysis - Adding to Integrated Drilling Operations
Authors: Ronaes Egil , Fossdal Truls , Stock Tore 
Published: March 2012

Abstract
Health and safety concerns and technically challenging wells in the North Sea have created a clear and present requirement for robust systems for automated, real-time measurement of key drilling fluid parameters. This paper discusses a suite of discrete sensor packages that has been developed, successfully yard-tested, and deployed in different configurations on three critical wells in the Norwegian sector. They replace manual measurements that have been in use of over 60 years. Specific parameters addressed by this suite include density, temperature, electrical stability and water content in oil-based fluids, elemental analyses, solid content, particle-size distribution, and multi-temperature rheological properties.
Industry has long recognized the value of automated drilling fluid measurements for reducing personnel on board and isolating remaining personnel from potentially hazardous areas, mitigating non-productive time, rapidly diagnosing problems, providing necessary input to various drilling automation processes, optimizing fluid performance, and sharing real-time data with remote operating centers. Successful implementation had been plagued by the lack of suitable sensors and efficient means to transfer and interpret the data. Business issues also had been of concern, but fortunately most of these are steadily being defused.
This paper describes each of the sensor packages, including the design, method of operation, accuracy, reliability, interpretation, and means of data transmission. Two sensors in the suite that have been previously available are included for completeness. The authors present sample yard and/or field data, demonstrating typical results as well as suggesting how these results could be leveraged for maximum benefit.
Innovative Fiber Solution for Wellbore Strengthening
Authors: Friedheim James E. , Sanders Mark W. , Arias-Prada Jorge , Shursen Ryan P. 
Published: March 2012

Abstract
A new high-fluid-loss, high-strength (HFHS) lost circulation solution has been designed and validated using innovative test methods. This new HFHS pill system has been recently proven in the field to work for a wide range of loss rates and provides a more effective and permanent seal than traditional treatments.
While lost circulation is one of the drilling industry’s most significant problems, the solutions are numerous and varied. Direct and associated costs of lost circulation approach $3 billion globally, including whole mud loss, treatment of cost, and rig time.
Specially designed pills are some of the more popular approaches to curing severe lost circulation. These pills are mixed, pumped and spotted across the loss zone with the intention to stop or reduce the losses sufficiently enough to resume circulation of the wellbore fluid and regain control of the well. However, many severe lost circulation solutions that are used today incur additional risks that should be avoided. These may include having to use specialized pumping equipment, bypass tools, or even the removal of the BHA. The HFHS pill was developed to not only meet the need for an effective lost circulation solution, but also not present further operational risk during its placement.
In this paper, the path to designing and testing the HFHS pill is described, including an evaluation of the effectiveness of a number of commercially available high-fluid-loss pill treatments and the methodology used to meet a set of "ideal" field criteria. The roles played by various teams in support of this effort will be highlighted, as well as results from recent field trials which prove the advantages of this technology.
Distributed Dynamics Feasibility Study
Authors: D'Ambrosio Piero , Bouska Reisha R. , Clarke Alan , Laird Jason , McKay Jim , Edwards Stephen T. 
Published: March 2012

Abstract
The advent of wired drill pipe has the ability to allow a variety of measurements to be distributed throughout the whole drilling assembly. One such measurement is acceleration to better determine the impact of how vibration events are distributed through from the bottom hole assembly to the upper drillstring or vice versa. In turn we can now investigate the potential use of distributed dynamics by utilizing a set of designed for purpose independent Downhole Dynamic Data Recorders (DDDR), for real-time decision making. A test project was executed to acquire vibration data along the drill string on a horizontal well in Oklahoma’s Woodford Shale. This project allowed the evaluation of data acquired from the bit and the bottom hole assembly (BHA), in the horizontal section, as well as the sensors located in the upper assembly showing the dynamics throughout the vertical section, curve, and landing point of the horizontal.
This paper focuses on the analysis of the measurements gathered during the project and it will provide detailed descriptions of the obtained results. Several concepts as well as common known misconceptions related to drilling dynamics will be discussed, among them the decoupling effect of the mud motor to drilling vibrations, the value of downhole torque, weight and bending moment for the understanding of distributed dynamics along the drill string. The importance of the vibration sensors’ placement and data recording frequency in order to diagnose and mitigate drilling dysfunctions will also be discussed.
Potassium Silicate-Treated Water-based Fluid: An Effective Barrier to Instability in the Fayetteville Shale
Authors: Fritz Brady , Jarrett Michael 
Published: March 2012

Abstract
Both oil- and water-based fluids have been used to drill in the Fayetteville shale play with mixed results. Oil-based muds (OBM) provide reliable inhibition and drilling performance, but environmental and economic concerns have generated interest in water-based alternatives.
However, drilling with traditional water-based muds (WBM) such as lignite/lignosulfonate, gel/polymer, potassium chloride (KCl)/polymer, polyanionic cellulose (PAC)/starch, and partially hydrolyzed polyacrylamide/polyacrylate (PHPA) brought only marginal success. Conventional silicate WBM is known for preventing both clay hydration and dispersion, but requires high concentrations of potassium silicate and high dilution rates. It can also exhibit poor lubricity and temperature stability.
Developing the optimal WBM for Fayetteville applications requires a clear understanding of how that shale is destabilized. Insufficient physico/chemical inhibition can lead to unwanted water absorption, which can cause stress fracturing and delamination. These conditions provided the right opportunity to test and optimize the sealing and inhibitive properties of a new potassium silicate-treated fluid containing much lower concentrations of potassium silicate.
The unique inhibition mechanism is the surface adsorption and chemical reaction of the silicate salt with the formation surface, which provides a thin pressure and chemical barrier on the wellbore face. Extensive lab and field data demonstrate that the new WBM helps prevent hole washout, tripping difficulties, low gravity solids build-up and the excessive torque and drag typically encountered in Fayetteville drilling operations. The new system is now a widely used alternative to OBM, with a 70+ well track record at the time of this writing.
This paper describes the technical process used to design, formulate, and apply the customized potassium silicate-treated WBM for use in the stressed Fayetteville shale play. Mineralogical analysis, microscopy studies and continuous improvement based on field observations are discussed in detail.
Automated Managed Pressure Drilling Allows Identification of New Reserves in a HPHT Exploration Well in SB Field, Offshore Malaysia
Authors: Ismail Zulkarnain , Aziz Intan Azian , Umar Lawrence , Nordin Noor Azree , Nesan Thanavathy Patma , Rodriguez Freddy Rojas , Zapata Fernando Gallo , Garcia Greg , Waguih Ahmed , Subroto Bramanta , Dow Blaine 
Published: March 2012

Abstract
The SB Field is located in Block PM on the west side of the Malay Basin, Malaysia. It is notorious for its steeply rising pressure ramp, narrow drilling operation window and inter-bedded sand, coal, and shale formations.
Block PM is still at the exploration and appraisal stage with limited petrophysical information. Well SBD-2 was the second attempt to reach and cross the F & H sands of this basin. Despite using managed pressure drilling, the first attempt failed when an influx exceeded the fracture gradient, resulting in total fluid losses.
Due to the shallow pressure ramp and narrow window between pore pressure and fracture gradient, a repeat attempt was initially deemed "un-drillable". However, the design team felt the target could be reached using an automated managed pressure drilling technology. The team was able to maintain constant bottom hole pressure over three demanding hole sections and reach target total depth.
The 8-1/2" × 14-3/4" section required minimum overbalance to manage "wellbore breathing" and to control potential losses to weaker horizons. In the 10-1/2" × 12-1/4" section, the system was used to identify and react quickly to kicks in high pressure sands and also to eliminate wellbore breathing/ballooning. In the final 8-1/2" × 9-1/2" section, the objective was to maintain overbalance in the narrow pressure window between pore pressure and fracture gradient.
This paper will describe the design efforts employed while preparing to drill the SBD-2 well. The challenges and lessons learned, particularly managing pore pressure prediction with multiple techniques will be discussed. Lessons learned and recommended workflows for similar projects will also be outlined.
Roller Reamer Fulcrum in Point-The-Bit Rotary Steerable System Reduces Stick-Slip and Backward Whirl
Authors: Stroud Daryl , Bird Neil , Norton Peter , Kennedy Mathew , Greener Malcolm 
Published: March 2012

Abstract
An increasing proportion of wells are drilled using RSS, whose BHA dynamic behaviour is very different to that of steerable mud motors. This return to rotary drilling has renewed industry interest in detrimental dynamic phenomena such as backward whirl (Stroud et al, 2011). Preventing these undesirable dynamics is crucial to drilling efficiency and it is widely recognised that the nature of BHA/borehole contact points plays a key role in preventing backward whirl. Side-loads applied to stabilizers by the RSS for the means of controlling the trajectory of the wellbore can increase traction with the well bore. Although these borehole contact points are designed to be low friction; even a well engineered sliding contact surface can never be as effective as a rolling bearing element in preventing traction.
The use of roller reamers in BHAs to prevent stick-slip being generated at contact points under high side-load is well known. In addition, Sowers et al (2009) pointed out how backward whirl creates high side-forces at borehole contact points leading to stick-slip and proved that replacing stabilizers with roller reamers can be an effective method of decoupling BHA whirl and stabilizer torque. They also speculated that roller reamers are more effective at smoothing out borehole features created by whirl. In addition, roller reamers are field proven technology and could potentially gain rapid widespread acceptance.
This investigation focuses on how roller reamer technology can be adapted for use as a key component in a rotary steering assembly to prevent borehole traction WITHOUT causing side-cutting and hole enlargement, and without adversely affecting system steerability. It describes how a custom design roller reamer can be used to replace a stabilizer as the fulcrum for a point-the-bit rotary steerable system (RSS).
Results of laboratory and field test programs are presented, showing a dramatic reduction in dysfunctional drilling conditions caused by traction between the fulcrum stabilizer and borehole. Full scale laboratory testing explores the impact of custom design and strategically placed rolling contact elements in a point-the-bit RSS. Results confirm that rolling contact elements are effective at preventing backward whirl at borehole contact points.
Properties of Filter Cake of Water-Based Drilling Fluid under Dynamic Conditions Using Computer Tomography
Authors: Elkatatny S. M. , Nasr-El-Din H. A. 
Published: March 2012

Abstract
Heterogeneity of the filter cake plays a key role in the design of chemical treatments needed to remove the filter cake. Filtrate invasion into the formation can substantially reduce the permeability of the near wellbore region and in turn, damage the formation. In addition, the nature and the thickness of the filter cake will increase the potential of differential pipe sticking.
Extensive lab studies were conducted to measure the filter cake thickness and porosity of 69 pcf water-based drilling fluid using a CT (computed tomography) scanner and develop a relationship between the porosity and the permeability of the filter cake. An HPHT filter press was used to perform the filtration process under dynamic conditions at 250 °F and 300 psi differential pressure using 10-micron ceramic disks. Experiments were done at 1, 5, 10, 15, 20, 25, and 30 min. After each experiment, the filter cake was scanned using CT.
The results obtained from the CT scan showed that the filter cake contained two layers with different properties. No compression period was observed during the filtration operation. The ratio of the layer closer to drilling fluid thickness was 70% of the filter cake, which will affect the amount of enzymes and acid, which are used to remove the filter cake. The layer closer to rock surface had a near constant thickness (0.04 in.), a decrease in porosity from 30 to 10% during the buildup of the filter cake, and an average permeability of 2.4 µd which was obtained from different correlations (Elkatatny et al. 2011a). The porosity of the layer closer to drilling fluid decreased from 0.25 to 0.0 %, due to poor sorting, which resulted in zero permeability. Using CT for the first time allowed us to evaluate existing models to predict porosity-permeability relationships of the filter cake.