bluuebunny/crossref_metadata_2025 huggingface dataset:
Using Deep-Azimuthal Resistivity and 3D Seismic for Optimal Horizontal Well Placement: An Integrated Approach, Nipisi Field, Western Canada
Authors: Omovie Sheyore John , Pearson Warren
Published: March 2012

A major challenge facing the oil industry is optimizing horizontal wellbore placement in a reservoir. Uncertainty in the predrill geological model and seismic interpretation may lead to the well being placed in non-reservoir, or steering the well out of the prospective formation. This can lead to lower well performance or the requirement to sidetrack the wellbore, both of which directly impact the profitability of the operation.

The Nipisi D Pool produces oil from the Middle Devonian Slave Point Formation, a regionally extensive carbonate bank characterized by low permeability limestone reservoir. The advent of horizontal drilling (HZ) and completion technologies has elevated this reservoir to a top tier tight oil resource play. Although HZ drilling provides a cost effective means to reservoir development, maximizing reservoir penetration while avoiding the unstable shale above the Slave Point are imperative.

Structural definition of the reservoir is provided by 3D seismic coverage. This provides a good predrill estimate of wellbore trajectory, however is limited in its vertical accuracy, as well as definition of small-throw faults that do not appear to be imaged on the seismic data. These two limitations introduce a real risk of drilling out of the productive zone.

Using the contrast in resistivity between the productive carbonate reservoir and the low resistivity Waterways shale which overlies it, deploying Measurement-While Drilling (MWD) deep azimuthal resistivity tools provided the operator with higher resolution measurements to detect the top of reservoir and keeping the wellbore within the desired reservoir. This paper focuses on the integration of geological/3D seismic mapping and MWD azimuthal resistivity for optimal HZ well placement in a tight limestone reservoir, as well as the limitations of each technology when used in isolation. It illustrates how utilizing this approach the operator was able to achieve 100% reservoir exposure.
True Zonal Isolation in Openhole Alternate Path Gravel Pack Completions
Authors: Barry Michael D , Hecker Michael T. , Yeh Charles S. , Moffett Tracy J.
Published: March 2012

Openhole completions are often selected as the preferred completion technique to maximize reservoir flow potential and provide reliable, high capacity, low skin completions. With the advances of Alternate Path® Technology (APT), a full gravel pack can be realized under challenging well conditions to provide increased long-term reliability. One drawback to openhole gravel packs has always been the inability to isolate water or gas, whether it is during the initial completion or during the production lifecycle of the well. ExxonMobil embarked on a multi-year initiative to develop, qualify, and successfully deploy Shunt Zonal Isolation (SZI) packer technology that, when combined with Internal Shunt Alternate Path Technology (ISAPT) screens, can provide true zonal isolation in an openhole gravel pack completion.

The new openhole technology enables greater extended drilling to capture additional pay, selective completions to isolate zones, and production flow control inside the screen basepipe similar to cased hole conditions. True zonal isolation in openhole gravel pack completions facilitates more flexible well planning and operational execution while maintaining reliable sand control. This paper will explore the range of application opportunities this new technology presents.
A Systematic Approach to Improving Directional Drilling Tool Reliability in HPHT Horizontals in the Haynesville Shale
Authors: Pinto Errol , Mota José , Grable Jeffery , Ward David
Published: March 2012

Unconventional shale gas has become an increasingly important source of natural gas in the United States over the past decade, and interest has spread to shale-gas plays in multiple countries. Shale gas is expected to continue to supply larger shares of the natural-gas production in North America by 2020.

One of the most active shale plays in North America is the Haynesville, which represents extreme challenges in drilling horizontal lateral sections with 16,500–18,500-ft measured depth wells and flowing temperatures that can exceed 375°F at section TD. This paper examines a collaborative and systematic approach between the service provider and operator to drive relentless performance improvements in the production interval of the Haynesville.

In 2009, the team set out a challenge to eliminate mud motor and MWD failures in the production interval. The approach outlined in this paper will explore how root-cause failure analysis, new condition-based maintenance systems, and field-operation processes were used to systematically push MWD, mud motor, and LWD performance in this hostile environment.
Blowout Preventer (BOP) Health Monitoring
Authors: Mckay Jim , Simmons Clayton , Hogg Tony , Starling Gavin , Doty Mike , Pere Allen
Published: March 2012

As every motorist knows, a vehicle’s dashboard is an important interface that alerts the driver of real-time changes regarding certain car engine "health?? metrics and alerts the driver that the engine may need to be serviced. While not a diagnostic tool in and of itself, the dashboard serves to alert the driver that a performance or health issue may exist. Blowout Preventer (BOP) equipment is designed to secure the well and a BOP’s health is critical to ensuring that it works as designed. A realtime BOP dashboard can improve communication between operations personnel, rig contractor subsea engineers and the Original Equipment Manufacturer (OEM) to assess potential BOP health issues.

This paper describes a development process for a BOP dashboard and discusses the potential benefits, challenges, and lessons learned associated with implementing a BOP monitoring system.
Upgrading the Real-Time Drilling Optimization Culture in Brazil’s Challenging Deepwater Operations: The Utilization of a Remote and Rigsite Multidisciplinary Collaborative Concept
Authors: Borella Hougaz Augusto , Gozzi Danilo S. , Fujshima Isao , Vello Klaus L. , Alves Sandro , Thomson Ian , Krasuk Raul , Buzzerio Frank
Published: March 2012

In recent years deepwater drilling operations has become more challenging and expensive, new exploratory frontiers and the rise of rig rates demanding the need for first-class drilling optimization technology and services. In Brazil, deepwater well construction activities increased significantly since the first major pre-salt discovery in the Santos basin in 2006.

In this highly demanding and extremely challenging drilling scenario, building a drilling optimization culture based on the synergy and integration between a major deepwater operator and a leading service company has proven to be fundamental for achieving better drilling results and superior performance.

The creation of a multidisciplinary drilling optimization group, integrated with the operator’s drilling team in 2008, and the introduction of a highly specialized downhole drilling dynamics measure while drilling (MWD) tool changed the drilling optimization concept in Brazil. This new optimization concept pioneered the remote (off-the-rig) downhole drilling parameters surveillance in deepwater operations.

This paper will present the fundamentals of this real-time remote and rigsite drilling optimization concept, with focus on the integration between the operator and the service company, the operational aspects, with regards to appropriate communication protocols and decision-making processes, highlighting the performance improvement achieved to date.
Case Study on Bottom Hole Assembly Tool
Authors: Verhoef Richard
Published: March 2012

In these days of rig automation and advanced rig mechanization, the industry may wonder why running the Bottom Hole Assembly (BHA) still requires more people on the drill floor and more equipment then required when tripping in or out.

Part of the reason is that BHA’s are made up of many different components; each usually having a separate outside diameter, which means every component needs a specific set of hand slips. Furthermore, every component needs to be secured by a safety clamp to prevent unwanted pipe slippage. Both setting the slips and fixing the safety clamp is a manual process, which often requires 2-3 persons to complete. This is a potentially unsafe practice and it is imperative to find a reliable solution to meet this challenge.

The Bottom Hole Assembly Tool (BHAT) provides the solution to all of the main challenges faced when handling the BHA:

(1) many different diameters (2) safely running collarless components with relative low loads

The BHAT eliminates these problems because it is able to grip a wide range of diameters without component changes to the tool; it grips BHA components with the necessary force so the BHA cannot slip through and with such built-in safety features a safety clamp is not needed.

During the design and prototype testing of the BHAT, all individual design features have been examined in great detail; from the design of the inserts teeth profile, to the clamping force of the cylinders and its integrated safety features.

This paper presents the design challenges and the prototype testing leading to the final version of the BHAT.
Establishing an Industry Best Practice on Subsea Wellhead Fatigue Assessment
Authors: Buchmiller D. , Hørte T. , Grytøyr G. , Haug L. T.
Published: March 2012

Wellhead fatigue has received priority attention within the drilling industry, especially on the Norwegian Continental Shelf. Concern has also been raised in other areas of the world when drilling on existing older wells and when using new heavier rigs and BOP systems. Focus has been on developing a universal wellhead fatigue calculation methodology. This is part of an ongoing joint industry project (JIP) facilitated by DNV with participation from BG Group, BP, Chevron, Det Norske, Eni, ExxonMobil, GDF Suez, Lundin, Marathon, Nexen, Shell, Statoil, Talisman, Total and Woodside. Motivation for developing an industry guideline stems from the fact that existing international standards provide limited or no guidance on wellhead fatigue calculation.

A recommended practice is being finalized through the ongoing JIP, which builds on the strengths of the methodologies available in the industry today. The RP provides guidance on selection of methodologies for wellhead fatigue assessment based on the specific conditions for a subsea well.

Due to the harsh weather conditions and shallow waters of the North Sea, wellhead fatigue has historically been a challenge. There are uniquely different challenges in deeper water, such as the Gulf of Mexico, which influence the selection of the analysis approach. In recent years, there have been a number of papers published on wellhead fatigue, and the background for different methodologies as well as the key differences is presented in this paper.

It is crucial that the drilling industry is aware of the challenges with regard to a consistent safe design and operation of its equipment and that the industry is continuously pushing forward to improve upon design methodology and guidelines. This methodology incorporates key elements from the best practices from around world on wellhead fatigue analysis.
Regeneration of First-Generation Subsea Fields: The Challenges of New Wells in Old Infrastructure
Authors: Stright Sean , Srivastava Vikas , King Gregory , Smith David W. , Tears Nelson
Published: March 2012

A large number of subsea production wells have been drilled, but to date there has been limited industry experience of redrilling subsea wells, whereas, redrills have become routine in platform and surface wellhead applications. The focus of this paper is to highlight some of the key aspects of redrilling a subsea production well to extend field life.

The paper will describe how the unique challenges of redrilling three subsea wells were overcome in old and declining fields where the original wells were designed and drilled with limited consideration for redevelopment of the fields through reuse of existing wells. The paper will define the problems of and describe the solutions to:

The mooring and BOP handling constraints in the crowded subsea infrastructure of a subsea field development. The riser and wellhead analysis for redrilling a well through a subsea tree, and the operational practices required to maintain tree and wellbore integrity. The analysis of the additional loads put on a subsea well through the extended period of riser and BOP loading. The casing exit and redrill constraints unique to operations from a semi-submersible rig; casing recovery operations, the management of window milling debris in a subsea BOP system.

There has been limited industry experience to date of subsea production well redrills, and this paper will share the significant lessons learned which will be of wider application, as the number of subsea wells increase along with the requirement to maximize recovery and extend field life.
Size Degradation of Granular Lost Circulation Materials
Authors: Scott Paul D. , Beardmore David H. , Wade Zack D. , Evans Eddie , Franks Krista D.
Published: March 2012

Lost circulation is a major cause of drilling non-productive time with significant cost implications for many locations throughout the world. Increased attention on the performance of lost circulation materials and engineered solutions to lost circulation, such as wellbore strengthening and the recycling lost circulation materials, has brought about the need to use materials which do not size-degrade rapidly.

Little mechanical property data or shear degradation information is available for most lost circulation materials as they are normally not highly engineered materials, and standard test methods have not been developed. In addition, lost circulation materials are often sourced locally to reduce cost, and logistics are such that they may not come from sources with consistent quality.

Anecdotal information about which materials size-degrade most is common in the industry but little scientific information is available. Field data has conclusively shown that lost circulation materials degrade in size with time. A laboratory procedure has been developed and used to study the relative reduction in particle size of the most common granular products.

Laboratory and field data are presented to demonstrate the relative size degradation rates for several common lost circulation materials. This data on the relative degradation in the particle size distribution of granular lost circulation materials will provide improved understanding of their performance for more efficient application of the materials. This will lead to improvements in wellbore strengthening and lost circulation material recycling applications.
Directional Drilling Tests in Concrete Blocks Yield Precise Measurements of Borehole Position and Quality
Authors: Stockhausen Ed , Lowdon Ross , Lesso Bill
Published: March 2012

Directional drilling is accomplished by causing a mechanical or hydraulic deflection of the bit during drilling. Predicting BHA behavior prior to drilling and taking survey check-shots while drilling is common practice because understanding the directional tendency of a BHA is critical to successful well placement.

It has been suspected that different modes of drilling cause a near instantaneous change in the size, shape and centerline position of the borehole and, thus, change BHA tendencies. This is not backed up by continuous MWD inclination data which shows a long transition between the slide/rotate zones.

Since examining a wellbore to accurately determine these effects is impractical, a logical approach would be to set up a directional drilling process where the wellbore could be dissected and examined. Precise measurements of the wellbore centerline, diameter or circumference can be made under laboratory conditions and compared to field sensor measurements to determine the accuracy of the field measurements in terms of wellbore position, tortuosity and rugosity. Schlumberger developed a directional drilling test capability utilizing concrete blocks placed sequentially and drilled horizontally. The blocks can be positioned to accommodate changes in wellpath. They are sealed to allow mud flow during the drilling and then broken apart for extensive laser measurements and scans. The blocks are tagged to allow surveying to maintain a 3D coordinate system to millimeter accuracy.

Chevron and Schlumberger conducted a series of drilling tests to evaluate wellbores drilled with positive displacement motors (PDM’s). The blocks were drilled with slide/rotate sequences with up to 10 deg/100ft curve rates. Multiple MWD directional surveys were taken and compared to the actual position of the wellbore from the lab measurements.

This paper discusses the TVD accuracy of the well as a function of different survey spacing and its impact on horizontal well placement. Changes in touch points of the BHA within the varying hole diameter of the slide/rotate sections are also discussed. Metrics are proposed for managing wellbore quality in terms of tortuosity and rugosity along with their impact on the wider drilling community.
Continuous Circulation Drill String Sub
Authors: Weir J. , Goodwin R. , Macmillan R.
Published: March 2012

There is an increasing need to drill difficult reservoirs in a cost effective way. Over the past few years Managed Pressure Drilling (MPD) has made it possible to drill reservoirs which have a narrow window between pore and fracture pressure gradients. Before the introduction of MPD techniques, safely drilling and completing these formations was very costly and not always successful. Cycling the mud pumps off and on for connections affects the pressure and is a major problem for MPD. Techniques and equipment have been developed to make a connection while continuing to circulate the drilling mud to maintain constant pressure. Since 2005, the Continuous Circulation System (CCS) has allowed continuous circulation during connections with traditional jointed drill pipe, by using a chamber around the connection. Several companies have developed continuous circulation subs which are threaded between tool joints to achieve continuous circulation without a pressure chamber. These have had varying degrees of success from both an operational and safety standpoint. This paper describes the current MPD market and describes the philosophy adopted for a new side-entry sub.
Qualification of a 4.75 in. Rotary Steerable System for Complex 3D and High Build-up-Rate Applications in through Tubing Drilling (TTD) Operations
Authors: Eidem Morten , Andersen Stein Kristian , Winterstø Knut Morten , Schwartze Sascha , Clemmensen Carl C. , Nesheim Anders
Published: March 2012

Maturing of fields in the North Sea has led to a drive for technologies to extend field life and improve recovery rates. Through Tubing Drilling (TTD) is one technology which shows particular potential with regards to accessing bypassed oil and multiple small targets. TTD consists of two closely related technologies, coiled tubing drilling (CTD) and through tubing rotational drilling (TTRD). These technologies allow for re-entry through existing wells and drilling of one or more laterals from the existing well bore, while the old completion and Xmas tree remain in place. With the kick-off point below the production packer and subsequently close to depleted/over-pressurized zones or water, a high dogleg RSS is required based on the fact that a motor with bend causes high risk of damaging the crown plug seal area in the horizontal Christmas tree.

The Operator has for several years supported the industry in order to qualify a high dogleg Rotary Steerable System (RSS) with a motor to achieve the following:

– Perform subsea TTRD through 5.75 in. restrictions and with 15 deg/30 m dogleg capability. Consistent dogleg capability of 12 deg/30 m or more will enable TTRD in about 50 % more wells, compared to having a dogleg capability of 6 deg/30 m. – Minimize tubing wear during TTRD by combining motor and RSS. – High RSS reliability. – Enable use of RSS in CTD operations.

In collaboration with the Service company a modified 4.75in. RSS combined with a downhole motor successfully achieved the following objectives:

– Demonstrate max build-up and dogleg of 15 deg/30 m in wells with 5.75 in. pass through. – Verify capability of performing CTD, with regards to high dogleg capability with low weight on bit. – Demonstrate drilling capabilities with motor and with low RPM – Demonstrate capability of holding tangent. – Verify long life time.
A New, Alternative Weighting Material for Drilling Fluids
Authors: Al-Bagoury Mohamed , Steele Chris
Published: March 2012

Barite has been used to increase the density of drilling fluids (DF) since 1922. However, circumstances & needs are changing:

The API has recently introduced a new standard for 4.10 sg barite in recognition of diminishing supplies of readily available barite that meet API’s standard minimum density specification of 4.20 sg - high quality barite is running out. The search for new hydrocarbon resources to replace reserves has resulted in more difficult drilling conditions & fluid requirements e.g. deepwater, ERD, HPHT etc., where ECD management, sag control & formation damage mitigation are critical to success.

Alternative weighting materials (WM) such as manganese tetraoxide, treated micronized barite & cesium formate have been successfully used to handle many of the problems mentioned, but they are expensive & not produced in large volumes. Therefore, their application tends to be restricted. There is, therefore, a need for alternative weighting materials capable of providing better functionality than barite, but available in sufficient volumes to meet requirements & be competitively priced.

This paper describes a new micronized, weighting agent, suitable for use in drilling & completion fluids, which offers significant advantages in the control of ECD, sag & formation damage. It is denser than barite, acid soluble, available in large volumes of > 100,000 tpa and is significantly cheaper than the current, high-end weighting materials.

Test results are given showing stable fluids with low plastic viscosity, gel strengths & sag, even under HPHT conditions, for both aqueous & non-aqueous based fluids. The material has an excellent HSE profile & is soluble in oilfield acids. Accordingly, it provides a viable alternative product, intermediate between barite & the more expensive weighting materials.
Integrated Pressure Management Processes for Reducing the Risk Associated with Well Instability Issues: Implications for HPHT Wells
Authors: Figenschou Jorunn Haver , Thorsen Arve K. , Thistle Bruce , Williams Urban
Published: March 2012

Optimizing well control processes are critical in high-temperature/high-pressure (HPHT) drilling operations so they do not encounter high cost overruns and compromise safety. The key to success is recognizing and mitigating challenges and associated risks early to adequately optimize drilling operations. This leads to a more effective drilling operation with reduced risk, increased safety margins and increased probability of successfully achieving the well’s objectives.

This case describes an integrated work process that has been implemented, incorporating pre-drill and real-time pore pressure prediction with proactive equivalent circulating density (ECD) management during well planning and drilling operations. This work process is especially important for optimizing drilling fluid properties to retain the drilling parameters within a safe operating mud window identified by real-time pore pressure and wellbore stability prediction. Operating in this safe window enables reduction in wellbore instability, formation damage, hole cleaning inefficiencies and poor drilling performance, resulting in improved safety margins, reduced risk, improved drilling performance and reduction in non-productive-time (NPT).

Several recent examples from Suncor Energy Norge HPHT wells are presented to illustrate the success of utilizing this integrated approach, resulting in drilling HPHT wells with no formation pressure-related NPT. The process begins with identifying pressure-related challenges in the pre-drill planning phase, optimizing the drilling process by validating, defining and maintain the drilling parameters within the safe operational window through an integration of proactive real-time pore pressure prediction and ECD management using all available LWD measurements: acoustic, gamma, resistivity, density, formation pressure while drilling, imaging, ECD, and temperature. Analysis is performed on mud logging data such as gas, the drilling exponent, cuttings and borehole caving and surface drilling data. Finally, lessons learned are captured that will further improve drilling efficiency and best practices in upcoming drilling campaigns.
Is There a Place for High Reliability Organisations in Drilling?
Authors: Thorogood J. L.
Published: March 2012

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

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

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

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

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

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

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

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

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

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

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.