bluuebunny/crossref_metadata_2025 huggingface dataset:
Friction Factors: What are They for Torque, Drag, Vibration, Bottom Hole Assembly and Transient Surge/Swab Analyses?
Authors: Samuel Robello
Published: February 2010

The term "friction factor," conventionally defined for fluid flow engineering calculations, is also used for solid mechanics calculations in the drilling industry. At first glance, it may seem to be a misnomer, but there are underlying facts and reasons for the adoption of the term "mechanical friction factor" that is unique to the industry. This term is used as a proxy for the coefficient of friction (COF) or the Coulomb friction, a dimensionless scalar value, in the estimation of torque, drag, side forces for the directional tendancies prediction, static displacement of string for vibration analysis, and moving pipe elastic force for transient swab/surge pressure estimation. Because of larger uncertainties in the modeling of a long drillstring, including cuttings bed, tortuosity, mud properties, fluid viscous effects, wellbore temperature, pressure, and non-uniform geometrical interferences between the drillstring and wellbore, the COF is termed as a friction factor by including the uncertainties involved without defying the mechanics involved. Another important parameter used during the planning stage in combination with the friction factors is the tortuosity factor to provide artificial undulation to the wellbore. The tortuosity factor causes an additional problem, which requires a different friction factor for the analysis, even though the COF between the drillstring and the wellbore has not changed. Because there is no industry standard for quantifying these parameters, a great deal of confusion exists between these parameters and results in the overestimation or underestimation of the frictional drag. This paper describes the details, clear definition, calibration, pitfalls, and context in which they can be used. It presents the simple guidelines and several example calculations. This paper also provides methods for evaluating these parameters with real-time data.
A Gulf of Mexico Case History: Benefits of Foamed Cementing to Combat a SWF
Authors: Fuller George A. , Bolado David , Hardy Fred , Spath John
Published: February 2010

Cementing a deepwater riserless casing string in areas where shallow water flows (SWF) are encountered can be difficult and very costly if not successful on the first attempt. One of the practices commonly used by much of the industry for these jobs is foamed cementing. Foamed cementing has provided many benefits over specialized lightweight blends such as comparable heat of hydration properties, fluid compressibility for maximum hydrostatic transmission, improved elastic properties, and rapid density changes possible due to unforeseen well conditions.

Because of the surface features on the seafloor and the location of geological objectives, wells are routinely drilled in areas of potential SWF. These hazards are typically categorized as high flow potential, moderate flow potential, or minimal flow potential. Although the potential risk of encountering SWF hazards can be identified, the actual pressure of these hazards are not known until they are drilled. Preplanning is crucial to combat these flows before they are encountered.

This paper will discuss the planning that took place to prepare for cementing if SWF was encountered. These include: how preplanning was prepared for the event that the well began to flow, how weaker zones above the hazard were managed with lighter density foamed, how the density of foamed cement throughout the hole was planned without knowing the hole size, and how foamed cement helped with displacement in a very large annulus.
Sonic While Drilling: Multipole Acoustic Tools for Multiple Answers
Authors: Degrange Jean-Marie , Hawthorn Andy , Nakajima Hiroshi , Fujihara Takeo , Mochida Manabu
Published: February 2010

Acquiring good downhole sonic-while-drilling measurements is challenging and complex. However, because of the multiple applications of acoustic data it has been a major goal of the industry to develop tools that achieve this objective.

Applications for sonic-while-drilling data cover a wide spectrum, including real-time determination of pore pressure and overburden gradients, seismic calibration, complex lithology identification, gas detection, fracture evaluation, and estimation of mechanical properties. These are used by a broad spectrum of disciplines including drillers, geophysicists, geologists, petrophysicists, and reservoir and completion engineers.

Recent developments in multipole sonic measurements provide robust compressional and shear data irrespective of mud speed, as well as Stoneley information, that can be used for advanced sonic applications.

A novel hardware design, coupled with a reassessment of data handling and processing in parallel with extensive modeling now allows advanced answers to be acquired and delivered while drilling.

There are numerous examples in the literature that demonstrate the importance of multipole acoustic data for real-time pore pressure, wellbore stability and seismic correlation. This paper will look at some other applications of great benefit to the drilling and completion community, including top-of-cement identification, rock mechanics, gas detection and other sonic uses that can potentially be an aid in the overall goal of drilling optimization. Data will be shown from deviated, highly deviated and horizontal wells and other challenging logging environments.
Mono Diameter Expandable Drilling Liner Applications in Deepwater Drilling
Authors: Kumar Nitesh , Marker Roy , Corneliussen Rune , Kirkemo Erik G , Rønneberg Erik
Published: February 2010

Claims can be found in technical literature for using Mono Diameter Expandable Liners in deepwater applications. In a technical review of the existing Mono Diameter Expandable Liner systems by various vendors, it is concluded that Mono Diameter Expandable Liner can be considered for using as a drilling liner if certain prerequisites as discussed in this paper are met. Further, the product can be used in a brown field development scenario, where no pore pressure surprises are expected. In any case, once drilling to target has been achieved, the product must be covered by a conventional casing. Proper risk evaluation before running in the hole is recommended, given the high per day costs associated with the deepwater wells. On the other hand, if the product has to be used for deepwater pre planning and casing design purposes, substantial increase in strength (collapse & burst of the pipe) will be required, without which the product will not qualify industry standard casing design criteria’s at the basis of design level. From design perspective, one time or multiple mono diameter expandable liner extension are the same and the key issue to address in using this product is meeting the collapse pressure requirements.
Improved Accuracy of Borehole Positioning in Horizontal Wells
Authors: Lawrence Brett , Mojsin Tanja , Strachan Michael
Published: February 2010

Accurate measurement of the true vertical depth (TVD) and reduction in the error uncertainty of the TVD measurement has become an increasingly important element in field development and well placement. A field on the North West Shelf of Australia required precise positioning of the wellbore within the reservoir. The trajectory within the horizontal production section depended completely on accurate geometric measurements to achieve the goal of keeping the well within +/-1 m of the target TVD for the entire length of the horizontal section – typically 1600m to 2300m. With great attention to detail, this is possible; however, the uncertainties associated with determining the actual wellbore inclination would normally overwhelm the required accuracy.

The main sources of error while drilling horizontally result from misalignment (SAG) of the bottomhole assembly (BHA) within the wellbore, sensor axial misalignment, and axial accelerometer bias. To combat these sources of error, a multiple sensor system was designed with improved accelerometer bias (attained by using extreme calibration techniques). Compounded software programs for advanced BHA analysis and multistation analysis of the survey data were used. The data from the primary sensor determined the directional parameters used while drilling. The second directional sensor was positioned in the BHA to confirm the accuracy of the SAG correction applied to the primary sensor and to confirm any bias. Proprietary software was used in real time and post-drilling to perform multistation analyses of the accelerometer and magnetometer data from both sensors.

This paper describes the methods used to reduce the TVD uncertainty while drilling long horizontal sections. Improvements were made to standard Industry Steering Committee for Wellbore Surveying Accuracy (ISCWSA) MWD+SAG error model to simulate the increased level of accuracy generated as a result of the multiple sensor system. Using data from the two directional sensors and a continuous at-bit accelerometer assembly, the ellipse of uncertainty was estimated throughout the section and remained with a +/-1.5 m (1 sigma) limit. TVD uncertainty was set to zero at the gas/oil contact (GOC); it was not necessary to model the total error from surface.
Successful Application of RSS in a Highly Nitrified Mud System
Authors: Chase Clint , Zafar Syed Hammad
Published: February 2010

The presence of high nitrogen injection rates through the drillstring represents a challenge for modeling hydraulics inside the BHA, in particular rotary steerable systems (RSS). An algorithm was developed to simulate the downhole pressure across the desired bottom hole assembly (BHA) components for nitrified drilling fluids. This paper captures the main features of the model and its validation process.
First Year Performance Review for 6th-Generation Drillship
Authors: Davis Mike , Banks John , Rainnie Barry
Published: February 2010

The challenges of bringing an enhanced deepwater drilling vessel design to market and then into operations successfully in a high-activity market are immense. Using a project based approach with close co-operation between the rig owners, shipyard, customer, 3rd party equipment suppliers, classification society, a 6th generation drillship was successfully engineered, built, commissioned and delivered on time. The drilling contractor teamed up with their client and effectively completed it’s first two deepwater sub salt wells ahead of target time, and more importantly without causing harm to personnel or the environment.

The drillship was delivered to the operator on January 1, 2008 in Korea commencing a 4 year contract.

The paper will be a case study of the drillship’s excellent HSE and operational performance on her first two ultra deep water sub salt wells in Brazil and GOM. The paper details the progress of the project through the shipyard, acceptance programs and tracks both operational and HSE performance though it’s first year of operations.

Addressed in the paper are the factors that contributed to the success of this project i.e. conceptual, construction and timely delivery, along with a top quartile drilling performance. The project based approach to operations and planning that led to exceptionally low rig non-productive time on start-up and excellent HSE performance throughout the first year of operations.

The following issues are dealt with in the discussion: The operators rig selection process and criteriaBackground to selection, design and project execution for the construction of the drillshipProject management and acceptance testing including general approach to QA/QCWell planning strategy, personnel requirements and long lead time issuesMobilization and performance on the Deepwater project in GOMReview of well planning and execution strategy to maximize efficiency and HSE benefit to project stakeholders during delivery and first year of operation
Evaluation of Precision Drilling Super Single Performance
Authors: Griffin Harold Gordon
Published: February 2010

Drilling Rigs that lead the industry in performance and safety is what drilling owner/operators strive to have because these rigs will work in many different markets. The Precision Drilling Super Single Rig will be evaluated as a case study using data from wells drilled on performance and safety. As of November 2009 Precision Drilling has 53 Super Single Rigs in 5 different models (38 Slant, 6 Light,

5 Electric, 3 Stretch, and 1 Mobile) and has drilled over 16,750 wells.

Precision Drilling keeps detailed history records of its own rigs. The Super Single Rig data will be compared to industry. Individual well cases will be examined where it is known that a conventional rig and Super Single completed similar wells in a similar location.
Effect of Bicenter Bit-BHA Design on BHA Behavior
Authors: Taylor Jennifer , Bouska Reisha R. , McKenty Mike , Silva Roger , Prochaska Ernest
Published: February 2010

The petroleum industry is continually pushing to safely drill deeper, longer, and faster sections. The use of bicenter drill bits has been a popular option since the mid 1990s for borehole enlargement while drilling. Borehole enlargement offers significant benefits allowing multi-diameter casing strings, additional contingent hole sections and reduced equivalent circulating density with a narrow mud-weight situations, allowing longer well profiles and larger hole diameters to reach deeper reservoir sections.

Bicenter bits are unique because of their eccentric design and the rules of use below a smaller diameter drift. Those with a pilot bit and reamer combination are different than a conventional full-hole concentric bit. Generally, the bicenter bits are longer and have cutting force challenges not shared by concentric full-hole bits. The ability of a bicenter bit to drill a larger hole below a smaller drift diameter requires slightly different BHA configurations to maintain consistent directional control. There are currently no published reference tables or programs to accurately predict the directional behavior of bicenter-bit bottom-hole assemblies (BHAs).

This paper presents a study of bicenter bit and BHA runs in the Gulf of Mexico (GOM) that evaluates and analyzes operating parameters, stabilizer placement and BHA type [positive displacement motor and point-the-bit rotary steerable system (RSS)]. Also included are documented results, techniques, and references for establishing guidelines for successful use of bicenter-bit BHAs in directional drilling applications.
Wellbore Positions Obtained While Drilling by the Most Advanced Magnetic Surveying Methods May Be Less Accurate than Predicted
Authors: Ekseth Roger , Weston John
Published: February 2010

Various methods, often referred to as in-field referencing (IFR) techniques, are used to enhance the performance of traditional magnetic measurement while drilling (MWD) well-bore surveys. Simulation and field data studies of effects commonly not accounted for, like the fact that the geomagnetic field varies with depth, indicates an unrealistically high level of confidence in the IFR techniques, especially when run in conjunction with multi station corrections (MSC). The SPE wellbore position technical section (WPTS) is currently recommending the use of the standard MWD error model weighting functions, which do not reflect a horizontal east-west singularity associated with combined IFR-MSC surveys. The WPTS is further recommending the use of geographically dependent IFR azimuth uncertainty figures, which average globally to 0.22º (1σ). The WPTS average is supposed to account for all errors that corrupt an IFR survey, not only those affected by the IFR correction itself which, according to WPTS, have an average of only 0.18º (1σ). The WPTS figures do not account for the additional uncertainty generated by geomagnetic depth variation. Simulations show a global uncertainty of 0.38º (1σ) from this error source alone. Geomagnetic depth corrections are possible, but not commonly applied, and are far from error free; residual errors after correction exceeding 30% appear to be common. The study described here indicates an underestimation of the real wellbore position (IFR based) uncertainty of 50% or more, a fact that represents a potential safety hazard to both human life and equipment of which the industry needs to be made aware.
Managing Circulation Losses in a Harsh Drilling Environment: Conventional Solution vs. CHCD Through a Risk Assessment
Authors: Masi S. , Molaschi C. , Zausa F. , Michelez J.
Published: February 2010

Conventional drilling techniques used in harsh drilling environments are sometimes impractical or uneconomical. This was experienced while drilling through the reservoir section being investigated. This section is characterized by high pressure and formation fluids estimated to contain 18-20% of H2S and 4-6% of CO2. The presence of extensive karst/fractures along with severe circulation losses prevents successful drilling using the conventional circulation technique. For this scenario, the Pressurized Mud Cap Closed Hole Circulation Drilling (CHCD) technique was applied, and proved to be the most effective method to drill through the Lower Carboniferous Carbonate.

In conventional drilling through such loss circulation zones, the typical method is to isolate the thief formation (LCM's pills, gunks and cement plugs) in order to maintain an overbalanced condition. These methods have their disadvantages: uncertain results, time and cost increase, damages on well productivity. Furthermore, it may be a long, ineffective process due to multiple leak-off zones or massively fractured zones.

Where unsustainable losses occur and conventional circulation is no longer possible, the "CHCD" technique may be used to allow the continuation of drilling. This technique is not under balanced drilling. The annulus is closed and no returns are circulated to the surface.

The CHCD is not a simple or an inexpensive system. It is used only when other systems for controlling losses have proven to be ineffective. Large quantities of water and mud are required as well as additional equipment and specialized personnel. An accurate evaluation of several factors has to be performed. Drilling hazard is the major issue as the primary barrier to well influx is jeopardised, but also rig time, material availability and consumption have to be considered.

The aforementioned uncertainties can be addressed through risk evaluations by comparing two drilling scenarios of a typical development well where one uses CHCD technology and the other uses conventional drilling techniques.

This paper will discuss the operational details of conducting CHCD as well as the risk management approach which involves the identification, evaluation and mapping of all risks involved in each scenario (qualitative risk assessment). A probabilistic model is therefore developed in order to combine all the risks identified and to address their consequences within operational time (quantitative assessment).
The Automated Drilling Pilot on Statfjord C
Authors: Larsen H. F. , Alfsen T. E. , Kvalsund R. , Iversen F. P. , Welmer M. , Hult Ø. , Ekrene S.
Published: February 2010

In the Automated Drilling Pilot three newly developed technologies aiming to improve the quality of the drilling operation, have been submitted to an extensive offshore field test in the North Sea. The technologies involved were: (1) Software for drilling control automation based on real time process modeling, (2) system for drillpipe tracking based on RFID technology and (3) sensors for continuous measurements of drilling fluid parameters. During this field test the listed technologies were not only tested simultaneously, but also set up to exchange data in real time, forming one integrated drilling automation system.

In this paper the relevant functionalities of the technologies tested in the pilot are described. The paper also outlines the preparations for the pilot, including work performed on risk mitigation, onshore testing and training of personnel. In addition, the actual field performance of the technologies have been measured and evaluated regarding their influence on a number of important operational areas such as HSE, operational efficiency, work tasks/responsibilities and demands on surrounding technology. Lastly the capability of these technologies for exchanging data in real-time to form a closely integrated automation system has been demonstrated and evaluated.

Based on the experiences from the Automated Drilling Pilot, several crucial technology enablers have been identified for the technologies involved, the most important being related to personnel training/experience building, drilling data quality/availability and offshore expert support.
Elimination of Errors in Cement Displacement Volumes and Plug Bump-Plug Indicator System
Authors: Gradishar John , Groesbeck Brad Michael
Published: February 2010

This paper describes the development and deployment of a new method of determining the physical location of a top cementing plug in a subsea casing string. Typically, the position of the top plug is approximated based on the calculated volume of the string, which can often vary significantly from actual casing volume, especially in long, heavy subsea casing intervals.

Such discrepancies can create major problems during primary cementing operations, including failure to bump the top plug or potential overdisplacement of cement. The former tends to increase subsequent drillout times; the latter may result in contaminated cement in the shoe track.

After review of the problems, the operator in the region concluded that utilizing the described technology, the Plug Indicator System (PIS), was warranted. The PIS was expected to facilitate more effective primary cementing operations by mitigating these risks, thereby reducing nonproductive time (NPT) and associated costs and avoiding expensive remedial operations.

This paper reviews and helps familiarize the reader with the problems associated with subsea casing primary cementing operations. A case history of the PIS and its successful conclusion is presented.
Behavior and Shape of Gas Kicks in Well Bores
Authors: Spoerker H. F. , Tuschl T.
Published: February 2010

Conventional assumptions of how a gas kick develops in the wellbore mostly refer to one "dry gas bubble" over a wellbore length equivalent to the total influx volume and – while fulfilling all requirements for volumetric/hydraulic well control calculations – are clearly unrealistic. However, modeling the system of gas entering the annulus out of a porous medium and with drilling mud moving in most cases under turbulent flow conditions is highly complex and computer-power intensive.

The paper describes the driving mechanisms of gas entering into the wellbore, the methodology used for simulating and visualizing the percolation of gas after the well has been shut in and the influence that gas distribution/movement has on the chemical buffering of sour gas influxes in high-pH drilling fluids. It is part of a multi-year research project aimed at understanding the well bore / gas influx system in more detail and allowing a better definition of the behaviour of high-strength steel drill pipe in potentially sour environments. As the buffer reaction between the sour gas influx and the (generally) caustic drilling mud is heavily influenced by the initial distribution of the gas into the mud, the generation of bubbles (i.e. active surfaces) and the kinetic energy transferred to the system during the mixing process, the results of this study form the basis for subsequent high-definition simulators.
Well Integrity Monitoring & Analysis Using Distributed Acoustic Fiber Optic Sensors
Authors: Hull John , Gosselin Lance , Borzel Kevin
Published: February 2010

Evaluating well integrity (i.e. flow of fluids or gas) from behind casing can be challenging using existing single mode analog sensors; they offer limited representation and data acquisition can be time consuming. Further, traditional processing algorithms such as Fourier Transforms are not responsive to non-stationary, nonlinear events such as random, low volume leak signatures. Recent advancements in both fiber optic Distributed Acoustic Sensors (DAS), and processing algorithms stand to significantly simplify downhole low rate leak detection. This paper will explain the capabilities and limitations of this monitoring approach.

Distributed Acoustic Sensors; Proven in demanding applications such as submarine sonar systems, optical fiber can be packaged in such a way that makes it extremely sensitive to acoustic disturbances along its entire length. Using the fiber itself as a sensor has several advantages, some of which include; extreme sensitivity, design simplicity, and the ability to obtain 1000’s of simultaneous measurements with little or no loss of fidelity. Datasets were obtained from both a specifically designed 200 ft vertical controlled test well simulator and actual problematic gas wells in Canada.

Processing Algorithms: Using DSP techniques and real time methods, the engineer can tune the system to a specific leak signature which eliminates unwanted events and highlight useful acoustic components pertaining specifically to the leak. Once the data is obtained the high fidelity acoustic data undergoes various filtering and error detection processing. Algorithms were tested in Matlab and converted to executable code once verified.

The integrated well monitoring and analysis system offers a more comprehensive, detailed solution. When compared to traditional technologies, future remedial strategies were often strategically more accurate using the fiber based systems, especially when low leak rates were involved. It is anticipated that engineers will be able to locate problematic leaks with higher confidence and save money by reducing the number of failed interventions; similarly, the need for experienced highly trained log analysts will be reduced. Applications for this information may include: low rate leak detection through casing, pipe integrity failures, zonal isolation issues, long term well monitoring, carbon storage and sequestration, evaluating intervention effectiveness, and locating multiple source leaks along a wellbore.
Liner Drilling Technology as a Mitigation to Hole Instability and Loss Intervals: A Case Study in the Gulf of Mexico
Authors: Rosenberg S. , Gala Deepak M. , Xu Wei
Published: February 2010

The combination of liner drilling with a casing while drilling (CWD) bit to successfully drill and cement a 7-in. liner in place through a severe loss zone in the Gulf of Mexico, offshore Texas, USA, will be presented in this paper. Previous attempts to drill this problem formation were unable to reach the objective depth because of lost-circulation and hole stability issues. This paper will present equipment selection, operation, and results of liner drilling that allowed this well to be successfully drilled and cased.
Vertical Riser Handling with a Knuckle Boom Crane
Authors: Hagen Sondre , Talberg Kaare Tommy , Kristiansen Narve
Published: February 2010

This paper presents a new solution in terms of how to handle drilling riser vertically on a floating drilling rig by means of the well known offshore crane type, the Knuckle Boom Crane and vertical column storage. The main reason for introducing this new solution is the resulting increased free deck capacity and the overall increase in VDL capacity on a floating drilling rig.

The solution has recently been implemented as part of a deepwater upgrade on an old semi-submersible drilling rig from the mid 70’s and has been in operation for nearly 1 year.

The paper focus on the Human Machine Interface specifically developed to enable a smooth handling process, in addition to the resulting general operational and construction project related benefits from implementing the solution.

The solution has proven its benefits throughout the design and construction phase in terms of limited interference with existing deck structure, in addition to operation in terms of an available free deck space comparable with the significantly bigger new generation deepwater semi-submersibles.
Real-Time Well Tool Face Information Reduces Directional Uncertainty and Risks in Difficult Sidetracks in Gulf of Suez
Authors: Howes Thomas B. , Farouk Mohamed , Darwish Mohamed , Koroletz Wilhelm , Ismail Ahmed , Moustafa Amin , Heisig Gerald
Published: February 2010

To address risk and uncertainties in difficult sidetrack operations in the Gulf of Suez in Egypt, a new method was implemented to identify and control the direction of the wellbore during the whipstock exit, and close to the liner, where standard directional measurements are compromised due to magnetic interference. Bending moment sensors were placed directly above the motor and only 26 ft behind the bit. These sensors delivered two perpendicular bending moment measurements referenced to gravity high side. Transmitted to surface via mud pulse telemetry, the two signals were further processed to deliver the well tool face and - with the help of a mathematical BHA model - the dogleg severity of the well.

In one case the well tool face confirmed the orientation of the whipstock and the window milled. However, in a second case, the measurement revealed a 40 degree deviation from the original whipstock orientation. The well plan was immediately adjusted to compensate for this deviation from plan. The dogleg severity information gave improved azimuth control when steering away from the existing well in sliding mode. As a result, both sidetracks achieved their directional objectives and could be steered into the target. The directional estimates derived from the bending moment measurements were later confirmed by the first valid MWD surveys and by gyroscopic survey measurements.

The paper will start with a detailed description of the directional challenges in this application. It will then introduce the concept of the bending moment measurements and the derived directional information, well tool face and dogleg severity. After a description of the implementation and directional execution of the sidetracks, the paper will conclude with a discussion of the benefits and the potential of this new directional control method, which could result in a reduction or even complete elimination of gyro runs during similar casing exits and significant rig time savings.
Drilling a Challenging HPHT Well Utilizing an Advanced ECD Management System with Decision Support and Real Time Simulations
Authors: Rommetveit Rolv , Ødegård Sven Inge , Nordstrand Christine , Bjørkevoll Knut S. , Cerasi Pierre , Helset Hans Martin , Fjeldheim Mikkel , Håvardstein Stein T.
Published: February 2010

A very challenging HPHT well has been drilled utilizing an advanced ECD Management System including real time simulations, early diagnosis of upcoming problems, and real time simulations using state-of-the art models. The System uses all available real time drilling data (surface and downhole) in combination with real time modeling to monitor and optimize the drilling process. This information is used to visualize the wellbore in 3D in real time. It has been implemented in Total E&P Norge TASC (Total Activities Support and Collaboration) Center in Norway. The system is composed of the following elements, some of which are unique and ground-breaking:

An advanced and fast Integrated Drilling Simulator which is capable of modeling the different drilling sub-processes dynamically, with interaction between these sub-processes in real time. Automatic quality check and corrections of drilling data; making it suitable for processing by computer models Real time supervision methodology for the drilling process using time based drilling data as well as drilling models / the integrated drilling simulator. Methodology for diagnosis of the drilling state and conditions. This is obtained from comparing model predictions with measured data. Advisory technology for more optimal drilling. A Virtual Wellbore, with advanced 2D and 3D visualization of the downhole process. Data flow and computer infrastructure.

Among the challenges during planning and drilling of this well have been:

Very small window between pore and fracture pressure. RT ECD simulations were performed with an advanced hydraulic and thermal wellbore model. Increased probability for instabilities in the tight window. Was mitigated by RT stability modeling during drilling. Pore pressure predictions which were updated during drilling.

Experiences from the drilling as well as use of the ECD Management System will be summarized and presented. The usefulness of supervision and diagnosis functionalities is illustrated.
Wellbore Stability in Fractured Rock
Authors: Ottesen Steinar
Published: February 2010

Numerous wellbore instability problems related to drilling through potentially fractured formations have been reported. Often, these rocks are characterized by the abundance of macro and micro scale bedding planes and/or networks of natural fractures. The presence of fractures weakens the rock mechanically and produces potentially higher-permeability fluid-flow paths within the low-permeability rock matrix. Practically, it is difficult to identify fracture size and fracture density without a costly core sample. A number of wellbore stability case studies have therefore been published where the author relied on anecdotal evidence to postulate failure mechanisms involving fractured rock, and recommendations for how to mitigate the observed instability range from increasing to decreasing the wellbore pressure.

This paper presents results from a geomechanical investigation of a wellbore instability incident experienced in a fractured shale formation. As part of this assessment, a preserved core was obtained from the fractured shale interval and the presence of fractures was identified both by CAT scan and visual inspection. A series of triaxial tests were conducted to characterize the mechanical properties and failure strength of this shale. This data, combined with wellbore stability modeling, suggests that the residual strength, rather than the peak failure strength, is a more representative measure of a fractured rock's in-situ strength. The Hoek and Brown (1982) failure criterion was found to be particularly suitable for modeling fractured rock.

Multi-arm caliper logs from two boreholes through the same fractured shale suggests that wellbore instability is more complex in the fractured interval than in the over- and underlying intact rock. These caliper logs also clearly demonstrate that the borehole quality was significantly improved by increasing the drilling fluid density, which contradicts the conclusions drawn in a number of published wellbore stability case studies (Santarelli et al., 1992; McClellan et al., 1996; Edwards et al., 2004; Fontana et al., 2007).
Controlled Pressure Drilling (CPD) Candidate Screening Methodology, an Update
Authors: Villatoro Jaime , Boutalbi Said , Schmigel Kevin , van Galen Martijn , Lakshminarayanan Sunil
Published: February 2010

Controlled pressure drilling (CPD) is an emerging, multi-component drilling application that can improve drilling time and reduce previously recorded lost time on offset conventionally drilled wells—when applied appropriately. In addition, specific drilling techniques offered within CPD technology not only improve the time it takes to reach total depth (TD), but also have been proven to optimize reservoir section productivity and maximize economically recoverable reserves. CPD is composed of three main techniques: air drilling, underbalanced drilling, and managed pressure drilling. This paper provides an updated discussion of CPD techniques, the nonproductive time that it can address and screening methodology.

A methodology to properly screen CPD techniques to reduce failure/misapplication and align objectives with expectations had been lacking. This paper addresses the latest refinements in an expert system developed to better understand and screen options for CPD operations. The Internet-based selection tool provides guidance by using key indicator questions, beginning with the primary objective(s) for the given wellbore section. If the specific CPD technique is known, the user can activate the online screening tool. The online screening tool considers a range of economic and technical parameters, which are applied to algorithms and logic rules, to provide a relative ranking for each CPD candidate. This paper will also address modifications that have been made to reduce cost related sensitivity when screening air and managed pressure drilling, which previously made the screening process less consistent. Sensitivity analysis can also be performed to determine the impact of key uncertainty parameters. Additional expert-user screening and selection can be incorporated upon the completion of the online CPD candidate selection process. Lastly, the paper will also include supporting case histories.
Bending Tool Face Measurements While Drilling Delivers New Directional Information, Improved Directional Control
Authors: Heisig Gerald , Macpherson John D. , Mounzer Fadi , Linke Christian , Jenkins Mark
Published: February 2010

This paper introduces bending tool face, a new measurement with applications in directional drilling. The measurement is derived from two perpendicular bending moment sensors in the BHA and identifies the orientation of BHA bending with respect to gravity high side while drilling, both in rotating and sliding modes. The paper presents the underlying theory and motivation for the measurement, describes its implementation into a downhole MWD tool and shows measurement examples from field applications. Furthermore, the paper outlines the use of the data for directional calculations. The paper concludes with a discussion of applications in which the bending tool face information adds value, such as reducing uncertainty in casing exit applications and improving directional control in challenging 3-D well profiles. The discussion is supported with field results.
The Developing Role of Deep Azimuthal Resistivity to Assist Optimal Well Placement in the Captain Field, UK North Sea
Authors: Bell Chris , Audinet Cecile , Hammond Lisa , Baule Ansgar , Skillings Jon , Oxborough Melanie
Published: February 2010

The development of deep azimuthal resistivity LWD tools and their use in geosteering horizontal wells has become increasingly important in the development of the Captain Field in the UK North Sea, in combination with a new strategy to access reserves.

As the field matures targets become smaller and wells have to be placed high in the reservoir to maximise recovery. Targets increasingly lie close to the margin of the field where the reservoir rapidly thins, has a rugose top and is poorly imaged on the seismic. The relative mobility of the water to oil also results in unpredictable water development. A combination of these challenges has required the technology to identify the proximity of shale or water, optimise well placement and avoid unnecessary sidetracks.

In 2008, the deep azimuthal resistivity tool, AziTrak™ was first deployed on the Captain Field. The well was geosteered close to the roof. At a point in the well where it was anticipated the well would exit the roof, the deep azimuthal resistivity clearly showed decreasing resistivity. Contrary to expectation the response was from water below. The well was steered up, and realised additional 25ft pay sand above the anticipated top reservoir. Had the deep azimuthal resistivity not been deployed the well path would have been steered down. Ultimately this resulted in approximately an additional 1mmbls of reserves.

The second deployment in 2008 demonstrated the value of being able to rapidly rebuild the reservoir model from the distance to bed boundary data obtained from the deep azimuthal resistivity. The rebuilt model enabled the replan of the second leg of a multi-lateral well. The well was successfully drilled close to top of the reservoir following the re-planned path.

Further benefits can potentially be realised by reducing the number of sidetracks and pilot holes. Pre-planning, modelling and directional drilling as part of an integrated service have played an important role in the successful placement of recent Captain Wells.

It is anticipated that the role of deep azimuthal resistivity will become more important as the Captain Field matures, opportunities become smaller, more technically challenging and in a cost conscious environment.
Automation of Well-Construction Fluids Domain
Authors: Geehan Thomas , Zamora Mario
Published: February 2010

The drive to industrialize the drilling process through automation is gaining greater acceptance within the upstream oil and gas industry. The concerted, multi-faceted effort is being spearheaded by SPE and IADC committees working with industry on a common automation language, fit-for-purpose interface protocols, and a disciplined technology roadmap. The primary purpose of this paper is to define the Well-Construction Fluids (WCF) domain in order to contribute to the roadmap foundation. Also discussed are existing technology gaps related to fluids automation, and targeted efforts to find practical solutions for these gaps.

The WCF domain encompasses the fluids used in drilling and completion operations, as well as the flow conduits, tanks, and process equipment required for optimum performance. At the highest level, the domain is represented by four major systems: (a) fluids treatment and pumping, (b) downhole, (c) solids control, and (d) waste management. Understandably, the WCF domain has a broad sphere of influence and interacts with all well-construction processes, including conventional drilling, well control, managed-pressure drilling, tripping, and running and cementing casing. Because of this interdependence, numerous projects have been initiated to develop robust, automated equipment to measure critical fluid properties required by all these processes.

Within the WCF domain, systems also are being developed to automate and control different fluids processing equipment and to mechanize chemical additions and mixing operations. Ultimate success will depend not only on improved data from better monitoring, but also comprehensive data management systems linked to interpretative schemes and predictive analyses that convert the data into useable knowledge.
Multiwell Thermal Interaction: Predicting Wellbore and Formation Temperatures for Closely Spaced Wells
Authors: McSpadden Albert R. , Coker Oliver D.
Published: February 2010

A method is presented to predict wellbore and formation temperatures for a template of closely spaced wells. Multiwell thermal interaction will alter the wellbore temperatures as well as formation temperatures in the inter-well zones and also further out from the well template. The change in temperature profile relative to a single well can be significant. For producing wells in close proximity, wellbore and formation temperatures will converge to a significantly hotter condition than in the isolated single well case.

The modeling of wellbore and formation temperatures for closely spaced wells has not been widely examined to date. This problem has only been approached using theoretical formulations based on simplified assumptions. The current work presents for the first time a methodology based on standard industry tools and models which yield results consistent with field experience. The method employs standard industry thermal-hydraulic modeling software and a finite-element model (FEM) in a loosely-coupled, iterative analysis which assumes steady-state conditions. Other numerical approaches including finite-difference (FD) and boundary element method (BEM) techniques are also considered. The far-field thermal flux behavior of a single well is also considered as an important baseline for comparison.

The effect of multiwell thermal interaction is important for closely-spaced wells such as offshore platforms or subsea and arctic developments. A case study is presented for an HPHT offshore field development. The multiwell disturbance on formation and wellbore temperatures affects well design, facilities planning and operations. Annular pressure build-up (APB), wellhead movement, tubular stress design, cement slurry design, subsidence/compaction effects and facilities HSE issues can all be affected In some cases, unexpectedly high wellbore temperatures can be catastrophic.

If multiwell thermal interaction is not taken into account, then load events such as APB and wellhead movement and thermal induced stresses may be underestimated. For high-rate production wells, the increase in produced fluid temperatures may be small, but even a small change may be critical. In all cases, the effect on outer wellbore strings/annuli and on the formation is significant. This also impacts the planning of offshore fields to be developed in phases with batch drilling.
Just How Reliable is Your BOP Today? Results from a JIP, US GOM 2004-2006
Authors: Sattler Jeff , Gallander Frank
Published: February 2010

In 2008, several industry groups created a task force to define workscope for a joint industry project to study BOP reliability experienced for wells drilled in the US Gulf of Mexico in the 2004 to 2006 time frame. They also undertook to identify possible contractors, prepared, evaluated, and awarded the bid for completion of this workscope, which included wells utilizing both subsea and surface BOPs (Blowout Preventers).

This paper summarizes major findings and recommendations from the study. The study was easily the most comprehensive one ever completed, with almost 90,000 individual component tests analyzed in the course of drilling 238 wells using 37 different floating drilling units and just over 40,000 individual component tests from 415 wells untilizing 78 surface rigs.
Application-Specific Bit Technology Leads to Improved Performance in Unconventional Gas Shale Plays
Authors: Isbell Matt , Scott Dan , Freeman Mark
Published: February 2010

Unconventional gas plays in Texas, Oklahoma, and Louisiana have become increasingly important. Operators have produced unconventional gas in these shale formations through better well profiles and completion/fracture technology. One key to the fields’ continued success is reducing drilling cost even with the current depressed pricing of natural gas. The two general types of drilling programs are vertical/curve/horizontal profiles and more complex wells drilled from a pad. Each of these well types challenges bit designs. A new application-specific bit design package has been developed for these applications. This new design includes features such as improved stability, steerability, optimized hydraulics, depth-of-cut control, diamond volume management and wear- and durability-optimized cutters.

Over the last couple of years, operators and service companies have developed a three-bit program to successfully drill in the Barnett play. The challenge of this vertical/curve/horizontal program is combining two intervals into one bit run, thus reducing the number of bits from three to two and improving the economics in drilling the well. In complex well profiles, steerability and durability are critical. Until recently, many intervals were drilled exclusively with roller cone bits. The advent of the application-specific bit designs has enabled the operators to replace multiple roller cone bits with one polycrystalline diamond compact (PDC) bit.

This paper will present case studies from multiple independent operators showing the drilling performance improvement, leading to significant cost savings through reduced drilling time and fewer trips. Similar case studies include those in the Haynesville shale play. Runs in the Barnett play have shown up to 91 % faster rate of penetration (ROP) with run lengths of up to 92% longer footage. In the Haynesville play, bits have shown above average ROP with footage increases of 39%.

Operators are rapidly adopting this technology and strategy throughout these fields and similar fields in other markets.