Extended Reach Drilling Guidelines - BP

EXTENDED REACH DRILLING

GUIDELINES © Copyright The British Petroleum Company p.l.c., 1996. All rights reserved. British Petroleum wishes to acknowledge the contribution of ARCO Exploration and Production Technology in the preparation of these ERD Guidelines.

Acknowledgments

These Guidelines are a collaborative effort. BP acknowledges the contributions of the following individuals, and other parties.

British Petroleum Fereidoun Abbassian Arnis Judzis Dave Andrew Daryl Kellingray Mark Aston Nigel Last Kevin Barrington Charlie Leslie Peter Bern Yuejin Luo Colin Bowes John Martin Brian Chambers Mike McLean Dave Cocking Samir Modi Rob Dallimer Rune Olsen Joe Duxbury Steve Parfitt Martyn Fear John Pucknell Mike Guy John Thorogood Phil Hearn Allan Twynam Perry Hill Curtis Weddle John Henderson Hugh Williamson Kamal Jardaneh

Statoil

Harald Blikra OGCI

Mark Brooker Gerald Coulter Deutag

John Gammage Anadrill

Andy Hatch TH Hill Associates

Tom Hill Marc Summers Halliburton

Nic Jepson Larry Wolfson Arco

Mike Payne

Table of Contents

SECTION 1: INTRODUCTION

Purpose......................................................................................................................................... 1 Strategy......................................................................................................................................... 1 Focus ............................................................................................................................................ 2 Format........................................................................................................................................... 2 Feedback ...................................................................................................................................... 2

SECTION 2: OPERATIONS ACHIEVEMENTS

SECTION 3: TRAJECTORY AND DIRECTIONAL DRILLING OPTIMIZATION

Introduction ................................................................................................................................3-1 Trajectory Design and Planning.................................................................................................3-2

Optimum Trajectory..............................................................................................................3-2 Choosing Among Classes of Trajectories ............................................................................3-3 Influence of friction factor (μ) ...............................................................................................3-4 Additional Directional Planning Tips ....................................................................................3-5 Anti-collision Planning..........................................................................................................3-6 Effect of Build Rate ..............................................................................................................3-6

Directional Drilling Planning and Implementation ......................................................................3-7 Drilling Assemblies...............................................................................................................3-7 Downhole Motor Usage........................................................................................................3-9 MWD/LWD Considerations ................................................................................................3-10 Bit Selection .......................................................................................................................3-10 Tortuosity Issues................................................................................................................3-11 Influence of Buckling..........................................................................................................3-11

Wytch Farm Procedure For Sliding A Steerable Motor At Extreme Horizontal Departures .....3-13

References...............................................................................................................................3-14

TOC-1

SECTION 4: COMPLETION AND FUTURE WELL MANAGEMENT ISSUES

Introduction ................................................................................................................................4-2

Wellbore Considerations............................................................................................................4-4 Planning Well Profile ............................................................................................................4-4 Mud Design & Hole Cleaning Issues....................................................................................4-5 Drilling Reservoir Section.....................................................................................................4-6 Displacements......................................................................................................................4-6

Completion Types ......................................................................................................................4-7 Extended Reach / Horizontal Well Completions for Sand Control .......................................4-9 Gravel Packing / Fracpacking ............................................................................................4-10 Frac Pack Completions ......................................................................................................4-10 Designing Upper Completion .............................................................................................4-11 Running Upper Completion................................................................................................4-11 Damage Removal in Extended Reach / Horizontal Wells ..................................................4-11 Matrix Stimulation...............................................................................................................4-13 Hydaulic Fracturing ............................................................................................................4-13

Well Interventions ....................................................................................................................4-14 Open Hole Logs/RFT .........................................................................................................4-14 Cement Evaluation.............................................................................................................4-14 Perforating..........................................................................................................................4-15 TCP....................................................................................................................................4-15 Running & Pulling Completions..........................................................................................4-16 Production Logs .................................................................................................................4-16 Water/Gas Breakthrough Management .............................................................................4-16 Coiled Tubing.....................................................................................................................4-16

Artificial Lift...............................................................................................................................4-18 ESPs ..................................................................................................................................4-18

Recommended Additional Reading .........................................................................................4-18

References...............................................................................................................................4-19

SECTION 5: MECHANICAL AND CHEMICAL WELLBORE STABILITY

Introduction ................................................................................................................................5-1 Mechanical Aspects ...................................................................................................................5-2

Planning Stage...............................................................................................................5-3 Drilling Stage..................................................................................................................5-4

Chemical Aspects ......................................................................................................................5-5 Planning Stage...............................................................................................................5-6 Drilling Stage..................................................................................................................5-7

References.................................................................................................................................5-7

Contacts.....................................................................................................................................5-7

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SECTION 6: DRILLING FLUIDS OPTIMIZATION

Introduction ................................................................................................................................6-1 Selection of Fluid Type ..............................................................................................................6-2

Environmental Issues...........................................................................................................6-2 Optimization of Fluid Formulation ........................................................................................6-3 Barite Sag ............................................................................................................................6-4 Wellbore Stability/Inhibition..................................................................................................6-4 Hole Cleaning Capability......................................................................................................6-5 Mud Lubricity - Torque and Drag Reduction ........................................................................6-5 Filtration Control/Differential Sticking...................................................................................6-6 Solids Control Management.................................................................................................6-6 Formation Damage Aspects.................................................................................................6-7

General Considerations .............................................................................................................6-7

References.................................................................................................................................6-8

Contacts.....................................................................................................................................6-8

SECTION 7: TUBULAR DESIGN AND RUNNING GUIDELINES

ERD Well and Casing Program Design Issues..........................................................................7-1

Severe ERD Casing Running ....................................................................................................7-2 Critical Casing Pickup Loads ...............................................................................................7-3 Critical Casing Slackoff Weights ..........................................................................................7-4

Liner Running and Rotation .....................................................................................................7-11

Casing Wear ............................................................................................................................7-13 Wear Modeling ...................................................................................................................7-13 Wear Management.............................................................................................................7-13 Wear Monitoring and Measurement...................................................................................7-14

Casing/Liner Centralization......................................................................................................7-15

Tubular Design and Running Summary...................................................................................7-16

References...............................................................................................................................7-18

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SECTION 8: CEMENTING

Option Selection - Considerations When Selecting ERD Candidates .......................................8-1 Theory and Introduction .......................................................................................................8-1

Pre-Drill Data Package - Required Prospect Information ..........................................................8-2

Well Planning - Feasibility Through Detailed Drilling Procedures..............................................8-3 Equipment ............................................................................................................................8-3

Slurry Design and Testing Requirements ..................................................................................8-5

Implementation - Operational Issues, Rig Practices ..................................................................8-6 Cement Placement and Mud Removal ................................................................................8-7

Centralization .............................................................................................................................8-9 Setting Cement Plugs in ERD/Horizontal Sections ............................................................8-12

Post Analysis/Performance Measurement...............................................................................8-13

Wytch Farm Case History ........................................................................................................8-14 ERD Stage III Development - Wells F18-F21 and M1-M15 ...............................................8-14 Future Wells .......................................................................................................................8-16

References...............................................................................................................................8-16

Contacts...................................................................................................................................8-16

SECTION 9: DRILL STRING DESIGN

Introduction ................................................................................................................................9-1 Non-Cyclic Load Trends ............................................................................................................9-2

Torque..................................................................................................................................9-3 Tension and Combined Tension/Torsion .............................................................................9-4 Estimating Non-cyclic Loads in a Well .................................................................................9-8 Handling High Non-cyclic Loads ..........................................................................................9-9 Reduction and Redistribution of Non-cyclic Loads.............................................................9-10 Cyclic Loading and Fatigue................................................................................................9-10 Buckling .............................................................................................................................9-11 Cyclic Stress Induced by BHA Sag ....................................................................................9-12

Other Drill String Design Issues...............................................................................................9-13 Annular Velocity and Drill Pipe Size...................................................................................9-13 Hydraulics and Drill Pipe Size............................................................................................9-13 Casing Wear Issues...........................................................................................................9-14 Jar Placement ....................................................................................................................9-14 Drill String Inspection Practices .........................................................................................9-15

References...............................................................................................................................9-16

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SECTION 10: TORQUE AND DRAG PROJECTIONS

Introduction ..............................................................................................................................10-1 Torque Projection.....................................................................................................................10-1

Torque Components ..........................................................................................................10-1 String Torque .....................................................................................................................10-2 Bit Torque...........................................................................................................................10-7 String Torque Prediction ....................................................................................................10-9 Torque Monitoring and Management Measures ..............................................................10-11

Drag Projections ....................................................................................................................10-13 Drag Friction Factors and Monitoring...............................................................................10-13 Buckling Behavior ............................................................................................................10-14 Predicting Drag and Buckling Severity.............................................................................10-16 Buckling Impact on the String ..........................................................................................10-17 Drag Monitoring and Management Measures..................................................................10-18

Torque and Drag Projection Summary ..................................................................................10-20

References.............................................................................................................................10-21

SECTION 11: HOLE CLEANING AND HYDRAULICS

Introduction ..............................................................................................................................11-1 Hole Cleaning ..........................................................................................................................11-2

Well Plan............................................................................................................................11-2 Mud Properties...................................................................................................................11-3 Drilling Practices ................................................................................................................11-4 How Cuttings are Transported ...........................................................................................11-9 Cuttings Transport Models ...............................................................................................11-10

Hydraulics ..............................................................................................................................11-13 System Pressure Loss .....................................................................................................11-13 Mud Rheology ..................................................................................................................11-14 Hydraulics Modeling.........................................................................................................11-14

References.............................................................................................................................11-16

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SECTION 12: RIG SIZING AND SELECTION

Introduction ..............................................................................................................................12-1 Rig Sizing.................................................................................................................................12-2

Well Design........................................................................................................................12-2 Operational Requirements .................................................................................................12-2 Hydraulic Requirements.....................................................................................................12-3 Torque and Drag Predictions .............................................................................................12-4

Equipment Sizing and Specifications.......................................................................................12-5 Efficiencies.........................................................................................................................12-9

Evaluation ..............................................................................................................................12-14

Example .................................................................................................................................12-14

References.............................................................................................................................12-15

Rig Sizing and Selection ........................................................................................................12-16

SECTION 13: SURVEYING PRINCIPLES AND PRACTICE

Introduction ..............................................................................................................................13-1

Setting Clear Objectives ..........................................................................................................13-2

Hitting the Target .....................................................................................................................13-2 Anti-Collision ......................................................................................................................13-3 Contingency for Relief Well Drilling....................................................................................13-4 Tools and Techniques........................................................................................................13-4 Magnetic Surveys...............................................................................................................13-4 Magnetic Bias.....................................................................................................................13-4 Magnetic Interference Corrections .....................................................................................13-5 In-Hole Referencing ...........................................................................................................13-6 In-Field Referencing...........................................................................................................13-6 Gyro and Inertial Surveys...................................................................................................13-6 Running Methods...............................................................................................................13-7 Continuous versus Stationary Tools ..................................................................................13-7 Gyro While Drilling .............................................................................................................13-7 Survey QA Tool Comparison and Learning .......................................................................13-8

Surveying - Principles and Practice .........................................................................................13-8

Setting Objectives ....................................................................................................................13-8

Program Design and Tool Limitations......................................................................................13-9

References.............................................................................................................................13-10

Contacts.................................................................................................................................13-10

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SECTION 14: DRILL STRING DYNAMICS

Severe Vibration ......................................................................................................................14-1 How to Know Severe Vibration is Occurring ......................................................................14-2 Symptomology and Control of Vibration.............................................................................14-2 Controlling Severe Vibration ..............................................................................................14-3 Vibration Monitoring Tools .................................................................................................14-3 Rotary Feedback Systems.................................................................................................14-4 Consideration of Geology...................................................................................................14-4

References...............................................................................................................................14-5

SECTION 15: SURVEYING PRINCIPLES AND PRACTICE

Introduction ..............................................................................................................................15-1

Kick Tolerance .........................................................................................................................15-1

Kick Prevention and Detection.................................................................................................15-2

Well Shut-In and Surface Pressures........................................................................................15-2

During Well Shut-In Period ......................................................................................................15-3

Well Kill Techniques.................................................................................................................15-3

Trapped Gas in Inverted or Horizontal Hole Section ...............................................................15-4

References...............................................................................................................................15-4

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SECTION 16: STUCK PIPE PREVENTION

Well Planning - Anticipating Probable Mechanisms.................................................................16-1

Differential Sticking ..................................................................................................................16-2

Formation Related ...................................................................................................................16-4 Geopressured ....................................................................................................................16-4 Reactive .............................................................................................................................16-4 Unconsolidated ..................................................................................................................16-6 Mobile.................................................................................................................................16-7 Fractured/Faulted (tectonic) ...............................................................................................16-8 Inadequate Hole Cleaning..................................................................................................16-9 Wellbore Geometry/Keyseating .......................................................................................16-10 Collapsed Casing.............................................................................................................16-12 Cement Blocks .................................................................................................................16-13

Connections Guidelines .........................................................................................................16-14

Reaming and Back-Reaming Guidelines ...............................................................................16-15

Freeing Stuck Pipe.................................................................................................................16-17

Stuck Pipe Issues ..................................................................................................................16-18

Contacts.................................................................................................................................16-19

References.............................................................................................................................16-19

SECTION 17: EMERGING TECHNOLOGIES

Drill Strings...............................................................................................................................17-1 High-Strength 165 ksi Drill pipe..........................................................................................17-1 Purpose-Built ERD Drill Pipe..............................................................................................17-2 Composite Drill Pipe...........................................................................................................17-2 Titanium Drill Pipe..............................................................................................................17-2 Thread Inspection ..............................................................................................................17-3 Lubricant Embedded Hardfacing........................................................................................17-3

Directional Drilling Systems .....................................................................................................17-4 Rotary Steerable Drilling Systems - Inclination Control .....................................................17-4 Rotary Fully Steerable Systems - Inclination and Azimuth Control....................................17-6 Summary..........................................................................................................................17-12

Other Special Equipment .......................................................................................................17-13 Sonic LWD Tools .............................................................................................................17-13 Magnetic Interference Correction Software......................................................................17-13 MWD Gyro System ..........................................................................................................17-14 Inteq / Mitsubishi Drilling Mechanics Sub.........................................................................17-14 Security/DBS Flexible Bit .................................................................................................17-15 Liner Thruster Tool...........................................................................................................17-15 Wireline and Coil-Tubing Tractors....................................................................................17-16 Enhanced Performance (Lo-Torque) Drill Pipe ................................................................17-16

References.............................................................................................................................17-18

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Section 1

Introduction

This is the first version of the ERD Guidelines, which has been compiled on behalf of the BP Exploration Extended Reach Drilling Network. The Guidelines are a collaborative effort designed to give each BP Asset the benefits of our past experiences and to provide a base for Assets new to ERD. BP acknowledges the contributions of ARCO Exploration and Production Technology, and the substantial input from BP Exploration Technology Provision, Anadrill, Halliburton, T.H. Hill Associates, Inc., OGCI Management, Inc., Statoil and other parties.

Purpose

These Guidelines were developed to provide Drilling Staff in Assets and shared resource groups with guidance on current best practice. The information contained herein is based primarily on experience in Wytch Farm, the North Sea, and the Gulf of Mexico. BP is at the forefront of the industry in the application of ERD, and these Guidelines are intended to help maintain this position.

Strategy

In 1995, the ERD Network developed a strategic plan to develop all aspects of ERD opportunity for the Company. The Network developed a company-wide position that describes the role and capability of the Asset engineers. The Network continues to enhance processes for ERD option selection, well design and planning, implementation, performance measurement, and post appraisal. As would be expected, the Network is taking an active role in the direction and development of industry technology for Extended Reach drilling and production. For Asset managers, the ERD Guidelines partially define "what is possible?."

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Focus

These ERD Guidelines focus on well design, well planning and implementation at the field location. Well planning is an iterative process to determine the optimal mix of wellpath, fluid and tubular requirements, drillstring design, and so on. The information in the Guidelines is organized in a manner that supports this iterative process and highlights inter-relationships between technical components. Because this is a dynamic system both above and below the rotary table, we suggest that you cross reference between sections. No section contains an exhaustive discussion of all inter-relationships. Field implementation will require that you examine the Guidelines within the context of the actual situation.

Format

These Guidelines are just one component of the ERD Network's pledge to increasing BP's ERD capability world-wide. Since 1994 the Network has followed the principles of 'organizational learning', and is committed to promoting the strategic selection of ERD as a development option. This goes hand in hand with the Network's ongoing work in accessing and providing the latest in ERD technology and techniques.

This information will be made available in several formats, providing users with various means of access and to facilitate regular updates. Control copies of the Guidelines are available on diskette, but primary access will be via the ERD Home Page. Updates are scheduled throughout 1996.

The Guidelines are currently being reformatted to make them available in OLS - the OGCI Organizational Learning System(tm) - which is designed to aid learning within project application. This process format will be available 1Q 1996.

Feedback

The commitment of BP to becoming a learning organization places a requirement on the users of these Guidelines. The Network intends that continuous loop communication will allow the Guidelines to be genuinely live. Contributions from the users are not only valuable, they are essential.

For the Network's efforts to continue to reflect the Company's latest understanding and capability, each iteration of ERD option selection, planning and execution should be reported back to provide the Network with the benefits of the learning experienced by those Asset Teams. The reservoir, surface and contractual conditions of each project will challenge and enhance the Guidelines. The more effective each Asset is at putting new information out into the BP public forum, the more effective the Company becomes at maintaining world-wide ERD leadership. Beyond drilling, the Network is actively examining ER completions, interventions and life cycle issues that impact the total value of the technology.

Please treat the Guidelines not as a manual but as an active workbook, shared by the ERD community. Annotate and feed back information as often as new experience dictates. With the co-operation of each user, these Guidelines can be improved substantially in the future.

Please send feedback or comments to Colin Bowes, Kamal Jardaneh, Arnis Judzis, or your local ERD Network representative.

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Acknowledgements

The ERD Network would like to thank the following people for their contributions to the ERD Guidelines as authors and reviewers:

• Fereidoun Abassian • Mark Aston • David Andrew • Kevin Barrington • Peter Bern • Harald Blikra • Colin Bowes • Mark Brooker • Brian Chambers • David Cocking • Pat Collins • Rob Dallimer • Joe Duxbury

• Martin Fear • John Gammage • Andy Hatch • Phil Hearn • Perry Hill • Tom Hill • Kamal Jardaneh • Nic Jepson • Arnis Judzis • Daryl Kellingray • Charlie Leslie • Yuejin Luo

• John Martin • Mike McLean • Rune Olsen • Steve Parfitt • Mike Payne • John Pucknell • Marcus Summers • John Thorogood • Allan Twynam • Curtis Weddle • Hugh Williamson • Larry Wolfson

Section 2

ERD Operations and Achievements

In this Section...

• Definitions of ERD • Critical Technologies for ERD • Overview of ERD Applications • Examples of ERD Costs and Performance • The ERD Learning Curve

DEFINITIONS OF ERD

Figure 1 shows current ERD achievements by the industry in terms of TVD and well departure. Also shown are lines which normalize the wells based on Reach/TVD ratios. Given such information, definitions of ERD can be considered from a number of perspectives. A global definition of ERD can be based on the state-of-the-art. As shown, state-of-the-art ERD can be defined in terms of Reach/TVD ratios of 5-to-1 and departures of 8km or 26,000 feet. This definition of ERD quantifies absolute capabilities and promotes consideration of ERD applications which might otherwise be ignored. The state-of-the-art ERD definition will remain dynamic and should be updated as operators expand the ERD envelope.

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2

Focusing purely on the state-of-the-art, however, can be distorting and has potentially serious disadvantages. ERD wells drilled in specific fields and with specific rigs, equipment, personnel, project teams, etc. do not necessarily imply what may be readily achieved in other areas. Because of the myriad of variables which control drilling mechanics and performance, local ERD definitions should be developed in terms of the extent of experience within specific fields and with specific rigs. As one example aspect, the feasibility of ERD wells is inherently tied to the ability to manage wellbore stability. This topic alone is impacted by local geology, in-situ formation stresses, possible tectonic influences, shale reactivity, proposed well inclinations and azimuthal orientations, etc. The primary means of managing wellbore stability via mud weight, mud chemistry, casing points, etc. are likewise impacted by considerations such as loss circulation zones, permeable zones which may cause differential sticking, environmental constraints affecting mud selection and cuttings disposal, and regulatory requirements and production objectives which constrain hole/casing programs.

Standard Technology Advanced Technology

Industry Extended Reach Wells

Departure, m

0

1000

2000

3000

4000

5000

6000

7000

0 1000 2000 3000 4000 5000 6000 7000 8000

Wytch Farm

Other BP

Other Operators

Dep / TVD = 3

Dep / TVD = 2

Dep / TVD = 1

Wytch Farm M3

Statoil C2 Amoco T12

Ula

ClydeMiller

A'jackNiakuk N.Hydro C26

Pompano

Figure 2-1. ERD - Industry Achievements

The implication of these issues is that ERD should be defined in terms of local operating experience and capabilities. Areas where operating experience has been captured and accumulated will have different definitions for ERD than an area where a high departure well is being considered for the first time. Assets should recognize limitations of prior experience and candidate rigs. Assets should also recognize the investment of engineering and capital upgrades which may be required prior to embarking on an ERD objective. In this sense, ERD should be defined as any drilling that substantially extends local experience. While these guidelines are intended to accelerate the transfer of ERD technology to all operating areas, there is simply no whole substitute for direct experience.

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An attempt to define feasible ERD targets with conventional drilling equipment is also shown in Figure 1 via the envelope labeled “Standard Technology”. This definition implies conventional drilling equipment such as 5 inch drillpipe, two (2) mud pumps, a standard (30,000 ft-lb) top-drive, 3,000 - 4,000 rig horsepower, water-based drilling fluids, etc. Outside of the “Standard Technology” envelope (i.e. in the “Advanced Technology” region), one or more upgrades will likely be required. Such upgrades could include 5-1/2 inch and/or 6-5/8 inch drillpipe, three (3) mud pumps, enhanced solids control, a high-capacity (45,000 ft-lb) top-drive, more generated power, oil-based drilling fluids, etc.

Each upgrade must be evaluated technically based on local constraints as identified by prior and ongoing drilling experience. Alternative means of alleviating constraints should also be considered. An example is Statoil’s drilling of then world-record Well C2 with only two (2) mud pumps. While a third pump would have provided clear advantages for that well, fitting the pump on the platform was not achievable cost effectively. As a result, Statoil planned the well and managed the operation within the constraint of two pumps and used a backreaming program to improve hole cleaning which was flow-rate limited in some hole sections. Thus, clearly establishing ERD feasibility with conventional and enhanced equipment is not simple and assessment of upgrades must be performed on a focused, case-by-case basis.

In summary, state-of-the-art definition of ERD is crucial in assessing what may be achievable. Such ERD definitions like 5-to-1 ratios and 8 km (26,000 feet) departures should be publicized. Awareness of these capabilities is critical, particularly where it can impact development planning on major projects. However, equal emphasis must be placed on local ERD experience and rig capability. Extending local capability towards the industry’s ever increasing state-of-the-art will require careful attention to the technical and operational considerations conveyed in these guidelines. Thus, local definition of ERD by recognition of experience limits is critical. In brief, if a proposed well involves a higher departure than prior experience, it is an ERD well regardless of absolute departure, Reach/TVD ratio, or other measure.

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OVERVIEW OF ERD APPLICATIONS

ERD has primarily been used to access reserves from existing offshore platforms. In some cases, high departure ERD wells have been part of the initial development plan for offshore platforms. Examples include platform installations near shipping lanes where high departure wells are required for reservoir access (UK, GOM, Australia) and platform installations on outer shelf transitions where deep water constraints forced a large offset between the platform and the reservoir boundary (GOM). However, the most common ERD applications have been conceived after initial developments have been installed. These cases involve reservoir development from existing platforms where ERD has been chosen over other options for secondary platforms or subsea development. This application typifies most of the current ERD operations including:

• Statoil, Norsk Hydro, and BP in the Norwegian sector of the North Sea, • Amoco, BP, Shell, Mobil and others in the UK sector of the North Sea, • BP, Shell, Exxon, Mobil, ARCO, Forest and others in the GOM, and • Unocal offshore California.

A further class of ERD application is the development of offshore reserves from onshore facilities. Wytch Farm, where ERD was used to avoid the construction of an artificial island for drilling, is a leading example. In Alaska, BP and ARCO have also used high departure drilling to access reserves in a number of North Slope fields which extend off the northern coast. More aggressive ERD operations are now being initiated in Alaska and will be critical to the future development of several reservoirs. Further applications of this nature are also pending, most notably Mobil’s plan to develop reserves offshore California from an onshore drillsite.

With the advancement of ERD capabilities, integration of ERD considerations in development planning is increasing. This will lead to better optimization of development schemes through the minimization of offshore facilities and the optimization of their location. Benefits can be achieved in this regard for both fixed structures and subsea developments. The West of Shetland developments are examples where ERD capabilities are being considered for the optimization of the subsea infrastructure.

ERD is not cost effective for all developments. Many offshore operations in shallow and benign environments have low facility costs. Examples include shallow water regions in the GOM and SE Asia (Indonesia, Malaysia, Thailand, etc.). In such areas, low-cost offshore structures such as “Minimum-Area” platforms and tripods can be installed and conventional directional wells drilled more economically than ERD development. These economic assessments obviously depend, however, on costs and risks assumed for ERD. Accurate and timely tracking of ERD technologies and operations is thus required to ensure these development decisions are sound.

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A final ERD aspect warranting discussion is the link between ERD and horizontal drilling. Horizontal wells are now commonplace and can offer advantages in terms of enhanced rates, increased reserve access, increased fracture exposure, lower sandface drawdown, reduced water/gas coning, etc. Despite these advantages and the popular application of horizontal drilling, many horizontal drilling operations are still terminated (or planned too conservatively) because of real or perceived drilling limitations. Recognition of the technological link between ERD and horizontal drilling mechanics has the potential to enable new classes of horizontal wells. Such techniques have notably been applied by Maersk offshore Qatar in two wells which exposed 10,000 feet and 12,500 feet of 8-1/2 inch reservoir section, respectively. Like departure capabilities, the ability to drill massive reservoir sections must be publicized and integrated into reservoir development planning. ERD mechanics should thus be viewed as enabling both Extended-Reach Drilling and Extended Reservoir Drilling.

CRITICAL TECHNOLOGIES FOR ERD

Another typical question concerning ERD is what technologies differentiate ERD from the engineering of conventional wells. Many wells are planned and executed using rules of thumb developed from prior experience. When these extrapolations become critical and what are the most important new technologies to consider are frequently raised issues. As with the local definition of ERD discussed above, the critical technologies for extrapolating prior experience will be dependent on local drilling conditions, procedures and equipment. As examples, wellbore stability can be the pivotal issue in some areas such as Columbia. Likewise in terms of equipment, some “conventional” rigs may already have high-torque top-drives or means of easily expanding available power, etc. Thus, the critical technical issues that may need attention again require local assessment. These guidelines provide useful information and all planning and operational issues which should be reviewed. As a brief checklist, critical issues that should be reviewed whenever a substantial ERD extension is being considered relative to prior experience include:

• Wellbore Stability (Planning and monitoring) , • Drilling Fluid optimization (Rheological optimization for hole cleaning, lubricity evaluation, etc.), • Survey planning and accuracy limitations, • Rig equipment selection (Top-drive, mud pumps, power), • Drill string design (High-torque tool joints, High-friction dope, Elevated make-up torques, Chromium

Hardfacings), • Torque reduction measures (Cased-Hole and Open-Hole), • Hole Cleaning (Rate, Rheology, Rotation, Special bladed drill pipe, Sweeps), • Directional Drilling Tools (Steerable motors, Variable gauge stabilizers, MWD/LWD, drilling

mechanics subs, near-bit surveying, geosteering systems, double or extended power section PDMs), • Dynamics Mitigation (Rotary Feedback, Dynamic mudlogging, MWD Accelerometers), • Drilling Optimization (Trajectory Design, Bit/BHA Optimization), • Casing Design and enhanced running procedures, • Liner Design, Running, Rotation (High-torque connections, upgraded liner hanger and running tools, • Cementing • Completion and Workover Operations (Wireline limitations, Coil-tubing techniques)

Each of these areas and others are covered in this guideline document.

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EXAMPLES OF ERD COSTS AND PERFORMANCE

Well abstracts are presented for a number of industry ERD wells in the following pages. These wells represent operations from several distinct areas and types of operations. The data thus reflects a variety of different drilling conditions and operational cost structures. The data is useful however for a variety of purposes and the abstracts represent the best available collection of detailed information on actual industry ERD operations.

The ERD well costs vary widely as a result of the different operations represented. The Norwegian offshore operations report total well cost in the range of $595 to $884/ft (1260 to 1870 UK£/m). The UK offshore operations are believed to have cost in the range of $730/ft (1540 UK£/m) for drilling and $976/ft (2065 UK£/m) total. UK onshore operations report total well cost in the range of $311 to $570/ft (660 to 1200 UK£/m). US GOM operations report total well cost in the range of $310 to $365/ft (656 to 770 UK£/m).

Similarly, ERD well timings vary as well. The Norwegian offshore operations report total well durations according to progress rates of 213 to 377 ft/day (65 to 115 m/day). The UK onshore operations report timing of 258 ft/day (79 m/day). The UK onshore operations report timing of 187 to 360 ft/day (57 to 110 m/day). US GOM operations report timing of 296 to 345 ft/day (90 to 105 m/day).

The cost and timing data is acknowledged to be complex and affected by many factors which make direct application to local ERD planning difficult. Although also affected by operational specifics, percent of trouble time is a somewhat more transferable parameter to consider for local ERD well evaluations. In this regard, total trouble time has been reported as high as 24%, 38%, and 27% respectively for UK offshore, UK onshore and Norwegian offshore operations. Directly following timing considerations, total well costs in the range of 40% over AFEs have been incurred. In terms of optimal performance, total trouble time has been reported much lower in areas where significant ERD learning has been possible due to sustained operations. Total trouble times as low as 9% and 13% are reported respectively for the Norwegian offshore and UK onshore operations.

Although quantitative for the specific operations cited, these cost, time and trouble data are clearly qualitative indicators of the range of costs and risks assumed when an ERD operation is undertaken. The reader is strongly encouraged to study the various well abstracts provided to gain a sense of the issues and risks that should be considered and the type of unexpected problems which may occur. All of the operations cited have been conducted by responsible operators with significant engineering planning being invested prior to the operation. Nevertheless, unexpected conditions and events occur with various trouble time events being incurred. These considerations imply that risk-weighted AFE estimates for ERD operations should be used, particularly for early or one-off ERD operations.

2-6

THE ERD LEARNING CURVE

As indicated above, operations such as Statoil and BP Wytch Farm where ERD operations are sustained over a period of time allow significant progress in terms of a learning curve. If ERD projects are being considered which will involve multiple-well programs, this learning curve should be recognized and integrated into the project cost estimates. Documentation of the learning curve based on Wytch Farm experience is shown in Figures 2 through 5. These figures demonstrate substantial increases in terms of drilling performance. These performance improvements were also accompanied by a remarkable extension of ERD achievement. ERD wells were drilled more and more successfully while simultaneously achieving higher and higher departure objectives. Time-based performance at Wytch Farm effectively doubled from 57 m/day to 110 m/day. Similarly, trouble time at Wytch Farm was reduced dramatically from a high of 38% to a low of 13%. These performance improvements were achieved while departure was increased in subsequent wells. The 3.8 km departure of the first Stage III well, F18, was eventually more than doubled to the 8.0 km departure of Well M5. This type of learning progress should be recognized and accounted for in major multi-well ERD achievements.

TIME vs DEPTH PLOT

0500

10001500200025003000350040004500500055006000650070007500800085009000

0 10 20 30 40 50 60 70 80 90 100 110 120 130 140

Dep

th, m

BR

T

M5 ActualM3 ActualM2 ActualM1 ActualF21 ActualF20 ActualF19 ActualF18 Actual

Days from Spud

WYTCH FARM DRILLING PERFORMANCE

Figure 2-2. Time vs. Depth Plot

2-7

8

F18 F19 F20 F21 M1 M2 M3 M50

50

100

150

200

250

m/day

F18 F19 F20 F21 M1 M2 M3 M5

AVERAGE METRES PER DAY

24" Section17.1/2" Section12.1/4" Section8.1/2" Section


Figure 2-3. Average Metres per Day

F18 F19 F20 F21 M1 M2 M3 M50

500

1000

1500

2000

2500

$/m

F18 F19 F20 F21 M1 M2 M3 M5

STAGE III PERFORMANCECOST PER METRE

To 9-5/8" CasingReservoir

Completed W ell

Figure 2-4. Cost Per Metre

2-8

F18 F19 F20 F21 M1 M2 M3 M50%5%

10%15%20%25%30%35%40%45%50%

F18 F19 F20 F21 M1 M2 M3 M5

PERCENT NON-PRODUCTIVE TIME

24" Section17.1/2" Section12.1/4" Section8.1/2" Section


Figure 2-5. Percent Non-Productive Time

One intent of this document is to accelerate transfer of technology into ERD operations including the initial well, if possible. Thus, future multi-well ERD projects may begin “higher” on the learning curve and hence exhibit less dramatic advances than Wytch Farm. However, due to the many factors which depend on local conditions, a significant learning potential should exist in all major projects. Similar learning achievements occurred in the Statoil ERD operations, however data for quantifying those advances are not fully available.

2-9

10

Detailed discussion of learning curves is beyond the scope of this document. The key issues are that “unexpected” events should be expected on early ERD wells, but the learning curve must be recognized and integrated into large ERD project planning. Mechanisms for achieving the learning should also be considered in terms of project management and impact on staffing, budgeting, etc. Active updating of guidelines such as these is important, but other mechanisms will be even more critical. Some of these include:

• Multi-Discipline Project teams comprised by Multi-Company Representation (Operator, Service, Product),

• Formal lessons learned meetings (Field and office staff) with documentation and follow-up on all actions,

• Continuity of all personnel to the fullest extent possible, • Goal Setting and use of focused Incentive programs to motivate achieving the goals, • Close interaction between office and field personnel, • Access to specialized technical resources within Sunbury, Aberdeen and other Asset areas, • Access to industry service and product sector, • Willingness to test new technologies and procedures, etc.

ERD wells can be tough, and communication boundaries or mixed objectives are the last things you need in the way of a good operation. Advanced technology is powerful, but it takes good management of people and communication to make it work in practice.

2-10

INDEX OF ABSTRACTS

The reader is strongly encouraged to study the well abstracts in this document to get a sense of the highpoints and lowpoints of key ERD wells in the industry to date. References to more detailed information on the wells is indicated in the abstract where such papers exist. These abstracts will be updated on an ongoing basis.

Contents as of Feb-96

Contents as of Feb-96 Operator Area Field Well TD Date

Amoco UK N. Sea Everest 22/10a - T12Z Dec-93 Unocal Corp. US Offshore Point Pedernales Platform Irene BP UK Onshore Wytch Farm F18 BP UK Onshore Wytch Farm F19 BP UK Onshore Wytch Farm F20 BP UK Onshore Wytch Farm F21 BP UK Onshore Wytch Farm M2 BP UK Onshore Wytch Farm M3 BP UK Onshore Wytch Farm M5 BP Gulf of Mexico Pompano MC 108 A13 BP Gulf of Mexico Amberjack MC 108 A27 Forest Oil Gulf of Mexico Eugene Island El 326 A6 Norsk Hydro Norway N. Sea Oseberg C-26A Statoil Norway N. Sea Statfjord C02 Statoil Norway N. Sea Gullfaks 34/10 - B29 Statoil Norway N. Sea Statfjord B42

2-11

Amoco UK 22/10A-T12Z South Everest Extended Reach (SEER) Well Summary

Introduction

The SEER well was drilled to achieve two main objectives:

• Early production from the South Everest Field would minimize the loss of reserves into an aquifier common to the North and South Everest Fields.

• The gas production from T12 would allow future development (subsea facilities or a second platform) to be deferred by two years or more.

The well profile required a sail angle of 76 degrees to a measured depth of approximately 25400 feet MD. The risks associated with drilling such a long (UK and Amoco records), high inclination well, through highly reactive shales reduced the possibility of successfully drilling and completing this well to 50%.

Goals

The well objectives were to:

• Penetrate the Forties Sandstone of the South Everest field • Complete the well for immediate production.

Results

The well was spudded by the Santa Fe Magellan (Monarch Mod V giant jack up) on the 23rd of July, 1993 and reached a total measured depth of 24670 feet (20966 feet departure) on the 24th of December, 1993. During this time, T12 was suspended from the 4th of August to the 30th of September to allow remedial work to be carried out on the existing North Everest wellheads. The original T12 wellbore was sidetracked (becoming T12Z) to TD in 8-1/2 inch hole on the 18th of December after the drillstring became stuck in a ledge at 24076 feet. Once completed and on production tests have shown rates of 59mmscfd and 3500bpd of condensate. Total unscheduled events for the well were 23.8% of which 51% were due to the stuck pipe and sidetrack.

Discussion & Conclusions

A number of notable achievements contributed to the successful completion of this well which is currently the longest extended reach well in the UK sector of the North Sea. These include:

• An inner string cement job on the 13-3/8 inch casing at 12000 feet. • A 10,000 foot 9-5/8 inch liner run and cemented through inclinations of up to 82 degrees with no problems. • A successful data download of an LWD at 23955 feet, and subsequent pulling of the nuclear source from this

depth using wireline retrieval tools. • Successful rotation (30rpm) of the 5-1/2 inch liner set between 21634 feet and 24670 feet. • World record for logging and for perforating on coiled tubing. Perforation interval was 23777 feet to 23548 feet. Problem areas included:

• Losses of 1100bbl of mud on the 13-3/8 inch cement job. This has been a recurring problem on Everest. Further studies will be required for future wells.

• BHA performance in the 8-1/2 inch section was unexpectedly difficult to control, mainly due to the high inclination in combination with formation dip.

• Stuck pipe in 8-1/2 inch section due to backreaming into a ledge. With pipe stationary differential sticking quickly exacerbated the situation. Mud wt. required for section was revised and successfully lowered 1.5ppg.

Amoco -Everest 22/10a-T12z - Page 1 of 2

• The coiled tubing logging program was shortened for two reasons. Firstly damage to a number of the conductors in the reel during manufacture and assembly reduced the capacity for power transmission and log telemetry. Secondly the extreme depth of the well, combined with the high angle and a “hump” in the well between 21800 feet and 22700 feet (angle increased from 76 to 81 degrees) caused severe problems running the coil to bottom.

The success of the SEER well has significantly contributed to the Everest Field performance while pushing back the boundaries of what was considered possible in this area. By doing so it should open up other development opportunities to Amoco UK.

Tertiary

Balder

Sele

Forties SST

Forties Shale

20000

16000

0 20 40 60 80 100 120 140

PLAN

ACTUAL

24000

TIME (Days)

12000

8000

4000

0DEPTH (FT 000'S)

DAYS vs DEPTH

SAFTEY & ENVIRONMENT

LTA: 0NEAR MISSES: 0COMMENTS: NONE

ENVIRONMENTAL IMPACT:

SYNTHETIC OIL-BASED-MUDWAS USED AS THE DRILLINGFLUID.

TOTAL TIME

TRIPS 14%

CIRC & COND 4%

DIRECTIONAL 1%WASH & REAM 1%DRLG CEMENT 1%

RUN CASING 11%

CEMENTING & WOCS 3%

TEST BOP/CSG/LOT 1%MISC 9% OTHER 2%

LOGGING/PERF 8%

NIPPLE BOPs 1%

RUNNING TUBING 2%

UNSCHEDULEDEVENTS 24%

DRILLING 15%

UNSCHEDULED EVENTSBREAKDOWN

STUCK PIPE 51%

CASING PROBS 2%

RIG REPAIR 9% DIRECTIONAL PROBS 9%

EVAL EQUIP FAILURE 14%

MISC 2%

HOLE PROBS/REAMING 9%

CEMENT PROBS 1%

WEATHER 3%

WORKING INTREST

AMOCO: 21.14 %BRITISH GAS 57.79 %AMERADA 18.67%PHILLIPS: 1.01 %

AGIP: 0.52 %FINA: 0.87 %

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Amoco -Everest 22/10a-T12z - Page 2 of 2

Unocal Corp. Platform Irene, Point Pedernales, CA

General Project Background

• Platform located 4.5 miles offshore California in 242 feet of water • Reservoir is vertically fractured and laminated chert, dolomite, and shale • TVD = 3870 feet (1180 m) • Target HD = 11,475 feet (3498 m) from existing platform • HD/TVD ratio of 2.96:1 • ERD project objectives:

− Eliminate high capital cost of 2nd offshore structure. − Intersect more vertical fractures and gain more formation exposure with high angle wells. − Prove that a negative weight well could be drilled economically.

Directional

• Rather complicated double build-hold-build-hold trajectory • Build rates of 4.5°/100 feet to 65° and then 0.51°/100 feet to 79° • Hold tangent angle of 79° to the reservoir and then build at 3.0°/100 feet to 85.5° • Hold 85.5° tangent angle through the reservoir target followed by gentle drop to TD • Steerable PDM assembly experienced trouble sliding and was rotated most of the time • Rotary BHA planning with 2D program was not successful • No HWDP or drill collars in the low angle hole section to add available WOB for 17-1/2 inch hole but 2500 feet of

HWDP used for 12-1/4 inch hold

0

1000

2000

3000

4000

50002000 6000 10000 12000

HORIZONTAL DISPLACEMENT, FT

VE

RT

ICA

L D

EP

TH

, F

T

0 80004000

ACTUAL

PLAN

Casing Program

• Friction factors for casing included planning for a range of 0.30 - 0.80 • Casing flotation device was used to run the 9-5/8 inch casing to bottom • Special liner running tool for 7 inch liner and high torque liner connections • Liner was rotated at 8- rpm and run in the hole at 100-300 ft/hr • Standoff bands were run on 9-5/8 inch casing and 7 inch liner

Unocal Corp. - Point Pedernales, Platform Irene - Page 1 of 2

Mud System

• Seawater/gel/sepiolite system for the 17-1/2 inch surface hole. High seawater dilution degraded rheology but with no apparent hold cleaning problems as a result (72° inclination).

• Seawater/gel/polymer system for the 12-1/4 inch intermediate hole with lubricant additions. Flow rate of 600 gpm and AV of 120 fpm required seawater/high viscosity tandem sweeps

• Same mud for 8-1/2 inch hole through reservoir as used for 12-1/4 inch hold. High dilution as a result of losses degraded rheology and required sweeps

• Best sweep rheology seemed to be with Fann 3 rpm reading of 50-100.

0

2000

4000

6000

8000

20000 40000 60000 80000 100000 1200000

ME

AS

UR

ED

DE

PT

H, F

T

INDICATOR WEIGHT, LBS

ACTUAL WELL PATH

BLOCK WEIGHT

INSIDE CASING FF = .33

13-3/8"CSG @ 5047'

OPEN HOLE FF = .60

ACTUAL WEIGHTS

BUOYANCY ASSISTED

NORMAL RUN

Drilling Equipment

• Large top drive on the rig with 26,500 ft-lb of continuous torque output.

DRILL PIPE

BUMPER SUB

HYDRAULIC RELEASING TOOLRUNNING HEAD

TIE-BACK SLEEVE

SAFTEY JOINT

INFLATABLE PACKER

DRAG RING

7" LINER

LANDING COLLARFLOAT COLLAR

FLOAT SHOE

Unocal Corp. - Point Pedernales, Platform Irene - Page 2 of 2

British Petroleum Wytch Farm F18


• Difficulty building at a fast enough rate in the initial build section. Problem was due to poor correlation of BHA performance compared to previous wells

• Severe Gumbo problems required refining of mud properties

• Insufficient mud weight led to hole instability and an inability to run the 9-5/8 inch to bottom. The string was pulled and 11 bow centralizers were left downhole. The subsequent clean-out BHA was lost downhole when an out of spec. Be/Cu MWD sub failed. Fish was left in hole and casing run past it.

Wytch Farm 1F-18SP (Cost vs depth)

0

500

1000

1500

2000

2500

3000

3500

4000

45000 800M 1.6MM 2.4MM 3.2MM 4.0MM 4.8MM 5.6MM 6.4MM 7.2MM 8.0MM

Cost (US$)

Actual Depth (m)

Wytch Farm 1F-18SP (Time vs Depth)

0

500

1000

1500

2000

2500

3000

3500

4000

45000 10 20 30 40 50 60 70 80 90 10

Time (Days)

Actual Depth(m)

0

• Steering problems in 8-1/2 inch hole section eliminated when used tri-cone instead of PDC bit.

• Successfully ran 2 ECPs in liner.

BP - Wytch Farm, F18 - Page 1 of 1



• Mud & BHA programs re-designed and top-hole problems eliminated.

• Serious wellbore instability in the 12-1/4 inch section resulted in a twist-off at the jar while backreaming. Jar metallurgy was out of specification. Sidetracked without problems after raising mud weight and changing water-phase salinity.

• Motor backed off in 8-1/2 inch section requiring a second sidetrack. Problem with motor backing off later found to be due to vibration.

• Ran 2 ECPs on liner but neither inflated

• 9-5/8 inch casing leaked during completion operations. This was due to tungsten carbide hardbanding on the rental drillstring.

Wytch Farm 1F-19SP (Cost vs Depth)

0

1000

2000

3000

4000

5000

6000$0 $1,600,000 $3,200,000$4,800,000 $6,400,000$9,600,000 $9,600,000$11,200,000

Cost (US$)

Actual Depth (m)


0

1000

2000

3000

4000

5000

60000 20 40 60 80 100 120 140 160

Time (Days)

Actual Depth(m)

• 9-5/8 inch casing leaked

during completion operations. This was due to tungsten carbide hardbanding on the rental drillstring.

• World record departure at that TVD of 5001m.

BP - Wytch Farm, F19 - Page 1 of 1



• A successful well in terms of drilling, with the worst incident being 92 hours lost due to coil tubing hanging up while running the CBL

• Geosteered in reservoir section • Third successful liner job confirmed by CBL


0

1000

2000

3000

4000

5000

60000 800000 1600000 2400000 3200000 4000000 4800000 5600000

Cost (US$)

Actual Depth (m)


0

1000

2000

3000

4000

5000

60000 10 20 30 40 50 60 70 80 9

Time (Days)

Actual Depth(m)

0

BP - Wytch Farm, F 20 - Page 1 of 1



• Began getting problems sliding in 12-1/4 inch section due to increasing departures • Longest 12-1/4 inch bit run at 3421m • Another motor back-off in the 8-1/2 inch section required a sidetrack. No attempt made to fish the motor rotor

after the fruitless attempts on F19. Again cause of back-off was vibration. • World record departure at that TVD of 5454m • World record wireline wet connect for RFT at 5209m


0

1000

2000

3000

4000

5000

6000


Cost (US$)

Actual Depth (m)


0

1000

2000

3000

4000

5000

6000

70000 10 20 30 40 50 60 70 80 90 10

Time (Days)

Actual Depth(m)

0

BP - Wytch Farm, F21 -Page 1 of 1

British Petroleum Wytch Farm M2


• Geosteered 1750m in reservoir section

• First utilization of Halliburton VGS in conjunction with Anadrill Geosteering Tool (with inclination & resistivity at the bit)

• High reservoir ECD's led to high mud losses. The addition of LCM to the mud system led to the discovery of its torque reducing capability.

• World record departure of 6760m

• Deepest RFT data point at 7400m

• Liner cement set early due to cement quality problems. 5000m of DP was cemented, resulting in 153 hours of lost time. The liner was perforated without cement.

Wytch Farm 1M-02SP (Cost vs Depth)

0

1000

2000

3000

4000

5000

6000

7000

80000 1600000 3200000 4800000 6400000 8000000 9600000

Cost (US$)

Actual Depth (m)

Wytch Farm 1M-02SP (Time vs Depth)

0

1000

2000

3000

4000

5000

6000

7000

80000 20 40 60 80 100

Time (Days)

Actual Depth(m)

120

• World record length 1650m TCP gun

• Critical operations now considered to be drag related; - sliding drilling - running 9-5/8 inch - running TCP guns - coil tubing operations

BP - Wytch Farm, M2 - Page 1 of 1



• Only 13% lost time throughout well • Full flotation tried when running 9-5/8 inch. Technique showed no clear advantage over normal running. Partial

flotation probably optimal • World record departure at that TVD of 6818m • Geosteered all of 2100m reservoir section • Only perforated toe of reservoir section

Wytch Farm 1M-03SP (Cost vs Depth)

0

1000

2000

3000

4000

5000

6000

7000


Cost (US$)

Actual Depth (m)


0

1000

2000

3000

4000

5000

6000

7000

80000 10 20 30 40 50 60 70 80 90 10

Time (Days)

Actual Depth(m)

0




• Used extended power section motor in 12-1/4 inch hole with a substantial improvement in slideability and ROP • World record bit run of 4014m (12-1/4 inch PDC) • Geosteered all of 2700m reservoir section with high ECD's and high losses • World record departure of 8035m • High drag prevented RFT's getting to bottom • Fully rotated liner with very low torque during cementing. Confirmed benefit of solid zinc alloy centralizers • Only perforated toe of reservoir section • Ran 'Formation Saver Valve' to isolate reservoir during workovers. Prevents losses to reservoir when ESP's shut

down.

Wytch Farm 1M-05SP (Cost vs depth)

0

1000

2000

3000

4000

5000

6000

7000

8000

90000 1600000 3200000 4800000 6400000 8000000 9600000 1120000 1280000

Cost (US$)

Actual Depth (m)


0

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2000

3000

4000

5000

6000

7000

8000

90000 20 40 60 80 100 120 140

Time (Days)

Actual Depth(m)


Pompano Abstract

Background

• Well--A-13 • Rig--H & P 100 • Water depth--1290 ft. • KB Elevation--142.5 • Drill Pipe--6-5/8 inch and 5-1/2 inch

Casing Program

Casing Set Depth

(tvd/md) Top Depth (tvd/md)

Pilot Hole Hole Size Fluid

26” 1866’/1872’ Surface N/A Driven N/A

20” 3311’/3576’ Surface 17-1/2” 24” SW/Sweeps

16” 5007’/11851’ Surface 14-3/4” 20” Waterbased

13-3/8” 6890’/11851’ Surface 14-3/4” 17-1/2” Waterbased

9-5/8” 9850’/18000’ 11325’ N/A 12-1/4” Petrofree

7” 10299’/19850’’ 15350’ N/A 8-1/2” Petrofree

Drilling Lessons Learned

• A high KOP (building angle at 3-1/2°/100’ directly below 26 inch csg) was used on the A-13 the avoid the hole stability problems experienced on the A-8. No stability problems were experienced on the A-13. Future ERD wells will use similar trajectories.

• Severe gumbo problems were experienced in the 14-3/4 inch pilot hole sections. 12-1/4 inch pilot hole should be used in the future.

• Because the P38 did not cause any drilling problems, future casing programs will be optimized. On the next ERD well (A-11), the 16 inch casing will be replaced by 13-3/8 inch and the casing string below the P-38 will be eliminated. This will reduce costs by eliminating 2 underreaming sections and a string of pipe. The 5-string design will remain an option for higher step-out wells.

• The 13-3/8 inch wellhead was not designed for the proper 5000 psi pressure rating. Field personnel expressed a lack of confidence in Vetco’s people. A full wellhead stackup will be conducted to better familiarize BP and Vetco personnel with the wellhead system.

• Lost returns prior to cementing the 13-3/8 inch required building a large volume of mud quickly to displace the cement. Future plans should consider displacing the cement plugs with water, keeping liquid mud available on a boat, or using a stab-in cement job.

• Pumping at high flowrates, backreamming after sliding, monitoring surface torque, and using Petrofree eliminated the hole cleaning problems experienced on the A-8.

BP - Pompano, MC 108 A13 - Page 1 of 2

POMPANO A-13 TROUBLE BREAKDOWN

WEATHER 29%BOP 18%

CEMENTING 16%

OTHER HOLE PROBLEM 11%FISHING 11%FLUIDS 6%

MISC 9%

A-13 Cost vs. Depth

0

3000

6000

9000

12000

15000

18000

210000 1000 2000 3000 4000 5000 6000 7000 8000

Cost ($M)

Depth (md)

Squeeze 16" Shoe

Wellhead

Hurricane

Float Equipment

A-13 Days vs. Depth

0

3000

6000

9000

12000

15000

18000

210000 5 10 15 20 25 30 35 40 45 50 55 60 65 70 75

Days

Depth (md)

Squeeze 16" Shoe

Wellhead

Hurricane

Float Equipment

BP - Pompano, MC 108 A13 - Page 2 of 2

Amberjack Abstract

Background

• Well--A-27 • Rig--H & P 100 • Water depth--1030 feet • KB Elevation--142.5 • Drill Pipe--5/1/2”

Casing Program

Casing Set Depth (TVD/MD)

Top Depth (TVD/MD) Pilot Hole Hole Size Fluid

26” 1620’ Surface N/A Driven N/A

20” 3200’/3550’ Surface 12-1/4” 22” SW/Sweeps

13-3/8” 5800’/9750’ Surface 12-1/4” 17-1/2” Waterbased

9-5/8” 8000’/15,825’ Surface N/A 12-1/4” Petrofree

7” 9399’/18,480’ 15350’ N/A 8-1/2” Petrofree

Drilling Lessons Learned

• In order to reduce DLS the conductor hole a 12-/14 inch pilot hole was drilled, opened to 17-1/2 inch then opened again to 22 inches. This was not required. Future well will begin with 17-1/2 inch then open to 22 inches

• An attempt was made to drill 17-1/2 inch hole section below 20 inch casing. Result was massive gumbo attacks. BHA was pulled, a 12-1/4 inch pilot hole was drilled, and opened to 17-1/2 inch. Unless the rig is upgraded with respect to pump capacity, a 12-1/4 inch hole will be drilled then opened to 17-1/2 inch.

• Water based drilling fluid was displaced to Petrofree at 13-3/8 inch shoe. 12-1/4 inch hole section was drilled and TD’d without problem.

• In order to reduce the amount of Petrofree left in the 9-5/8 x 13-3/8 inch a sized salt spacer (fluid in stock) was used to fill the annular volume. Problems occurred, the fluids swapped, and the complete Petrofree volume was lost. On future wells, either a 9-5/8 inch liner will be run and tied back or a different spacer will be used. Spacers will be evaluated prior to future jobs.

• An 8-1/2 inch hole was drilled to TD, and a 7 inch liner was run and cemented in place. The liner was reciprocated for 11 hrs while conditioning the wellbore. Additional time was spent circulating prior to cementing due to high viscosity of the cold Petrofree fluid. On future wells, circulation will be broken while TIH at various depths and full circulation will be made prior to entering the open hole.

BP - Amberjack, MC 108 A27 - Page 1 of 2

MC109 A-27 TROUBLE BREAKDOWN

WELLBORE INSTABILITY 35%

BOP/WELLHEAD 12%

MISC 15% FISHING 12%

LOST CIRCULATION 27%

Mississippi Canyon 108 A-27

FINAL DAYS 56.5

02000400060008000

100001200014000160001800020000

0 5 10 15 20 25 30 35 40 45 50 55 60Days

Depth

Days vs Depth

AFE 45 DAYS 30.7 DAYS/10,000WATER DEPTH 1030'

Mississippi Canyon 108 A-27

0

5000

10000

15000

200000 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000Cost

Depth

Cost vs Depth

FINAL COST $5,571,280AFE $4,539,000 COST/FT $307.8

BP - Amberjack, MC 108 A27 - Page 2 of 2

Forest Oil Corp. Eugene Island 326 No. A-6


• Well drilled to a shallow reservoir to protect a remote lease as “held by production”.

• Reservoir TVD = 2300 feet (701 m) • Target HD = 7000 feet (2134 m) from existing

platform • MD/TVD ratio of 3.1:1 and HD/TVD ratio of

3.04:1. • ERD project evaluated versus:

1. Minimal offshore structure (MOSS) - 2X expected ERD cost

2. Subsea - same cost as ERD but problems with mechanical reliability

Directional

• Simple build and hold trajectory. • Build rate of 6°/100 feet with very shallow KOP. • Tangent angle of 77°at 1389 feet MD (423

m)/1000 feet TVD (305 m). • Hold tangent angle to TD at 7169 feet MD (2185

m)/2300 feet TVD (701 m).

Eugene Island 326 A-6

Eugene Isl., Blk. 326 Offshore, LA

ME

AS

UR

ED

DE

PT

H

DAYSACTUAL CASING PROGRAM

DEPTH VS. DAYS

0 10 20 30 40 50 608,000

7,000

6,000

5,000

4,000

3,000

2,000

1,000

0 DAYS

26"D.P.

1 2

13-3/8"1,107' T.V.D.

1. Lost Hole - 20" "NO GO"

2. Lost Hole - Hole Opener Twist Off

9-5/8"2,007' T.V.D.

7"2,176' T.V.D.

• Friction factors for drill string (seawater-polymer mud): − Planned cased hole 0.25 / open hole 0.30 − Actual cased hole 0.30 / open hole 0.37

• BHAs included a building assembly and a three holding assemblies − PDM with 3° bent sub and wireline steering tool to achieve 6°/100 foot build rate − Slick rotary BHA to hold angle was unsuccessful − Steerable PDM assembly was unable to slide below 4411 feet MD (1344 m). − Rotary assembly with stabilizers was used to hold angle to TD

• HWDP and drill collars were run in the low angle hole section to add available WOB. Casing Program

• Could not work 20 inch casing through 6°/100 ft dogleg in 26 inch conductor hole. This appears to be related to: − Stiffness of the casing and softness of the formation − Hole enlargement at the drive pipe shoe, and/or − The reduced ID of the drive shoe limiting the movement of the 20 inch casing. It was replaced with 13-3/8 inch casing, thereby changing the entire casing program.

• A full string of 7 inch casing had to be run rather than the planned liner per government requirements. • Friction factors for casing:

− Planned cased hole 0.33 / open hole 0.30, 0.40, 0.45, 0.50, 0.60 − Actual average for both cased hole and open hole 0.30 - 0.40 during running

Forest Oil - Eugene Island, El 326 A6 - Page 1 of 2

• Actual drag values for 9-5/8 inch and 7 inch casing strings while reciprocating on bottom showed negative friction factors.

• The patented selective flotation device to run the pipe to bottom.

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-12 -9 -6 -3 3 6 9 12 15 18 21 24 27 30 33 36 39

TORQUE

SELECTIVEFLOTATIONDEVICEPICKED UP

FLOATED 7" CASING

FLOATED CASINGROTATING WEIGHT

ROTATION PROBABLYNECESSARYM

EA

SU

RE

D D

EP

TH

(F

T)

TORQUE (FT/LBS)

INDICATOR WEIGHT (LBSx1000)

• Solid body centralizers added significantly to casing drag and were removed except for shoe joints.

• Standoff bands were run on remainder of 9-5/8 inch casing and 7 inch casing

Mud System • Seawater and polyacrylamide with

lubricants with high vis pills prior to casing jobs

• Flow rates comparable to vertical wells in the area.

Drilling Equipment • Platform rig was small (1000 HP

drawworks and two 1000 HP triplexes) • No top drive on the rig. A rented power

sub was used, but its overall length in a small derrick did not allow backreaming a full stand. Its use was considered uneconomical and unsatisfactory.

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FINAL B.H.L.6098.06' S-

North

12181410

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16101786

18962174

59 301 M.D.

59 301 M.D.

59 301 M.D.

59 301 M.D.

Forest Oil - Eugene Island, El 326 A6 - Page 2 of 2

Norsk Hydro C-26A in Oseberg Field, Norwegian North Sea


• Giant offshore field with multiple platform requirement. • Pressure maintenance with gas cap injection. High angle wellbores near the OWC maximize oil recovery before

gas breakthrough. • Reservoir consists of fan-delta sandstones of varying thickness and quality. • MD = 30,586 feet (9325 m) / TVD = approx. 8850 feet (2700 m) • HD = approx. 25,600 feet (7800 m) from existing platform • HD/TVD ratio of approx. 2.89:1. • ERD project objectives:

− Eliminate high capital cost of additional offshore structures. − Increase percentage recovery of reserves. − Delay gas breakthrough.

Directional

• Double build and hold trajectory. • Build rates of 1.0°/100 ft in the 22-3/4 inch hole to

about 50° and then 1.5°/100 ft in the 17-1/2 inch hole to 79°

• Hold tangent angle of 79° to the reservoir and then build to near horizontal for the reservoir.

• A DTU PDM assembly was used in the 17-1/2 inch hole providing very precise directional control.

• A 9-1/2 inch elongated power section PDM was used in the 12-1/4 inch hole to allow more aggressive PDC bit designs to be used.

• The reservoir navigator tool was used in the 8-1/2 inch hole interval providing improved directional monitoring and reduced tortuosity.

• Sliding with steerable PDM assembly was successful down to 26,500 feet.

• A SRO gyro was pumped down to 13,907 feet (4240 m) to verify MWD surveys.

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8,000

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10 20 50 70 90 110

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Mea

sure

d de

pth,

m

BudgetActual

0

22 3/4-in.

17 1/2-in.

12 1/4-in.

8 1/2-in.

Casing Program

• Critical 9-5/8 inch liner job with 2350 psi differential pressure to allow 8-1/2 hole in the reservoir. • Used 8-inch drill collars with 6-5/8 inch HWDP in 6-5/8 inch drill pipe running string to offset loss of weight in

troublesome formation. Centralizers were used over the 9-5/8 inch casing collars. • Used 6-1/2 inch drill collars with 6-5/8 inch and 5-1/2 inch HWDP plus additional 8-inch drill collars uphole in the

running string to overcome drag. Aluminum rigid body centralizers (8-inch OD) were used on the 7-inch liner.

Norsk Hydro - Oseberg C-26A - Page 1 of 2

Mud System

• Seawater/CMC system planned for the 22-3/4 inch surface hole before losses required changing to KCl/PHPA. • Pseudo OBM system for the 17-1/2 inch hole for chemical stability in the reactive shales and mud weight

increased per schedule to maintain mechanical stability. Used 6-5/8 DP, 1050-1150 gpm flow rates, and pipe rotation at 140-175 rpm for hole cleaning plus high density and high viscosity pills. Friction factor of 0.21 and 0.28 in casing and open hole.

• Pseudo OBM system for the 12-1/4 inch hole similar to the 17-1/2 inch hole with rotary friction factor of 0.17. Losses due to surge and swab pressures. Used 6-5/8 DP, 750-850 gpm flow rates, and pipe rotation at 140-175 rpm for improved hole cleaning.

• OBM mud for 8-1/2 inch hole with good mud weight window in stable reservoir sand. The 6-5/8 inch drill pipe was used above the 9-5/8 inch liner top in a tapered drill string. Flow rate was 476 gpm and the string was rotated at 100-140 rpm.

• Best sweep rheology seemed to be with high density rather than high viscosity.

0 600 1,200 1,800 2,400 3,000 3,600 4,8004,200 5,400 6,000 6,600 7,200 7,8003,000

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Vertical section, m

Sou

th

Tru

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rtic

al d

epth

, m

7-in. linerC-26

9 5/8 in. casing-7,157m

13 3/8 in. casing-4,366m

18 5/8 in. casing-1,690m

27 in. conductor-286m

East

C-26

C-26A

C-26A

TRSCSSV at 242 m

7-in. tubing

7-in., 30-ft. polished bore receptacle

Flex-lock liner hangerat 5,073 m

7-in tie back seal mandrel

SABL-3 Packerat 6,918 m

Sleeve installedat 6,980 m

Top of 7-in. linerat 7,079m 9 5/8-in. casing shoe

at 7,1577-in. liner shoeat 9,325 m

Norsk Hydro - Oseberg C-26A - Page 2 of 2

Statoil 33/09-C02 Statfjord Field - North Sea Well Summary

Introduction

The well was recommended to complete the water injection patter in Upper Brent and provide pressure support and water-flood sweep to the north of current production wells in the North Statfjord Field. Based on the reservoir simulation model the additional recovery generated by this well was quantified to 1.2 million Sm3 from Ness and Tarbert. In addition to improve recovery the well was expected to confirm and increase in Upper Brent STOOIP of 1.2 million Sm3.

Results

The well was spudded on the 28th of October, 1992 and ready for production on the 22 of March, 1993. The average inclination, MD, TVD and Horizontal reach of the well was respectively 84°, 8761m, 2788m and 7290m. The total cost of the well was $17.73 million and the total number of days used was 144.7. The drilling cost alone was $15.7 million and the number of days used on drilling was 134.1. When drilling through the reservoir an oil zone appeared in the Upper Brent. Production testing showed that the oil zone was produceable, and the well was completed as an Upper Brent oil producer. The well was after one year of production converted to the originally planned water injection well. Total unscheduled events for the well were 9.3% of which 27. 2% were due to drilling.

DAYS VS. DEPTH

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TID (Dager)

Optimaltid

AFE-tid Virkeligtid

Kompletering

26" section

17 1/2" section

12 1/4" section

8 1/2" section

Kompletering

DY

P (

mM

DR

KB

)


The well was completed in March, 1993 as the longest extended reach well in the world at that time. Other experience from the well includes:

• To achieve a well path as smooth as possible, in wells similar to C02, it is recommended to split up the steering rotation interval in small steps in the build-up section and to use a motor with a small bend.

• The ester based drilling mud is a very good alternative to oil based mud systems with respect to hole cleaning, friction factors and also compared to mud cost if cuttings injection of the oil based cuttings is a problem.

• Plan for trips to “Slip and cut” of the drill line in long open hole sections, or plan for high quality drill lines with higher ton miles.

• The procedures for pumping of Electronic Survey System, ESS, in 6-5/8 inch drillstring must be modified for use in high angle wells. This well showed the difficulty to control the ESS-tool in an approximately horizontal well with 6-5/8 inch drillstring in the bottom of the hole. This is due to a considerable larger ID in 6-5/8 inch drillstring than the diameter of the ESS-tool.

Statoil - Statfjord C02 - Page 1 of 2

• 9-5/8 inch liners is a good alternative to 9-5/8 inch

casings in long reaching wells with high ECD in the 8-1/2 inch section. It also gives the opportunity to use 5-1/2 inch drillstring above the 9-5/8 inch liner to increase the available torque.

• The modified 9-5/8 inch Sperrydrill motor with a fixed bent housing and a low bend angle was very suitable and very reliable when the rotation was up to 180 rpm in the drilling mode to improve hole cleaning.

• The procedures/frequency used for changing the annular BOP should be evaluated when using ester based mud systems. This is due to ester based mud tending to swell rubber compounds and make them wear faster.

• It was possible to steer at 8100 mMD. • It was possible to get MWD signals from 8700 mMD. • It is necessary to use low friction centralizers in long

reaching wells.


TOTAL TIME

COMPLETION 8.5%

DRILLING 27.2%

FISHING 14.0%

RIG 1.7%TESTING 4.5%

WELL CONTROL 2.4%

WORKOVER/RECOMPLETE

BOP 12.4%

CASING 23.1%

DRILLING 43.9%

COMPLETION 13.7%

CASING 20.7%

BOP 2.9%

WORKOVER/RECOMPLETE

TESTING 2.4%

UNSCHEDULED EVENTS 9.3%

3000

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-250

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20" Casing

13 3/8" Casing

9 5/8" Casing

7" Liner

WELL PATH

Plotted values are measured depthsAxis is Grid North

East

North

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Statoil - Statfjord C02 - Page 2 of 2

Statoil 34/10-B29 Gullfaks Field - North Sea Well Summary

Introduction

The well 34/10-B29, A, B, BT2 & BT3 was drilled to develop a marginal satellite field from an existing platform. The well was meant to be a oil producer in Tabert formation, both in the north an the south part of the field. The plan was to drill a well against north-east trough two shallow points in the reservoir, T1 and T2. It was important to keep distance to the OWC in the thin oil column. In order to aid evaluation of the southern section of the field, an 8-1/2 inch pilot hole (B29) was drilled from the 13-3/8 inch casing shoe. To establish structural control around T1, an 8-1/2 inch pilot hole (B29A) was drilled to optimize the 8-1/2 inch section in B-29B and verify the OWC.

Results

The well 34/10-B29BT3 was ready for production on the 11 of May 1994. The oil production is 2000 Sm3/day. The recoverable reserves is estimated to 12 million barrel oil. During the operation, 3 pilot holes was drilled to optimize the well path regarding the location in the reservoir. The 8-1/2 inch section in well B-29BT2 had to be plugged due to fish in the hole.


COMPLETION 5.8%

DRILLING 44.0%

MOVING 0.2%

RIG 0%

EVALUATION 2.4%

PLUGBACK 3.8%

SNUBBING 3.9%BOP 3.5%

CASING 9.7%

TOTAL TIME

UNSCHEDULED EVENTS 26.7%

COMPLETION 1.9%

DRILLING 74.2%

WELL CONTROL 1.4%EVALUATION 5.8%

PLUGBACK 6.6%

SNUBBING 0.2%

BOP 0.9%

CASING 5.6%

FISHING 3.4%

0

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PLANLAGT VIRKELIG REVIDERT

24" Section B29

17 1/2" Section B29

8 1/2" Section B29

12 1/4" Section B29A

8 1/2" Section B29BT2

12 1/4" Section B29B

8 1/2" Section B29A

The final well, B-29BT3 was 6710m long and turned from 235 to 50 deg and afterwards turned back to 29 deg in the lower part of the well. The measured depth/true vertical depth ratio was 3,4.

The total cost of the well was $34.05 million and the total number of days used was 181. The drilling cost alone was $30.54 million and the number of days used on drilling was 169.

Total unscheduled events for the well were 26.7% of which 74.2% were due to drilling.


Other experience from the well includes: • Successful field optimization by use of pilot hole

drilling. • Totally drilled 13,131m from same slot. • Successfully drilled a wellbore with 181o azimuth

change in horizontal plane. • Successful utilization of computer analysis for torque

and drag modeling. • Improved torque and drag analysis could have

reduced the "helicoidal buckling" problem in the 17-1/2 inch section.

Statoil - Gullfaks 34/10-B29 - Page 1 of 2

• 3510m 13-3/8 inch casing run at max. 83.4o inc. in water based mud.

• Steering/sliding of the drill string was difficult after a MD/TVD ratio>3.2:1 in the shale formation and 3.0:1 in the sand formation.

• The well was successfully drilled in the 2000m long 8 1/2 reservoir section to meet the 5 geological targets.

• 15 kg Ancho Slide/m3 mud (glass beads) was successfully used to reduce the friction.

• The B29T2 was planned for underreaming from 8-1/2 inch to 9-1/2 inch hole in the reservoir section to improve the cement job. The underreaming assembly broke in a weak x-over.

• Successful teamwork throughout the project.

WELL PATHB-29BT3 Wellpath (TD: 6,710m)B-29BT2 Wellpath (TD: 6,863m)B-29B Wellpath (TD: 5,036m)B-29A Wellpath (TD: 5,723m)B-29 Wellpath (TD: 5,580m)

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B-29BT3 TD 6,710m

B-29BT2 TD 6,863m

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T 1

T 2B-29B

B-29

True

Ver

tical

Dept

h (m

)

East (m)

North (m)

Statoil - Gullfaks 34/10-B29 - Page 2 of 2

STATOIL 33/12-B42 STATFJORD FIELD - NORTH SEA WELL SUMMARY

Introduction

The well was drilled in order to maintain high oil production on the Statfjord B platform. The well can later be converted for injection purposes in the Statfjord and the Brent reservoir after total oil production potential has been exploited. A high angle wellpath was designed in order to penetrate the Statfjord Formation, Upper and Lower Brent in the same wellbore, penetrate all Brent reservoirs from west to east to optimize recovery, penetrate the Statfjord Formation from west to east in order to have a robust target with regard to uncertainties on top reservoir and level of the water oil contact and obtain long reservoir sections to allow for long perforation intervals and high productivity.

Results

When drilling the 3098m 12-1/4” section, the well had a 110° change in azimuth at an inclination of about 80°. The well was completed with a 115m long slotted liner in October 1994. The average MD, TVD and Horizontal reach of the well was respectively 7255m, 2904m and 3214m. The total cost of the well was $11.3 million and the total number of days used was 95. The drilling cost alone was $8.46 million and the number of days used on drilling was 78. Total unscheduled events for the well were 11.1% of which 55.1% were due to drilling.


Other experience from the well includes:

• Successful use of IDF DF 94/004 de-creased friction factor from 0.30 to 0.20.

• Tandem 9-5/8” PDM and Lyng LA325B drilled all of the 3096m in the 12-1/4” section.

• It is not recommended to rotate through intervals with high dog leg when using Sperry Sun’s “funny nukes” MWD tool.

0 10 20 30 40 50 60 70 80 90 100

8000

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6000

5000

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1000

0D

EP

TH

(m

MD

RK

D)

TIME (Days)

DAYS VS. DEPTH

17 1/2" section

12 1/4" section

8 1/2" section

AFE Line

Compl AFE

Target Line

Actual time

Compl TL

• Rotation of liner in high angle wells should not be done before the well is circulated clean and the mud is in good condition.

• Nodeco’s new PWP plug system was successfully used while running/cementing the 9-5/8” liner. • 9-5/8” liner was run to reduce ECD drilling of the 8-1/2” hole section. • Hycalog DS71H bit and tandem PDM motor was used to aid “stalling” problems while steering in 8-1/2” reservoir

sand formations, but is not the solution of this problem. • A new Gyro pump down concept was used with success in this well. The gyro was fully displaced down and the

displacement plug was collapsed at TD, and the gyro could be pulled out.

Statoil - Statfjord B42- Page 1 of 2

COMPLETION 6.9%WORKOVER/RECOMPLET 0.5%

CASING 13%

MOVING 0.8%BOP 3.1%

WIRELINE 1.8%

SNUBBING 4.5%

PLUGBACK 2.6%EVALUATION 2.5%

COILED TUBING 10.7%

DRILLING 42.1%

RIG 0.5%

UNSCHEDULED EVENTS 11%

SNUBBING 17.4%

BOP 1.5%COMPLETION 3.7%

FISHING 3.4%

DRILLING 55.1%

CASING 1.7%%

RIG 4.4%EVALUATION 0.5%

COILED TUBING 8.3%

WORKOVER/RECOMPLET. 4.1%


TOTAL TIME

North

Scale 1: 160.00

-4000 -3360 -3040 -2720 -2400-3680 -2080 -1760 -1440 -1120 -800 -480 -160 160 480 800

480

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: 100

.00

Scale 1: 100.00 Vertical Section on 128.26 azimuth with reference 33.53S, 10.76E from structure centre

WELL DATA

svy/prop slot well wellpath

p3627 slot #42 B42 B42 Feet P

s4002 slot #42 B42 B42 Feet P

B42 3GP, 2Tgt

B42 2GP, 1Tgt

B42 1GP

9 5/8

5 1/2

B42 4GP, 3Tgt

B42 FINAL SURVEY

B42 PLAN

13 3/8

18 5/8

30

EastScale 1: 160.00

9 5/8

B42 1 GP

B42 2 GP .1 Tgt

B42 3 GP .2Tgt

B42 4 GP .3Tgt

B42 FINAL SURVEY

B42 PLAN

13 3/8

18 5/8 30

Statoil - Statfjord B42- Page 2 of 2

Section 3 Trajectory and Directional Drilling Optimization

In this Section...

• Trajectory Design and Planning - Optimum Trajectory - Choosing Among Classes of Trajectories - Influence of Friction Factor (μ) - Additional Directional Planning Tips - Anti-collision Planning - Effect of Build Rate

• Directional Drilling Planning and Implementation - Drilling Assemblies - Downhole Motor Usage - MWD/LWD Considerations - Bit Selection - Tortuosity Issues - Influence of Buckling

• Wytch Farm Procedure For Sliding A Steerable Motor At Extreme Horizontal Departures

• References

3-1

INTRODUCTION

As with many aspects of ERD applications, the design and implementation of the wellbore trajectory requires continuing engineering compromise between various opposing forces. For trajectory design and planning phase, you must:

• Achieve the directional objectives - target location, size, orientation • Consider full well life cycle issues - evaluation, completion, intervention • Address anti-collision requirements • Consider wellbore stability - formation tops and types, offset and historical data • Understand mud requirements - type, weight, rheology, friction factors

For the planning and implementation of the directional drilling plan, you must cost-effectively mesh these objectives with your capabilities in several areas:

• Drilling assembly capabilities- build up rate (BUR), tortuosity, rotary -versus- sliding, jar placement

• Drill string performance - torque and drag, buckling • Bit selection - availability and compatibility with bottom hole assembly (BHA) and

formations • Hole cleaning and hydraulics - inclination, flow rate, rheology • Rig equipment limitations - top drive , pumps, setback capacity • Surveying - frequency, mode, accuracy • Casing wear - low contact forces, mitigation • Contingency plans for alternate casing and drilling tool programs

3-2

TRAJECTORY DESIGN AND PLANNING

Optimum Trajectory

To identify the optimum trajectory among many which achieve directional objectives, you first need to identify the most critical operations or wellbore characteristics which are the limiting factors:

• Wellbore stability (MW window) at target inclination/azimuth • Torque/drag effect on:

− BHA steerability − Ability to run casing − Logging and completion activities − Well Intervention

• Hole cleaning requirements • Rig equipment limitations

By definition, then, all other design work needs to adhere to these limitations. For example, if a limiting factor is the ability to run casing at high inclinations, you may need to reduce the tangent angle to allow the casing to slide more easily if allowed by other constraints (e.g. BUR, KOP depth, etc.).

3-3

Choosing Among Classes of Trajectories

There are several approaches to trajectory design to achieve long reaches with the fewest possible limitations on other downhole operations. The following list is a general comparison of the major options:

Option Advantages Disadvantages Multiple Build Profile: Rate of build increases with depth in several discrete steps to tangent angle, hold constant tangent angle

Very long reach, low torque/drag values, low casing wear

High tangent angle

Build and hold: Constant build rate to tangent angle, hold constant tangent angle

Simple, long reaches achievable, low tangent angle

Potentially high contact force in build (torque, casing wear)

Double build: Build-hold-build-hold trajectory, can use two different BURs in the build sections

Very long reaches possible with low contact forces in upper build

May require deep steering, High second tangent angle

Undersection: Build and hold with deep KOP

Reducing hanging weight below build section reduces contact force in build

High tangent angle, shorter reach

Inverted: Tangent angle above horizontal so the wellbore enters the reservoir from underneath

Flexibility for multiple targets, avoid gas cap

Higher axial (buckling) loads to push string uphill, deep steering required

3-D: Any of the above with significant azimuth changes

Flexibility to handle anti-collision and multiple target requirements

More curvature means more torque and drag, deep steering may be required, shorter reach

Build and Hold

UndersectionDouble Build

Multiple Build (with tangent)

Figure 3-1. Trajectory Profiles

3-4

Another wellbore profile which is frequently discussed is the catenary. In a catenary profile, the rate of inclination build continuously increases with depth to mimic the shape of a hanging cable. Theoretically, a catenary produces very low torque and drag as a result of low contact forces between the string and the wall of the hole. However, catenaries have not been widely used since creating the catenary shape is impractical and cost-prohibitive even with the most modern BHA configurations. The use of the catenary shape as a wellbore profile was first proposed and patented by Dailey Petroleum Services.

In choosing among these options, a useful concept to keep in mind is the critical tangent angle. This angle represents the limit beyond which a tool will not slide downhole under its own weight, meaning that it will have to be pushed from above. The critical angle is represented by:

q cos α = μ q sin α

or

tan α =1μ (3.1)

where q is pipe buoyant weight, μ is friction factor and α is critical tangent inclination angle. One approach to optimizing the trajectory is to try to position the KOP so that the tangent inclination equals the critical angle. If possible given other constraints, this will allow long reaches with reduced sliding problems.

Influence of Friction Factor (μ)

Since torque and drag can be the limiting design parameters, the optimum trajectory design depends heavily on our representation of wellbore friction. We use cased hole and open hole friction factors in our torque and drag studies, but they are not necessarily reflective of the coefficients of sliding friction one might measure in a lab. Friction factors should be calculated from field torque and drag data which depends upon a number of conditions including:

• Mud composition • Hole cleaning (cuttings beds) and cutting type • Operational procedures and type of operation (e.g. sliding or rotating), • Wellbore tortuosity • Formation type

See Section 10, “Torque and Drag Projections”, for a more complete discussion of friction effects and friction factors. For trajectory planning, the designer may want to account separately for tortuosity. This can be done by altering the input directional file for the torque and drag study to reflect some random deviations from the optimum plan. Appropriate deviations might be calculated from historical BHA behavior in the area and/or expected uncertainty errors in the surveying system.

3-5

Additional Directional Planning Tips

• Low BURs result in lower contact forces. This typically means lower casing wear. However, the longer MD required at the lower BUR may result in similar total torque and drag values as compared to high BUR wells.

• Low tortuosity is also achievable with low BURs. It tends to be more difficult to maintain low tortuosity with a high BUR.

• Torque and drag should be evaluated at the top and bottom of each hole interval as a minimum requirement using realistic friction factors for maximum required WOB (roller cone and PDC bits) in both sliding and rotary drilling mode.

• Trajectory design should be based upon realistic drilling assembly response. This will require close interaction between well planners, directional drillers, and geoscientists.

• Make the trajectory compatible with both the proposed and contingency casing points. • Once formation walk tendencies are known, consider “leading” the target azimuth in the

tangent to help avoid deep steering. • Avoid planned steering in hostile formations such as reactive shales or unconsolidated

sands.

To minimize steering, the trajectory in each hole interval should be designed to be compatible with the rotary mode directional behavior of the BHA.

The build section of the well should be designed around the rotary build performance of the steerable assembly. The tangent design should accommodate the walk characteristics of the assembly and bit combination.

Steerable assembly design should be such that the build can be achieved with 70-80% rotation. Build rates requiring more steering than this will, even with the most methodical drilling practice, result in significant unsurveyed doglegs. This may lead to localized high contact forces with subsequent casing wear problems and increased torque and drag. Generally, with lower build rate, more can be achieved while rotating the assembly and thus the chances of achieving the desired smooth build will be greatest.

Avoid directional work through formations exhibiting poor assembly response or that are fragile/unstable.

3-6

Anti-collision Planning

• Avoid a directional plan which may result in high dogleg severity (DLS) corrections in the shallow portion of the well. You may be paying for it for the rest of the well.

• Use pragmatic approach regarding deep ERD well intersections. Consider survey uncertainty based upon actual direction of approach and not semi major axis of ellipse.

The use of the normal plane traveling cylinder diagram has proved to be a very effective tool during ERD operations. However, in order to arrive at a workable directional plan and plot, the following points should be noted:

• Avoid plans that ‘hop’ over other wells, particularly during the build where there is the highest likelihood of ‘getting behind the line’. If the planned build rate cannot be achieved, an unacceptable dogleg could easily result as the well is ‘climbed’ out over the top in order to avoid well interference.

• If possible, avoid combined turns and builds in the upper section of the well, particularly if there are potential subsurface collision problems. Although the plan may look good on paper, if the well falls behind the ‘line’, again unacceptable doglegs may result as last minute course corrections are made.

• Always involve the directional driller, particularly if there is a tight exit to be made from a cluster, in order to check that allowable departure from plan (ADP) is realistic.

Effect of Build Rate

• High Reach/TVD ratio wells may tolerate high BUR because the string tension in the curve is low and may even be in mechanical compression.

• Low Reach/TVD ratio wells do not tolerate high BUR since drill string tension in the curve is higher.

• High build rates can cause casing wear problem, especially in high Reach/TVD ratio wells where there may be high tensile loads through the build section during trips out of the hole and backreaming.

Build rate may have a marginal effect on torque/drag levels for very high ratio wells. This is due to the increasing percentage of stringweight supported on the lowside of the hole resulting in lower tensile forces at surface. However contact forces may be sufficient to promote unacceptable casing wear at the higher build rates, especially when well operations such as extended backreaming are anticipated due to poor primary holecleaning. As a guideline, build rates in excess of 2.5 degrees/30m may cause concern with respect to high contact forces. If higher build rates than this are planned, the difficulty of achieving a smooth build also has to be considered where an increasing percentage of the build will be performed while sliding and not rotating the assembly.

3-7

DIRECTIONAL DRILLING PLANNING AND IMPLEMENTATION

The objective of directional drilling planning and optimization is to configure drill strings to cost-effectively achieve the optimum trajectory design.

Drilling Assemblies

• Configure BHAs to be short and light. Minimize non-mag equipment but without sacrificing survey accuracy.

• Maximize rotary mode drilling and minimize sliding mode drilling in build and tangent sections.

• Steerable drilling assemblies allow 3D course corrections. • Select housing bend to produce adequate DLS while minimizing housing fatigue in rotary

mode. A good compromise appears to be about 0.75o. • Consider positive displacement mud (PDM) rotor /stator interference to maximize life. • Use variable gauge stabilizers to control rotary mode directional tendencies and improve

hole cleaning. • Optimize flow rate for PDM, measurement while drilling (MWD), and bit while meeting

hole cleaning needs. Rotor nozzles may be required to achieve desired flow rate. • High drill string RPM assists hole cleaning. Refer to Section 11 - Hole Cleaning and

Hydraulics for a detailed discussion. Check top drive torque and RPM capability. • Optimize jarring system and placement.

3-8

Currently steerable motor BHA’s should be considered as the primary option for drilling extended reach wells due to their flexibility in making small 3D course corrections. To correctly plan and utilize a steerable assembly, these factors must be considered:

BHA Weight The assembly should be as light as possible. Increased BHA weight by the use of drill collars at high inclinations will lead to increased drag and torque and little, if any, increase in available WOB. Run the smallest number of NMDC or NMHWDP in order to achieve adequate magnetic screening both above and below the MWD.

Stabilization Run the smallest number of stabilizers commensurate with directional stability in order to minimize hole drag when sliding. Stabilizers should be of the straight bladed type and have tapered upper and lower blade edges (watermeloned) with minimal wall contact area. However, when considering placement, bear in mind the geometric correction that will have to be applied to MWD survey inclination. Running a stabilizer directly above and below the MWD collar should in most cases reduce this correction to something less than 0.2 degrees.

Offset Data Use caution in selecting and using offset directional BHA response data. Even if good directional reports are available, care has to be used, particularly if the offsets have been drilled with a different mud system to that proposed as it may have an effect on hole gauge and thus formation response.

Assembly Performance

Do not tolerate an assembly that is not performing as it will quickly lead to a well with an unacceptably high degree of curvature and result in excessive torque and drag. Steerable drilling assemblies should be treated as normal rotary assemblies, i.e. if they don’t perform directionally, they should be tripped. As a rule of thumb, if you’re having to slide an assembly for more than 10% of the tangent footage drilled, it is wrong for the application. During the process of optimizing the directional assembly, change one thing at a time, and this includes the bit type.

Target Sizing With increasing departures, driller’s targets can become relatively small, particularly where ‘industry standard’ MWD error ellipse’s are used. However, it has been demonstrated that by using steerable drilling systems and adhering to good directional planning and drilling practice, target centers can be intercepted without resulting in excessive orienting at depth. A logical approach to define a realistic confidence level to survey uncertainty is critical when sizing the driller’s target. The confidence level applied must be commensurate with the uncertainty level of the seismic and geological data.

3-9

Downhole Motor Usage

When considering a downhole motor for a specific extended reach application, the following issues must be addressed:

Stator Compound and Size

The stator compound will have to be fit for the mud system at the operating temperature of the motor. OBM will encourage excessive swelling and early degradation of the compound if the mud aniline point is exceeded. Care must be taken when assessing operating bottom hole temperature in extended wells. Experience from Wytch Farm indicates that motor temperatures can be 25% higher than the geothermal gradient alone. This will promote excessive rotor/stator interference if not accommodated within the setup of the motor. Refer to Figure 3-2 for a typical motor/hydrostatic relationship.

Housing Bend

Maintain a reasonable bend in the housing in order to ensure adequate dogleg response from the motor. Experience from Wytch Farm suggests that a 0.75 degree bend provides a good compromise between dogleg response and minimizing slide footage where hole cleaning obviously suffers without drill string RPM. However, be wary of drill string RPM limitations on the motor for a given bend. Excessive string speeds may result in detrimental fatigue loading on the lower stator housing, normally the weakest connection below the power section.

Flowrate Considerations

Because of the relatively high flowrates for hole size, rotor nozzles may be required if stator overpumping is to be avoided.

Increasing Length of Power Sections

Both extended and tandem motor sections have now been run in many extended reach applications. By increasing the number of stages, both configurations offer a higher stall torque for a given rotor/stator configuration than the standard power section. Alternatively, if the rotor/stator configuration is reduced, then significantly higher bit RPMs are achievable without compromise to torque output. In either case, depending upon the application, significantly higher ROPs are achievable without detriment to overall stator life. In addition, both types of motor have demonstrated easier ability to slide at depth.

PDM Integrity Severe vibrations in ERD wells have led to the loss of several motor rotors and lower bearing sections. The vibration has caused the lower service breaks to simply back off. This problem is not common to any particular supplier, it has been experienced by most. The solution to date has been to threadlock the lower bearing connection, and to employ a “rotor catcher”. This is a mushroom type assembly which is attached to the top of the rotor. In the event of a back off it will prevent the rotor from falling through the stator, allowing recovery of the entire unit. An improved design is still awaited which will prevent the back offs occurring without having to resort to threadlock.

HIGH P

RESSURE

INTERFERENCE D

ECREASED BY 0.010"

NORMAL OPERATIN

G AREA

LOWER 12 1/4"SECTION OPERATING

ENVELOPE

10000

7500

5000

2500

( INTERFERENCE IS

APPROX. 0

.020" )

INTERFERENCE IN

CREASED BY 0.010"

HIGH T

EMP.

0

DO

WN

HO

LE P

RE

SS

UR

E (

PS

I)

OPERATING TEMPERATURE ( F )

0 50 100 150 200 250 300

Figure 3-2

3-10

MWD/LWD Considerations

Flowrate Limitations

All tools need to be correctly sized for the maximum anticipated flowrate. Conventional equipment may be limited by excessive fluid velocity/force causing premature failure of telemetry/turbine components. Higher sand content within reservoir sections may exacerbate this problem.

Sensor Wear

Sag of collars between stabilizers may leave surface sensor windows, transmitters, receivers, etc. vulnerable to damage due to borehole contact, particularly in the more abrasive sandstone formations. Placement of circumferential standoffs/wear sleeves may be required to negate this.

Source Retrieval

If an assembly is run with wireline retrievable radioactive sources, the survey program should consider the risk of using pumped survey instruments, whether freefall or on wireline.

Sensor Position Optimize the position of sensors relative to the bit. Consider using near bit sensors where possible.

Special Materials Avoid using Beryllium-Copper (BeCu) alloy material as a replacement for Austenitic stainless steels. The BeCu material is most often used for saver subs on MWD/LWD collars.

Bit Selection

• Change bit designs incrementally and maintain compatibility with the BHA. • Treat the bit as integral part of the assembly. Different bit designs exhibit different

directional tendencies. • Ensure string design accommodates weight on bit (WOB) requirements for all bit types to

avoid buckling.

It is important to work with one design of bit in the early stages of any multiwell development where significant BHA changes may be required to achieve an adequate level of directional performance. As with BHA development, bit design changes should be methodical with one change at a time. In addition, it should be noted that with steerable assemblies, even minor changes in bit design may lead to significant assembly variations in both walkrate and inclination tendency.

3-11

Tortuosity Issues

• If the BHA is not producing the planned trajectory, trip it and change it. Do not tolerate a high percentage of sliding and associated high tortuosity from multiple corrections, especially in build sections.

• Drill in rotary mode as much as possible to maintain smooth BHA response. Additional benefits include higher ROP and improved hole cleaning.

• Keep DLS low. It is more difficult to drill a smooth build section with high DLS. • Typically, more BHA changes in a hole interval means improper BHA response and

higher tortuosity. • Calculate tortuosity consistently. See reference 1.

Influence of Buckling

• Rotary mode drilling minimizes axial component of drag. This reduces buckling tendency. • Axial component of drag is highest in sliding mode drilling. This increases buckling

tendency. • High inclination increases drill string support from the wellbore. This reduces buckling

tendency. Increased contact force also increases torque and but associated increase in drag may be less than that due to buckling.

• Buckling creates an additional drag source which can lead to lock up. • If the amplitude of sinusoidal buckling is kept below around 40 degrees then the

associated drag due to buckling is negligible. An oversized string to avoid buckling is often less optimum.

It is common, while orienting at depth in an extended reach well to have the complete drill string in compression, i.e. the neutral point in the string is at, or even above the rotary table. Although in this situation fatigue is not an issue due to no pipe rotation, buckled drill pipe will never the less result in higher drag and less available WOB downhole. Although buckling in this instance is largely unavoidable, it is rare that full helical buckling will occur; it will almost certainly remain sinusoidal. However, the engineer must attempt to moderate the problem by providing sufficient drill string stiffness within critical areas of the well.

3-12

To achieve satisfactory orientations at depth using a steerable drilling system, these key areas must be addressed:

• Minimize wellbore axial drag. The amount of mud solids in the well at the time will play an important part in determining this. However, don’t always assume that the cleaner the well, the lower the axial drag will be. It will depend very much on the friction generated between the drillstring, casing, formation and mud. The amount and type of solids in the fluid, particularly certain types of LCM, will play a major role in determining this friction factor.

• Ensure that the drill string is not suffering undue sinusoidal buckling as a result of applied surface loads. Although buckling lockup is unlikely, axial drag will increase significantly even with this lesser form of buckling. Refer to Section 9, “Drill String Design”.

• Apply weight to the top of the string by top drive manipulation. Care has to be taken to ensure that any unconstrained pipe buckling above the table is managed. The following formula addresses the amount of drill pipe above the rotary table for a given top drive weight. Refer equation 3.1 shown on the following page.

• Increase weight of the drill string itself by replacing drill pipe with either heavy weight drill pipe (HWDP) or drill collars (DCs) in the upper vertical part of the well. Points to consider prior to carrying out this technique are: - time to handle DC’s versus HWDP - makeup torque versus drilling torque levels - potential problems with HWDP hardbanding while rotating inside casing

3-13

WYTCH FARM PROCEDURE FOR SLIDING A STEERABLE MOTOR AT EXTREME HORIZONTAL DEPARTURES

At extreme well departures it will become progressively more difficult to slide a steerable motor. To facilitate this operation you must apply some or all of these non-conventional techniques:

• Run HWDP or Drillcollars near surface. • Apply the weight of the Topdrive to the string. • Use drillstring rotation to break sliding friction, without affecting toolface.

These procedures have been shown to yield good results, allowing motor slides at over 7.5km departure:

1. Prior to sliding take torque and drag readings. Use a working single for sliding. 2. Without circulation (if possible), attempt to work the pipe to bottom with no rotation. Observe

available downweight. It has been found that drags are generally lowest after a trip without circulation or rotation.

3. Pick up 10 ft. (3m) and establish full circulation. 4. Orient the string to the desired toolface and run to bottom. Drill ahead using the available

string and topdrive weight. 5. If the application of all available string and surface equipment weight is still insufficient to

allow sliding, then proceed with the following additional steps. 6. Mark the pipe, and with downweight applied put minimal right hand turns in the string to

promote downward movement. Closely monitor surface torque. 7. Once downweight has been established, removed the turns by rotating the string the exact

same number of turns to the left to bring the mark back to the original orientation. This will leave toolface unaffected.

8. Slack off the available downweight to drill ahead. 9. Repeat steps 6 to 8.

Notes: 1) Pay close attention to the allowable weight which can be applied on top of drillpipe above the

rotary table before buckling would occur. Allowable weight versus stickup above rotary for various tubulars can be estimated from equation 3.2 given below:

Maximum weight (lb) =

9377(OD4 − ID4 )L2

⎡ ⎣ ⎢

⎤ ⎦ ⎥

where pipe OD and ID are in inches, L is the stickup in meters. (3.2) 2) If drill collars are run at the top of the string, these must be laid out prior to drilling ahead with

rotation if surface torque is in excess of the maximum make-up torque. 3) Check that the swivel top plate and associated load paths can safely withstand the topdrive weight

application (45,000 lb). 4) Clear the drillfloor of personnel when applying topdrive weight.

3-14

REFERENCES

1. Banks, S.M., Hogg, T.W., and Thorogood, J.L., "Increasing Extended-Reach Capabilities Through Wellbore Profile Optimisation", SPE/IADC 23850, presented at the SPE/IADC Drilling Conference, New Orleans, February, 1992.

2. Eck-Olsen, J., and Drevdal, K.E., "Designer Directional Drilling to Increase Total Recovery and Production Rates", SPE/IADC 27461, presented at the SPE/IADC Drilling Conference, Dallas, February 1994.

3. Abbassian F., Mason, C., Luo, Y., Brown C., Payne, M., and Cocking, D., "Wytch Farm 7/8 km Stepout ERD Wells", Internal Report DCB/11/95, May 1995.

4. Abbassian, F, and Mason, C., "M3: Influence of Well Profile on Torque and Drag", DCB File Note, October 1994.

5. SDSS User Manual

6. Guild, G.J., Hill, T.H., and Summers, M.A., "Designing and Drilling Extended Reach Wells", Part 2, Petroleum Engineer International, January, 1995.

7. Payne, M.L., Cocking, D.A., and Hatch, A.J., "Critical Technologies for Success in Extended Reach Drilling", SPE 28293, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, September, 1994.

8. Sheppard, M.C., Wick, C., and Burgess, T., "Designing Well Paths to Reduce Torque and Drag", SPE Drilling Engineering, December 1987.

9. Mueller, M.D., Quintana, J.M., and Bunyak, M.J., "Extended Reach Drilling From Platform Irene", OTC 6224, presented at the 22nd Annual OTC, Houston, May 1990.

3-15

Section 4 Completion Issues Related to Extended Reach and Horizontal Wells

In this Section...

• Wellbore Considerations - Planning Well Profile - Mud Design & Hole Cleaning Issues - Drilling Reservoir Section - Displacements

• Completion Types - Extended Reach / Horizontal Well Completions for Sand Control - Gravel Packing / Fracpacking - Frac Pack Completions - Designing Upper Completion - Running Upper Completion - Damage Removal in Extended Reach / Horizontal Wells - Matrix Stimulation - Hydraulic Fracturing

4-1

• Well Interventions - Open Hole Logs/RFT - Cement Evaluation - Perforating - TCP - Running & Pulling Completions - Production Logs - Water/Gas Breakthrough Management - Coiled Tubing

• Artificial Lift - ESPs

• References

INTRODUCTION

The numerous extended reach / horizontal well completion methods available offer varying degrees of efficiency in the ability to manage the reservoir through the wellbore(s). These methods vary from extremely basic to the more complex. It is always important to keep in mind the concerns and practices used in vertical well completions. These concerns relate to drilling through the interval with a mud system that either produces minimum damage or a damage that is easily removed by perforating or low cost stimulation, to having sufficient zone isolation for stimulation and future work in the vertical well. It is important to have these same or greater concerns with extended reach / horizontal wells. The ability to manage the reservoir through these wellbores is important to the success of the well.

Table 4-1 points out some of the many variables which are important in obtaining the proper completion and, therefore, production from an extended reach / horizontal well. These are divided into three main areas as shown below:

• Reservoir Characteristics - These characteristics are divided into primary and secondary importance and both can dictate completion design.

• Wellbore Considerations - These considerations are divided into the radius of curvature for the well path and diameter of the drilled hole; and wellbore stability. The radius of curvature and diameter of the drilled hole will influence selection of equipment and tools that can be used upon completion and subsequent workovers. Wellbore stability will influence the mud weight and chemistry used to drill the well (and formation damage) and to the wellbore stability at drawdown (production).

• Completion Type - The selection of completion type will be based upon the reservoir characteristics, wellbore considerations and economics and can become an iterative process. That is, when the expected results are determined and compared to the cost and complexity of the completion, a different approach, perhaps shorter lateral length, assumption of a higher degree of risk (poorer completion design) or even a decision to not drill the well can be considered.

4-2

These variables point out that the process of drilling and completing extended reach or horizontal wells takes into consideration many disciplines. A multidisciplinary team effort is necessary to develop the final guidelines as to how these wells are to be drilled and completed. It is also evident that in many cases there is no definite separation between drilling and completion operations with these types of wells. The final running of the liner and washing the wellbore may also be the completion. The completion method must fit the reservoir characteristics and drilling parameters employed.

TABLE 4-1 ER AND HORIZONTAL WELL COMPLETION CRITERIA

EXAMPLE Reservoir Characteristics Wellbore Considerations Completion Type

Primary Secondary Radius/Dia Stability

Natural Fracs Normal PP Ultra Short Drill OB Open Hole

Water Coning PP>Normal Short Radius Drill UB Slotted Liner

Gas Coning PP<Normal Medium R Drill B Preperfed Liner

Unconsol Carbonate Long Radius Stable @ DD ECPs / SL

High Perm Sandstone Slim Hole Cased Hole

Low Perm Shale Wire Wrapped Screen

KH / KV Gas PrePacked Screen

Thin Beds Oil OH Gravel Pack

EOR CH Gravel Pack

PP = Pore Pressure DD = Drawdown

R = Radius ECP = External Casing Packer

OB = Overbalanced SL = Sliding Sleeves

UB = Underbalanced OH = Open Hole

B = Balanced CH = Cased Hole

Other factors not shown on the table also influence the completion type. Two of these are the effect of only having a portion of the horizontal wellbore open to production and the pressure drop expected along the horizontal well during production.

• Partially Opened Wellbore - Goode and Wilkinson reported in their work, that it may not be practical or cost effective to open the entire length of the lateral.

− It is possible to open as little as 50% of the lateral without substantial loss of production under certain circumstances

− Examples of selectively completed horizontal wells are; cemented liner that is subsequently perforated in selective intervals, the use of external casing packers on blank pipe to reduce the amount of screen used, etc

− Each reservoir situation may be different and an analysis of the expected reservoir performance should be made prior to selecting the completion method.

4-3

• Production Pressure Drop - Joshi and Dikken reported work related to the pressure drop expected along the horizontal wellbore during production.

− This pressure drop in many cases plays a big role in determining the size of the hole to be drilled and therefore the completion string size (ID/OD).

− This may influence the economical length of the lateral.

− These pressures can be significant with high production rates or the flow of highly viscous crudes.

− If the pressure drop (friction) in the lateral is small compared to the pressure drawdown from the reservoir to the wellbore then the horizontal wellbore can be considered as an infinite conductivity conduit.

− If the pressure drop in the wellbore is large as compared to the reservoir drawdown then the overall production rate would be influenced. In this case the length of the wellbore could be reduced or the drilling and completion design changed, i.e., larger hole, larger ID liner, etc.

4-4

WELLBORE CONSIDERATIONS

Planning Well Profile

Predictive modeling for coiled tubing (CT) access should play a major part in designing the well profile for all deviations above 50-65 degrees. The ability to drill ERD wells at extreme departure /TVD ratios currently exceeds our ability to deploy CT for well intervention at TD, yet the success of ERD wells over the life of well depends on the ability to service the wells.

For coiled tubing, the largest challenge is to overcome the frictional forces that build up in the 9 5/8" casing as the coil penetrates further into the wellbore. The forces are sufficient to cause the coil to form a helix and lock up in the reservoir section, preventing access much beyond 6,000m in high departure/TVD ratio wells (3.5-5).

For CT access, the key parameters to model are depth of kick-off point, tangent angle, and degree of inversion. High kick-off points are clearly advantageous. Small changes in tangent angle can have large implications for lock up depth. Use of chemical friction reducers, nitrogen and increasing CT size have provided successful remedies to date and penetration up to 7,000m ought to be feasible.

In horizontal sections, modeling indicates dog-leg severity's up to 2 deg/30m can in general be tolerated without incurring large penalties on CT penetration.

For extreme ERD wells, predictive modeling for running perforation guns and completions should also be considered when designing well profile.

Mud Design and Hole Cleaning Issues

At Wytch Farm it was essential that efficiency of hole cleaning pills was optimized to prevent perforation debris and LCM from blocking the ESP. They have had success with new OBM displacement technologies developed by ARCO. ARCO's Clear Fluid Technology is an advanced displacement process for the cleanout of oil based drilling muds. It improves both speed and effectiveness of the cleanup process. The process not only optimizes transport mechanics, but also incorporates efficient and environmentally friendly fluid systems. The technique is suitable for cleanout of OBM in both cased hole and open hole applications.

In general, the displacement design utilizes a series of four spacers to provide an optimized cleanout of the OBM:

• First: Weighted spacer containing surfactants • Second: Viscous gel • Third: Brine buffer • Fourth: Solvent mix

4-5

The strategy of the design is to first displace the bulk of the OBM in a piston-like manner using a proprietary weighted spacer and viscous Xanvis gel. Simultaneously, pre-cleaning is performed on the casing/formation surfaces by surfactants in the weighted spacer. The brine buffer is used to remove the residual viscous gel, and protect the subsequent solvent from being viscosified which would compromise its turbulent flow cleaning action. In all, the spacer fluid system is designed to:

• Provide a density-balanced displacement of OBM • Promote an interface miscibility with the OBM • Protect the integrity of weighted spacer from uncontrolled dilution • Accommodate density and viscosity transition • Provide fast-acting and turbulent cleaning action

In the displacements for Wytch Farm's ERD wells, a 3-spacer design is used because of the low weight OBM (0.94 sg), which eliminates the need for the weighted spacer. As a result, the weighted spacer and viscous gel are combined into a Xanvis pill weighted up slightly with NaCI and included with the surfactants. Spacer properties and displacement rates are optimized using BP's Cement Placement Simulator. The BP hole cleaning model was used to ensure any cuttings, residues, gelled OBM and other debris were effectively removed from the well during displacement.

Drilling Reservoir Section

Optimize bridging material size distribution in OBM. Optimize kill pill formula to spot in heavy losses. Use of thin section pore image analysis performed on core section can provide useful information when designing both systems.

Useful guidance on seawater filtration specifications to prevent formation damage can be obtained from conducting coreflood permeability tests.

Displacements

• Move pipe, both rotation and reciprocation. As in drilling open hole, rotation is extremely important to moving solids and heavy muds on the low side.

• Centralization or standoff will help get the low side cleaned up. Use standoff anywhere along the wellbore that holdup or duning is suspected.

• Weigh pros and cons of turbulent versus laminar flow characteristics for each spacer in the system. Review for each well in light of the wellbore geometry. Low spots and high rises may influence the choices.

• Review benefits and disadvantages of weighted versus unweighted displacements for both WBM and SOBM. Wellbore integrity may preclude going to seawater as an intermediate step. Or the risk of contamination of the completion fluid in a weighted displacement may be too costly.

• For the lead spacer, regardless of the mud being removed, ensure its weight is at least 0.5 ppg more than the mud weight and its viscosity is at least equal to (if not higher than)

4-6

the mud. This will help lift the entire mud column out of the well and reduce tendencies to channel.

• Thin the mud in the well before pumping any spacers. Be careful to not go too low to cause barite to settle out. A lead thin mud spacer may work well if the mud has been circulated and conditioned.

Circulate the mud at least one hole volume to condition before pumping spacers. Drop a carbide lag to check bottoms up. The mud must be in good shape first or the best displacement procedures will not work.

The displacement of OBM with seawater can be accomplished in less than 4 hours with clear seawater returns obtained at surface. Samples of fluid returns also indicated a good sweep as evidenced by the many drill cuttings and solids observed. The keys to the success of this type of job are:

• An effective spacer system • Good hydraulic design • Close rig site quality control of both mixing and pumping operations • Good preplanning for efficient use of available surface volume

This spacer technology has now been licensed to Halliburton, and it has also been applied for optimizing cement spacer systems for OBM with very successful results.

4-7

COMPLETION TYPES

The following presents some of the basic types of ER / HW completions being used in the industry, as well as some of their applications, advantages and disadvantages.

TYPE / APPLICATION POTENTIAL ADVANTAGES POTENTIAL DISADVANTAGES OPEN HOLE / Applicable in stable wellbore environments. No shale or other potentially unstable lithology exposed in the wellbore.

• Reduced initial completion cost

• Potentially less damage than in other completion methods since time of fluid exposure is less

• Entire formation face is exposed to wellbore for greater production potential

• Remedial work can be carried out with inflatable packers, etc

• Alternate completion method could be utilized later in well life

• Minimal production inflow / outflow control

• Difficulty in removing damage

• Aggressive stimulation treatments, i.e., hydraulic fracturing, difficult and risky

• Highs and lows in wellbore may allow preferential water and/or gas coning in those areas

• Plug and abandonment may be more difficult than where zone isolation completions are utilized

SLOTTED OR PREPERFORATED LINER / Liners run in open hole and “hung off” in production casing. Applicable in formations where wellbore stability is a problem, i.e., unconsolidated formations, exposed shales, etc.

• Initial completion cost is low

• Production potential may be similar to open hole completion

• Wellbore collapse, sloughing, sand production arrested

• Liner may be washed in using washdown assembly. Washdown assembly (stinger) may also be used to wash formation face after liner is in place

• Liner assists in getting workstrings or coiled tubing to end of lateral ( through doglegs, etc)

• With formation collapse around screen and blank sections zone isolation and stimulation can be performed

• No production control

• Difficulty in shutting off unwanted zones

• Effective stimulation difficult

• Production crossflow could be a problem

• Difficulty in obtaining quality production logging data

• Liner rotation while placing may cause liner failure/slot width deformation

• There may be difficulty in pulling liner for remedial work

• Liner collapse potential due to slots or perforations

• Plug and abandonment may be difficult

4-8

TYPE / APPLICATION POTENTIAL ADVANTAGES POTENTIAL DISADVANTAGES

LINERS WITH EXTERNAL CASING PACKERS / Applicable as above and where zone isolation is needed

• Zone isolation enhanced

• Applicable in naturally fractured reservoirs where cementing liners is normally not done

• Large numbers of completions exist using ECPs adding confidence to their use

• ECPs can be inflated with some muds or cement. Cement inflation can provide long term isolation

• Screens, slotted liners or blank liners with sliding sleeves may be used

• Flow control, monitoring equipment may be placed in the area of the ECPs or blank pipe sections

• Cost, where significant zone isolation is required

• Caliper logs necessary to determine where ECPs can be set. Clean, gauge hole required

• Inflating packers with cement can be risky

• Unless proper cement and inflation pressure are used cement inflated packers may contract with time breaking the seal with the wellbore

• Breakdown (fracture) pressure is normally lower in horizontal wells as compared to vertical wells. ECP setting potentially could cause formation fracturing

• High permeability wells may allow production around ECP

• Unconsolidated formations may collapse around ECP resulting in seal loss

CASED HOLE (Cemented and perforated liner). Applicable where a high degree of wellbore control and reservoir management is necessary. For example, where water or gas coning is a potential problem, where significant stimulation will be carried out, etc.

• Zone isolation and wellbore control is obtained

• Liner collapse resistance is assisted by cement sheath

• Perforations may penetrate damaged zone

• Enhanced potential for quality production log diagnostics

• Stimulation / water shutoff potential is increased over other completion methods

• Experience with perforating adds confidence to perforated completions in ER/HWs

• Plug and abandonment is made more reliable with this method

• Minimal mud losses while perforating/running completion

• Cost of initial completion

• Difficulty with remedial cementing, if necessary

• Usually limited to non-naturally fractured reservoirs unless hydraulic fracturing is planned

• Also, usually limited to consolidated formations. Not many ER/HWs in unconsolidated formations are completed as cased hole gravel packs

• Limited amount of formation may be exposed due to reducing perforations to reduce completion cost. This may or may not be detrimental

4-9

Extended Reach / Horizontal Well Completions for Sand Control

These completions would use the slotted liner or screen ( wire wrapped, sintered, etc) or a cased hole completion. A gravel pack could be carried out in these completions, however, industry experience to date indicates a gravel pack may not be necessary. The typical completion is a liner or a screen, normally prepacked, placed in the open hole. The formation is then allowed to collapse around the screen. The success of these completions is apparently due to a reduced producing fluid velocity per exposed area and reduced drag forces which cause sand production.

For perforated completions, where production frictional losses in long reservoir sections are large compared to production draw down, consideration must be given to a perforation strategy which involves perforation only the toe sections, varying the shot density and the spacer density. Especially important where controlled draw down is necessary to prevent coning.

Underbalance to ensure optimum cleanup of perforations without compromising formation disintegration should be investigated for each reservoir zonation. Unconfined compressive strength (UCS) tests and thick wall cylinder (TWC) tests can be conducted on core in the lab to get more data.

Gravel Packing / Fracpacking

• High angle frac pacs (fracturing) CAN be achieved and should be considered as a viable completion option. Four recent frac's in ERW's at 80#161# have been very successful.

• Review the tapers on both liner hangers and work string tools to ensure there are no ledges to stop movement while running tools into or out of the well.

• Review ball seat tapers on hydraulic packers to ensure the ball does not have to climb a sharp ledge to get on seat.

• Drift the casing after cementing with a gauge ring or junk basket at least as large as the GP packer. This packer is usually the largest OD tool that will be run in the well.

• During a circulating gravel pack, be mindful of the volume and weight of the carrier fluid that is returning through the washpipe and above the GP packer. If it is lighter than the kill weight fluid, it could cause sufficient loss in hydrostatic to cause the well to flow.

• To facilitate cleanup on flow back and thus help minimize damage from the gravel pack operation, use the simplest carrier fluids possible to suspend gravel. A single salt like 2% KCl water mixed with HEC will not only hydrate gel quickly, its viscosity will break more readily and to a lower residual level than a more complex salt. One downside could be more time required on CBU after the job to remove high levels of gas in the completion fluid due to the loss of head.

• Design the well to TD with at least 7" casing or larger. GP/FP tools smaller than this do not operate very well due to the cross-sectional size and pressure rating constraints.

• Due to the stretch of the work string in long reach wells, design GP/FP operations with a minimum amount of tool movements and try to operate at the extreme tool positions, i.e., lowermost or uppermost positions. Tools can move out of middle position undetected quite easily.

4-10

Frac Pack Completions

Frac Pack completions are a widely used high efficiency sand control treatment which provide for highly productive wells and reliable sand control. A frac pack is installed by pumping a proppant gel slurry downhole at pressures which exceed fracture pressure. Most frac packs are pumped with sand control screens in place. Frac packs place significantly more proppant/gravel behind pipe compared to conventional gravel packs. The productivity of frac pack completions is roughly three times that of a conventional gravel pack. Frac packs can be placed in long reach high angle wells with certain adjustments to the pumping operation. The current envelope for frac pack is 21,000 ft. and 80 degree hole angle across the pay.

The success of this completion type is attributable to the large amount of pay which is present at the wellbore. The pay can be impaired to a great extent at the wellbore while maintaining good total production because of the large exposure. Sand control in these types of well is suspect because of recent BP and industry failures. The specific cause of the failures is presently unknown.

Designing Upper Completion

Design well completions for minimum intervention. Use of a resettable hydraulic packer has been proven to work successfully in ERD applications and has provided useful flexibility for workovers resulting from shallow completion faults.

Use of a "formation saver valve" device, hung off in the casing, should be considered to protect the formation during completion pulling/running at workover.

Running Upper Completion

Completion spaceout calculations to land the tubing hanger and set the packer need to account for the way in which drag forces are distributed over the length of the completion. Where a high degree of drag is present , the slack-off acts predominantly over the vertical section owing to the large proportion of drag occurring in the build section. If the slack-off is based on the total string length, this could result in the tubing hangar standing proud of the of the bowl after the full string weight is slacked off. It is recommended that the space out procedure is related to load rather than extension, and that the relationship between string load and extension is determined on a well by well basis at the rig floor.

Model completion running on Super DSS to understand impact of drag on jewelry and ascertain whether target depth is achievable. If not, evaluate the potential for specialty chemical friction reducers.

Use of chemical friction reducers (e.g. Dowell's ID Lube XL, Baroid's TorqTrim-22) should be considered where buckling or lack of running weight while running completion is anticipated. Ensure these are non-formation damaging.

If possible, design the well profile to allow wireline access in preference to CT. When performing well design. Similarly, model effects of pull/running completion at design phase. Use of lubricants may help here (Circa 10-15% drag reduction with lubricants).

4-11

Damage Removal in Extended Reach / Horizontal Wells

Damage removal in extended reach or horizontal wells consists of simple very near wellbore damage removal and matrix acidizing. In non-matrix damage removal the very near wellbore is washed, jetted, circulated, soaked, flowed back (put on production), etc to remove a wall cake, wall cake building materials and very shallow invasion. The completion should be such that this cleaning of the wellbore can be accomplished. As mentioned above, where a liner has been placed with a stinger (wash pipe) circulation, etc can be carried out. With openhole completions a coiled tubing/work string is usually employed to clean the wellbore. The drill-in fluid and additives should have been designed with this hole cleaning in mind. The table below illustrates some of the materials potentially used as drill-in / completion fluids and the fluid loss control materials and approaches used to remove them.

DRILL-IN / COMPLETION FLUIDS

FLUID LOSS CONTROL MATERIAL

REMOVAL APPROACH

OIL BASE MUDS (Including synthetics)

• Organic (Starch, Nut Hulls, etc)

• Calcium Carbonate, Salt, etc

• Flow back

• Organic solvent/surfactant wash/soak to regain water wet conditions in sandstones.

• Utilize acids and oxidizers to remove organics after residual OBM has been removed.

• Use fresher water to remove salt if used.

WATER BASE FLUIDS • Polymers (CMC, PAC, PHPA, HEC, Guar, X-C, Starch, etc)

• Calcium Carbonate, Salt

• Flow Back

• Utilize acids and/or oxidizers for washing and soaking. Use fresher water for salt removal

GAS, AIR, MIST, FOAM • Normally used in underbalanced drilling to reduce damage, in low pressure reservoirs, etc

In those situations where filtrate invasion and particulate materials have resulted in formation damage away from the near wellbore area a more aggressive stimulation approach will be needed. This is also true for low permeability formations where hydraulic fracturing will be required. The following relates to some of the issues important in these situations:

• Maximize hole size across pay zone to keep tool sizes as large as possible. Small crossover tool do not perform as reliably as larger tools.

• Maximize hole size across pay zone to allow the use of large work string to minimize friction

• Maximize hole size across pay zone to allow the use of large sand control devices (i.e.. screen) and provide for sufficient casing screen annulus.

4-12

• Long measured depth creates large work string tubular volumes. This results in 1) Large fluid capacities, 2) Long fluid residence time for reactive fluids and 3) reduced efficiency for reverse circulating slurry from the work string.

• Long perforated sections create difficulty in producing a tight casing screen gravel pack. We currently perforate no more than 275 ft.

• Long, high angle perforated sections can hide gas produced during completion operations.

• Long perforated sections create very high fluid loss conditions.

• Excessive surface treating pressures are created by high friction pressure in ERD wells. The use of large work string is required to avoid high treating pressure.

• High pressures will cause pipe contraction and may cause crossover tools to shift out of position. The use of weight down tools are recommended.

• Rupture discs have not proven to be reliable for protecting from surface pressure spikes.

Matrix Stimulation

Zone isolation is important to allow differential pressures sufficient to inject into the sand face. Options:

• Open hole stimulate using inflatable straddle packers, bridge plugs for isolation on coiled tubing/work string

• Open hole stimulate using coiled tubing for fluid placement

• Cased hole stimulate using inflatable packers, bridge plugs, Perforating, Stimulating, Isolation tools for zone isolation

• Slotted liners / screens with External Casing Packers. Use straddle packers, bridge plugs for zone isolation. ECPs should be closely spaced such that isolated interval can be stimulated at one time. Chemical diversion difficult in sandstones with this completion.

• Slotted liners / screens with no ECPs. Matrix stimulation difficult unless formation sand has collapsed around screen. If sufficient blank liner sections have been run then zone isolation technique for stimulation could be used.

4-13

Hydaulic Fracturing

Zone isolation important to provide for high pressures and injection rates required.

• Wells drilled parallel to the minimum horizontal stress, i.e., transverse fractures. In sandstones, the preferred completion is cased hole. Perforations should be clustered in a short interval at the location of each fracture initiation point. Zone isolation would be with bridge plugs and packers. Number of fractures will depend upon reservoir characteristics and economics. In carbonates where acids can be used to generate fracture flow capacity, the completion can be open hole, cased hole or liners with ECPs. The preferred completion is cased hole with mechanical isolation, however, chemical diversion is possible in open hole completions.

• Wells drilled parallel to the maximum horizontal stress, i.e., axial fractures. In sandstones anticipate the fracture running long distances along the wellbore and potential problems with proppant placement. Normally a high injection rate will be required for successful fracturing. Cased hole completions preferred. In carbonates, completion options exist since acid is a possibility for generating fracture flow capacity and chemical diversion is possible.

4-14

WELL INTERVENTIONS

Open Hole Logs/RFT

RFT tools can be run successfully in drillpipe conveyed systems. The key risks are unsuccessful latching of the pumpdown wet connect head in high angle sections and the risk of damaging the cable on the outside of the pipe at the top of the hole. The risks can be mitigated by:

1. Drifting all pipe to 0.5" above the wet connect o.d. 2. Check threads for loose particles, minimum dope on pins, use mechanical dope

applicator. 3. Solids free mud 4. Pipe clean of cement/rust/scale, etc. 5. Break circulation every 10 stands; 5 stands when logging and running pipe and cable in

parallel. 6. The depth at which the wet connect should be attempted is a trade off. The deeper the

point, the lower the chance of success in making the connection, but also there is less cable in the open hole. Experience at Wytch Farm suggests high confidence in the former even in deviations up to 85 degrees, and results in less risk on damaging the cable. However, ensure that cable is not exposed to open hole which could lead to differential sticking problems.

7. Communication between driller and logging cabin MUST be excellent with every single movement and intent being communicated to prevent cable damage.

8. Typically no more than 10 minutes stationary time should be planned in open hole. Procedure to position at a station should be agreed beforehand.

9. A brass collar can be fitted above the pumpdown wet connect head to increase the pump down force at tool joints.

Cement Evaluation

For cased and perforated completions, cement evaluation logs have indicated that even where bond quality is judged to be poor, bond quality in the immediate vicinity of solid blade liner centralizers (e.g. "Spirolisers") remains excellent - the solid centralizers act as mini ECPs. Regular placement (2 per joint) virtually assures channeling will not occur.

Both CBL and USI tools have been run on CT in ERD wells at Wytch Farm to evaluate cement bond quality in the liner, and casing wear. Where logging under pressure has been possible, running a USI has been of limited value (See References).

4-15

Perforating

• Since most ERW's require the use of a tapered workstring, carefully review the tapers on both liner hangers and work string tools to ensure there are no ledges to stop movement while running tools(wireline) into or out of the well.

• Be mindful of the potential for large volumes of fluid losses and sand influx due to the length of the pay zone at high angles. Larger than normal kill pills may be required to control fluid losses. Flow back volumes may need to be adjusted downward to arrest sand production.

• Underbalances may need to be reduced with TCP guns in unconsolidated sands to keep from sanding up the guns on flow back.

• Any sand or debris that may be in the wellbore will not fall through the sump packer as in a conventional well. More time will be required to cleanout the wellbore and keep it clean. Diligence in this area will circumvent many headaches in the long run.

TCP

Chances of success in getting long lengths of TCP guns to TD in ERD wells can be improved by:

• Understanding weight loss and buckling tendency - use Super DSS modeling and bench test connections. Use of HWDP and DCs in upper section should be considered.

• Gun connections can be torqued in preference to using grub screws to add extra stiffness and to mitigate against critical buckling being induced.

• Use of chemical friction reducers (e.g. Dowell's ID Lube XL, Baroid's TorqTrim-22) should be considered

Annulus pressure fired systems with Positrieve rotational set packers have proved to be most reliable arrangements at Wytch Farm. Direct pressure fired systems were relegated to backup because of problems with delay calculations which led to some wells being perforated overbalanced.

Post perforation cleanout to remove gun debris should be planned. Use of correct flowrate is almost more important than chemicals used. A staged approach consisting weighted spacer/surfactant (to displace fluid/debris using weight), followed by a viscous gel, followed by brine (to remove gel and prevent solvent from viscosifying) and solvent should be considered.

Generally, if long reservoir sections are drilled and subsequently perforated, there are signifcant volumes of perforation debris. Use controlled debris gun systems if large amounts of perforating debris are a concern. For example, Schlumberger's Cleanshot system reduces size distribution of debris for minimal extra cost. If a debris-free well is required, then extensive efforts must be made to remove gun debris.

4-16

Running & Pulling Completions

Design well completions for minimum intervention due to the cost of CT and the risk of failure. Use completion items designed for high angle wells (e.g. Baker CMU SSOs, Nodeco packers). Don’t assume that proven technology in “vertical wells” will work in ERD/high angle wells.

Running completions in ERD wells requires extensive preplanning. Losses must be controlled for a longer period (i.e. well is open for a longer interval), meaning that well kills must be specially designed.

Formation damage may be a concern if wells are open longer/LCMs are used in well kills. Use of formation Saver Valves or other means of liner isolation should be thoroughly examined. (Generally, horizontal/ERD wells are higher producing than deviated or vertical wells in the same reservoir - thus loss rates may be significantly higher.)

Coiled tubing can be used for completion running and workover phases of ERD wells - setting/retrieving deep set plugs, inflatable packers, and DHSVs; shifting sliding sleeves; and spotting chemicals and LCM across the liner sections. The feasibility of completing more than one of these functions in a single trip should be investigated since significant development in CT deployment has been made to both increase penetration and reduce the number of runs.

During the planning stage it is important to ensure that there will be sufficient weight (tool face energy) at the bottom of the string to activate the tools.

Production Logs

Use of new phase velocity tools and lift impedance flow meter tools to measure oil and water flowrates and hold-ups independently should be considered when designing the production logging toolstring. The additional data obtained could to improve the interpretation of conventional production logging (spinner) data in long undulating horizontal wellbore sections.

Consideration ought to be given to methods and facilities necessary to deploy some of the new logging toolstrings on CT. These can be longer than 30 meters in length and consideration of pressure deployment methods and associated weak point technology should be reviewed locally.

Water/Gas Breakthrough Management

The compromise between maximizing stand-off from oil/water contact to delay water breakthrough and maximizing section in high quality pay zone should be fully evaluated at the beginning of the program. With future wells and more information the strategy can be amended on a well by well basis.

A cement bond evaluation strategy should be put in place to evaluate the first few wells. If success can be related to operational factors during the cementing operation, these can then be used to set criteria which can then be used to decide whether cement bond logs should be run on a well by well basis.

Criteria for controlling drawdown to prevent coning must be reviewed by modeling inflow performance, and supported by production logging objectives.

4-17

Wellhead sampling does not accurately reflect downhole water cuts. Large water cuts bay lead to slug flow in a high angle well.

Coiled Tubing

Use of chemical friction reducers, nitrogen and increasing CT size have provided successful methods of improving CT deployment depths to date. Friction reducer at Wytch Farm (e.g. Dowell's ID Lube XL) has typically reduced friction factors by up to 30% and has demonstrated a lasting effect after 5 days.

History matching of actual deployment depths versus prediction for a given profile should be undertaken to establish trends in friction factors and improve predictive modeling.

Use of cycle life criteria for CT fatigue evaluation may not be appropriate for ERD applications where failures due to thinning and scoring from external wear can arise. The use of a maximum footage run in hole may be a more relevant criteria for deciding whether to accept a coil for duty on ERD wells or not.

On-site butt welding of coiled tubing should not be undertaken lightly. If there is no alternative, strictly controlled conditions should be agreed by BP. These include:

• The maximum OD to be welded is 1.75". • Weld only pipe of similar wall thickness. • Butt welds must be placed such that they are deep in the well where pipe stress is lowest. • The correct size of chill blocks appropriate to the pipe size must be used and placed 3/8"

apart. • The absolute maximum fatigue life to be 40%. • A test weld should be conducted and tested with radiography and hardness checks to

ensure welding procedure is adequate • Hardness tests should only be carried out on test pieces as the indentation caused will

act as a stress concentration point. • Three x-ray shots should be taken 120 deg. apart. Inspection should be on a zero defect

basis.

4-18

ARTIFICIAL LIFT

ESPs

Some thought should be given to addressing the problems arising from the use of ESPs in near horizontal sections where, unlike in vertical wells, debris is likely to accumulate across the well section. Hole cleaning procedures should be developed. The ESP design can be modified to create low tortuosity, high volume flow paths with large intake ports. Spiral fins and paddles to induce fluid rotation can be built into bypass clamps to prevent debris settlement at intake.

The inclusion of a permanent downhole flow meter system in the completion design should be considered. The meter can prove to be a valuable diagnostic tool during well commissioning and normal production operations. Real time data provided by the meter can help quickly diagnose situations where the pump has been operating in reverse rotation, where downhole recycling is occurring and where the well is under performing because of a pump suction blockage. The meter could prevent the premature failure of ESP units.

Long cable lengths in ESP completed ERD wells can lead to the build up of current harmonics in the in the drive/transformer/cable/motor system. This can result in overheating of the transformer system. The phenomenon has been observed but can be designed out by adding additional reactances to the system.

The build up of air within the conductors of power cable during production operations immediately after ESP completion running can cause mechanical failure of the internals of wellhead penetrators leading to electrical failure of the completion. Special consideration should be given to controlling the rate of pressuring/depressuring of the production annulus containing the cable, and the design of the penetrator reviewed for a pressure release mechanism.

ESPs can be plugged by perforation debris and LCM.

Motor seal oil temperature and vibration monitoring devices are commercially available and should be considered where justified.

4-19

REFERENCES

1. Coulter, G. R.; Perez, J. I., “Issues Related to Completion of Horizontal Wells”. Presented at the International Symposium on Unconventional Hydrocarbon Recovery, St. Petersburg, Russia, Oct 12 -14, 1992.

2. White, C., “Formation Characteristics Dictate Completion Design”, Oil & Gas Journal, Dec 3, 1990.

3. Fuh, G.F., Loose, P.K., “Horizontal Wellbore Stability for Openhole Completions”, SPE 19717, Presented at the 64th ATCE of the SPE held in San Antonio, Tx, Oct 8-11, 1989.

4. Lowery, J.P., Ottesen, S., “An Assessment of the Mechanical Stability of Wells Offshore Nigeria”, SPE Drilling & Completion, March, 1995, pp 34-41.

5. Goode, P.A., Wilkinson, D.J., “Inflow Performance of Partially Open Horizontal Wells”, SPE paper 19341 presented at the SPE Regional Meeting . Held in Morgantown, West Virginia, Oct 24-27, 1989.

6. Joshi, S.D., “Horizontal Well Technology“ Pennwell Publishing Company, 1991.

7. Dikken, B. J., “Pressure Drop in Horizontal Wells and Its Effect on Production Performance”, Journal of Petroleum Technology, November, 1990.

8. King, G. E., “The Effect of High Density Perforating on the Mechanical Crush Resistance of Casing”, SPE paper 18843.

9. Morita, N., McLeod, H., “Oriented Perforation to Prevent Casing Collapse for Highly Inclined Wells”, SPE Drilling & Completion, Sept, 1995, pp 139- 145.

10. Coulter, G.R., “Horizontal Well Treatment Method”, U.S. Patent 5,197,543; March 30, 1993.

11. Byrom, T.G., Coulter, G.R., “Some Mechanical Aspects of Formation Damage and Removal in Horizontal Wells”, SPE paper 31145, Presented at the International Symposium on Formation Damage Control, Feb 14-15, 1996, Lafayette, Louisiana

12. Ogden, S., “Inflatable Packers Provide Options for Horizontal Wells”, Petroleum Engineer International, Nov 1991 p37-42.

13. Weirich, J.B., Zaleski Jr., T.E. and Mulcahy, P.M., “Perforating the Horizontal Well: Designs and Techniques Prove Successful”, SPE 16929, presented at the 62nd ATCE of the SPE, Dallas, Tx, Sept 27-30, 1987.

14. Pardo, C.W., Patrickis, A.N., “Completion Techniques Used in Horizontal Wells Drilled in Shallow Gas Sands in the Gulf of Mexico” SPE paper 24842, presented at the 67th ATCE of SPE, Washington, D. C., USA, Oct 4-7, 1992.

15. Murphy, P.J., “Performance of Horizontal Wells in the Helder Field”, Journal of Petroleum Technology, June 1990.

16. Browne, S.V., et al, “Simple Approach to the Cleanup of Horizontal Wells With Prepacked Screen Completion” , Journal of Petroleum Technology, Sept, 1995, pp 794-800.

17. Ryan, D.F., et al, “Mud Cleanup in Horizontal Wells: A Major Joint Study”, SPE paper 30528, presented at the SPE ATCE in Dallas, Texas, Oct 22-25, 1995.

18. Shale, L., “Underbalanced Drilling With Air Offers Many Pluses” Oil & Gas Journal, June 26, 1995, pp 33-39.

19. Economides, M. J. and Frick, T.P., “Optimization of Horizontal Well Matrix Treatments”, SPE Production and Facilities, May 1994, p 93-99.

20. Tambini, M., “An Effective Matrix Stimulation Technique for Horizontal Wells”, SPE paper 24993, presented at the European Petroleum Conference held in Cannes, France, Nov. 16 - 18 , 1992.

4-20

21. Yew, C. H. and Li, Y., “Fracturing of the Deviated Well”, SPE 16930 presented at the 62nd ATCE of the SPE held in Dallas, TX, Sept. 27 - 30, 1987.

22. El Rabaa, W., “Experimental Study of Hydraulic Fracture Geometry Initiated From Horizontal Wells”, SPE 19720, presented at the 64th ATCE of the SPE held in San Antonio, TX, Oct. 8 - 11, 1989.

23. Damgaard, A., Bangert, D.S., Murray, D.J., Rubbo, R.P. and Stout, G.W., “A Unique Method for Perforating, Fracturing and Completing Horizontal Wells ”, SPE 19282, presented at Offshore Europe 89, Aberdeen, Scotland, Sept 5-8, 1989.

24. Use Of Coiled Tubing During The Wytch Farm Extended-Reach Drilling Project - TD Summers, H A Larsen, M Redway, G Hill - SPE 28558, February 1995.

25. Operating Experience With ESPs And Permanent Downhole Flowmeters In Wytch Farm Extended Reach Wells - A Brodie, A Allan, G Hill - SPE 28528, September 1994.

26. Zonal Isolation And Evaluation For Cemented Horizontal Liners - H Gai, T D Summers, D A Cocking, C Greaves - SPE 29981.

27. Continuous Improvement In Well Design Optimises Development - P F Harrison, A W Mitchell - SPE 030536, October 1995.

28. Wytch Farm 7/8km Stepout ERD Wells - Wytch Farm 7/8km Interactive Project, XTP, May 1995.

29. Alfsen, T.E., et al, “Pushing the Limits for Extended Reach Drilling: new World Record From Platform Statfjord C, Well C2”, SPE Drilling & Completion, June 1995.

30. Brodie, A.D., Allan, J.C., Hill, G., “Operating Experience With ESPs and Permanent Downhole Flowmeters in Wytch Farm Extended-Reach Wells” Journal of Petroleum Technology, Oct 1995, pp 902-906.

31. Wu, J., Juvkam-Wold, H.C., “Coiled Tubing Buckling Implications in Drilling and Completing Horizontal Wells”, SPE drilling & Completions, March 1995, pp 16-21.

4-21

Section 5 Mechanical and Chemical Wellbore Stability

In this Section...

• Mechanical Aspects - Planning Stage - Drilling Stage

• Chemical Aspects - Planning Stage - Drilling Stage

• References

• Contacts

5-1

INTRODUCTION

This section addresses the mechanical and chemical aspects of wellbore stability, with particular emphasis on ERD wells. Hole instability refers to two extremes of formation collapse and formation breakdown (Figure 5-1).

FRIABLESANDSTONE

SALT

++++++++++++++++

+++++++++++++

++++++++

++

+

++++++

++++++

+++

++

++

+

OVERGAUGE

HOLE

HOLE

CLOSURE

CO

MP

RE

SS

IVE

WellborePressureLOST

CIRCULATION

FO

RM

AT

ION

BR

EA

KD

OW

N

BRITTLESHALE

Figure 5-1.

Formation collapse can lead to spalling and/or hole closure. A number of factors can be responsible for hole collapse, but the most common reasons are:

• Insufficient support was provided to the wellbore wall, i.e. the mud weight was too low.

• The mud chemistry was incompatible with the formation.

Formation breakdown describes the creation of an induced fracture (or opening of a natural fracture system) leading to massive mud losses. The primary reason for formation breakdown is use of too high a mud weight.

The very nature of extending the reach of wells in a given area will often increase the risk of instability. Therefore, greater care during the planning and drilling of an ERD well is required.

5-2

MECHANICAL ASPECTS

In cases where only one formation type is exposed during drilling, it should be possible to select a mud weight that will prevent hole instability. For example, mud weights up to 18 ppg (2.15 SG) have been used by operators to control hole collapse/closure in shales and salt formations. However, it is seldom possible to select a casing program that will isolate each formation type in turn.

In general, hole sections will contain shales/mudstones, which are susceptible to hole collapse, and sands or carbonates, which are susceptible to breakdown and lost circulation.

To drill a hole section without instability requires that the maximum mud weight tolerated by the sands/carbonates be greater than the minimum mud weight required to support the mudstones in the same hole section. In extremely difficult drilling regions (e.g. foothills of the Casanare region in Colombia) it is impossible to select a mud weight that will satisfy both criteria simultaneously. In less severe environments a "mud weight window" will exist (Figure 5-2a).

13 3/8"

9 5/8"

Drilling window

Drillingwindow

1.0 S.G. 1.5 S.G. 2.0 S.G.Equivalent Mud Density

Pore pressure

Collapse gradient

gradient

Fracturegradient

L.O.T.

(a) Drilling window for 12 1/4' hole section ofvertical well through given lithology sequence.

Drilling window

Drilling

window

1.0 S.G. 1.5 S.G. 2.0 S.G.Equivalent Mud Density

Pore pressure

Collapse gradient

gradient

Fracturegradient

L.O.T.

Dep

th(T

VD

)

(b) Drilling window for 12 1/4' hole section ofERD well through given lithology sequence.

Figure 5-2. (a) (b)

Provided the mud weight selected fits within the window, the hole section can be drilled relatively problem-free. How-ever, the width of the window depends on a number of operator controlled factors. In particular, increased well inclination usually reduces the width of the window, thus increasing the risk of straying from the region of safe mud weights (Figure 5-2b).

ERD wells have hole sections of greater inclination than have previously been adopted for a given setting. Hence, the risk of instability in an ERD well is greater. Factors requiring consideration during the planning and drilling stage of a deviated well (especially ERD) are covered in the following sub-sections.

5-3

Planning Stage

Well Inclination • Typically allow for increases in mud weight of between 0.5 ppg (0.06 SG) and 1.0 ppg (0.12 SG) per 30 degrees inclination through shale/mudstone sections. Only local experience will determine at which end of the scale you need to be.

• No increase in mud weight with hole inclination is necessary across permeable formations, e.g. sands. Formations with reasonable matrix permeability can be drilled with nominal overbalance, regardless of well trajectory or formation strength.

• The fracture gradient may reduce with increased inclination. Fracture Gradient • The fracture gradient for a hole section is more likely to be controlled

by a carbonate or sand than the shale within which the leak off test (LOT) was performed (see Figure 5-2).

• Drilling high pressure reservoirs with ERD wells may prove extremely difficult due to a tight mud weight window between taking a kick and getting losses. Carefully consider the extent and effect of ECDs at the planning stage.

• During appraisal, consider performing micro-frac tests (essentially a LOT taken beyond the point of breakdown) to determine the fracture gradient in formations that may be critical in an ERD well.

Regional Stress State

• Process any dipmeter or borehole imaging log data to determine in-situ stress directions. This may help to interpret any problems seen during the drilling operation and thus hasten corrective actions.

• In highly tectonically-stressed regions, drilling up-dip of the major faults may provide a larger mud weight window than drilling down-dip, cross-dip, or vertically.

• The in-situ stress state near a salt diapir is highly disturbed, such that well trajectories which approach the diapir normal to its surface provide a larger mud weight window than trajectories tangential to its surface.

Casing Program • Having planned for an increased mud weight to control shales in an ERD well, assess whether the planned casing setting depths still provide a sufficient mud weight window.

• In ERD wells, the mud weight required to drill a normally pressured reservoir is often significantly less than that required to prevent collapse in the cap rock. The setting of the production casing should minimize or exclude the presence of cap rock in the reservoir hole section, thus allowing the reservoir to be drilled with a nominal overbalance.

General • Oil-base muds often allow a lower mud weight to be used to prevent collapse in shales. This provides a larger mud weight window.

• The risk of instability in highly laminated shales may be reduced when adopting a trajectory normal to bedding.

5-4

Drilling Stage

• Even in normally stressed regions the mud weight window may be influenced by well azimuth. Be prepared to increase the mud weight in wells with azimuths nearly parallel to the maximum horizontal stress direction.

• Keeping mud filtrate loss to a minimum is particularly important for ERD wells in all hole sections, not just the reservoir section.

• Swab and surge pressures may trigger instability in weak or highly fractured shales. Particular care is required when running in, and pulling out of, hole sections with such formations.

• Unless absolutely necessary, do not reduce the mud weight while drilling if a shale is present in the open hole section. Otherwise, the risk of hole instability is greatly increased. If operational difficulties necessitate a mud weight reduction, then the slower this is done the better.

• The onset of cavings more than a few hours after drilling a shale indicates that the benefit of the initial overbalance has been lost. This is a result of migration of filtrate into the formation, causing near wellbore pressure increases. An increase in mud weight and/or a reduction in fluid loss are likely to help.

• The onset of cavings from a formation while it is being drilled may indicate inadequate mud weight. An increase in mud weight or a reduction in rate of penetration (ROP) may help.

• Often, an improvement in LOT value can be observed as the section is drilled. Consider repeating the LOT where low values have been obtained.

5-5

CHEMICAL ASPECTS

Chemical wellbore instability is due to chemical interaction between the formation being drilled and the drilling fluid. This occurs primarily in shales and salt formations. In both cases, it is an interaction with water which causes instability. Thus, chemical instability is always minimized by using oil-base muds.

When shales react with water, they can soften, disperse, swell, and crack. These effects can cause a wide range of operational problems, as shown in the table below.

Shale Type

Typical Hole Problems

MBT* (meq/100g)

Water Content (wt%)

Clay Types

Wt% Clay

Shale/ Clay Density (g/cc)

Soft (shallow)

• Tight hole due to swelling

• Hole enlargement due to washout

• Ledges if interbedded with sandstones

• Bit balling, mud rings, blocked flowlines

20-40 25-70 smectite + illite 20-30 1.2-1.5

Firm (deeper)

• Tight hole due to swelling

• Possible washout

• Prone to bit balling

• Occasional cavings

10-20 15-25 illite + mixed layer 20-30 1.5-2.2

Hard (deep)

• Cavings

• Cuttings beds causing packing off

• Tight hole in stressed formations

• Possible stuck pipe

3-10 5-15 illite + poss. smectite

20-30 2.2-2.5

Brittle (very deep)

• Cavings

• Hole collapse

0-3 2-5 illite kaolinite chlorite

5-30 2.5-2.7

* MBT = methylene blue test - a measure of cation exchange capacity; high MBT equates to smectite rich shale.

To minimize these problems, characterize the shale type at the planning stage of a well, and use an appropriately-designed drilling fluid.

In salt formations, chemical instability occurs if the formation is soluble in water. Using an incorrectly formulated fluid will lead to uncontrollable washouts in these situations. Formation types which exhibit this behavior are:

• Halite ( NaCl) • Carnallite (KMgCl3.6H2O) • Bischofite (MgCl2.6H2O)

• Sylvite (KCl) • Polyhalite ( K2Ca2Mg(SO4)4.2H2O)

5-6

Planning Stage

Characterizing the Formation

• When planning an ERD well, first decide if shales or water-sensitive salts will be encountered. Offset well data and mud reports will be particularly useful. Contact your geologist for assistance.

• Design the casing/well program to minimize the length of time reactive formations are exposed to the mud. Because shales have very

low permeability (10-9 - 10-6D), they may appear stable for a time, but water can slowly penetrate, leading to time-delayed effects.

• Characterize shale types by XRD analysis (contact Sunbury for this). This technique should also be supported by laboratory inhibition tests, which are best done on preserved shale.

• Watch out for interbedded formations (e.g. salt stringers in shale). A mud system compatible with both formation types will be required.

Mud Selection • The best way to minimize chemical instability in shales or salt sections is to use an oil-base mud. This should be the first choice.

• Do not solely rely on chemical-mechanical wellbore stability models to design the mud. There is, invariably, insufficient input data which does not take into account specific chemical reactions.

Oil-base Mud - Hints

• Oil mud salinity must be at least as high as the pore fluid

salinity of the shale. This will prevent water entering the shale by osmosis.

• When drilling salt formations, oil-base mud (OBM) salinity should be high (e.g. 300,000 mg/l chloride) to minimize salt dissolution into the water phase of the mud.

• Synthetic-oil muds (pseudo-oil muds) should be considered where environmental constraints restrict the use of conventional oil. Shale inhibition is equally effective in these systems.

• In microfractured shales, use a very low fluid loss mud (HPHT < 3mls), and add fracture sealing additives.

• Always consult your mud specialist, as systems vary widely in rheological properties, temperature stability, and cost per barrel.

Water-base Mud - Hints • If water-base mud is to be used, carry out a screening program at an early stage to allow optimization, and discuss issues with your fluids specialist and the mud companies.

• In salt sections, match the fluid to the type of salt. Salt saturated muds (NaCl) are used for simple halites; mixed salt systems are available for complex salts such as Carnallite.

5-7

Obtain specialist advice on these. • Use a low fluid loss mud (API < 5ml) in microfractured shales,

and add fracture sealing additives.

5-8

Drilling Stage

• Monitor mud properties frequently. It is important to maintain additive concentrations to maintain chemical inhibition.

• When drilling shales, monitor cuttings quality as a qualitative measure of inhibition. Very soft cuttings mean insufficient chemical inhibition.

• Obtain a fully detailed record (mud report) as this will give invaluable information when planning the next well.

REFERENCES

1. A Drilling Guide to Shales and Related Borehole Problems; M. Aston and P. Reid. BP Sunbury Branch Report DCB/46/93, dated 17 December 1993.

2. Wellbore Stability Guidelines (updated version); M.Aston, J. Hagan and M. McLean. Sunbury, dated 1994.

3. Salt Diapir Drilling Stability Guidelines; M. Addis, J. Roberts and I. Searle. Sunbury manual dated 1993.

CONTACTS

Specialty Name Location Telephone Fax Geomechanics Joe Hagan XTP Sunbury 44 (0)1932 762109 44 (0)1932 764183

Nigel Last BPX Colombia 57 1 623 4077 57 1 618 3215

Mike McLean XTP Sunbury 44 (0)1932 764135 44 (0)1932 764183

Dave Roberts PSR Dyce 44 (0)1224 832285 44 (0)1224 832827

Mud Chemistry Mark Aston XTP Sunbury 44 (0)1932 764055 44 (0)1932 764183

Bryan Chambers PSR Dyce 44 (0)1224 833635 44 (0)1224 833577

Allan Twynam BPX Venezuela 582 901 9379 582 901 9023/27

5-9

Section 6 Drilling Fluids Optimization

In this Section...

• Selection of Fluid Type - Environmental Issues - Optimization of Fluid Formulation - Barite Sag - Wellbore Stability/Inhibition - Hole Cleaning Capability - Mud Lubricity - Torque and Drag Reduction - Filtration Control/Differential Sticking - Solids Control Management - Formation Damage Aspects

• General Considerations

• References

• Contacts

INTRODUCTION

The selection and correct implementation of drilling fluid is crucial to the successful drilling of any well. The fact that potentially troublesome formations will be exposed for greater lengths, and for longer time periods, increases the importance of drilling fluid selection for ERD applications. Many fluid related issues, such as hole cleaning, torque, drag, and hydraulics, that present few problems on vertical wells, must be addressed in detail when planning an ERD well.

6-1

SELECTION OF FLUID TYPE

Environmental Issues

The selection of fluid type for ERD wells is essentially the same as for conventional wells. Initially, a choice must be made between an invert emulsion (mineral- or synthetic oil-base) and a water-base drilling fluid.

• Where feasible, an oil-base invert is the preferred fluid for ERD applications. • When environmental limitations prevent the use of mineral oil-base mud (OBM), consider

using a synthetic oil-base invert. • Where environmental, or logistical, limitations completely negate the use of any form of

oil-base formulation, the most suitable water-base mud must be chosen.

The most suitable water-base fluids currently available for ERD drilling when clay inhibition is required are potassium-based, non-dispersed, polymer muds containing glycol or silicates. When inhibition is not required, low solids polymer formulations or Mixed Metal Hydroxides can provide the required hole cleaning and their use, with a suitable lubricant, should be considered.

When comparing fluids on a commercial basis, it is not sufficient to merely compare costs per barrel. Consideration must be given to anticipated rig time savings (penetration rates, requirement for wiper trips, etc.), actual usage per foot, buy backs and/or disposal costs (where applicable). For instance, many operators find the use of a relatively expensive pseudo oil-base fluid is readily justified by savings in rig days. High mud costs for the right system are fairly inconsequential in ERD wells when compared to probable wells costs resulting from use of the wrong fluid.

6-2

Optimization of Fluid Formulation

Having made the choice between an invert emulsion and a water-base mud, experience and/or laboratory testing must be used to optimize the formulation. These major requirements must be addressed and fine tuned:

Rheology Plastic Viscosity - The required yield point and low shear characteristics should be achieved with minimum plastic viscosity. Circulating density becomes an important factor in long step-out ERD wells, particularly in the smaller diameter holes (8-1/2 and 6-inch intervals). High equivalent circulating density (ECDs) can be produced which may exceed the fracture gradient of the rock and produce downhole mud losses. To minimize these effects, rheology (particularly plastic viscosity) should be maintained at the lowest level that supports efficient hole cleaning and solids suspension.

Gels - Excessive gel strengths must also be avoided. During trips, high gel strengths may result in surge and swab pressures that can in turn lead to downhole losses or have a destabilising effect on the wellbore. When high bottom hole temperatures (i.e. >300°F) are anticipated, test results that demonstrate the fluid's rheological behavior at elevated temperatures must be made available by the service company. Many labs are available to perform testing and verify these results.

Inhibition If an oil-base mud is selected, the correct water phase salinity must be determined so as to minimize transfer of water from the mud to the formation, and vice versa. Water phase salinities in the region of 180g/lt is a good starting point for marine shales with somewhat lower levels (100g/lt) being appropriate for freshwater shale. When a water-base mud is to be used in sections where clays are exposed, the optimum level of chemical inhibition should be determined in laboratory tests.

Lubricity Effective lubricants must be identified that will produce workable coefficients of friction and be compatible with both the mud and the environment.

Reservoir compatibility

The potential for products to cause formation damage in the reservoir must be considered. Products known to be potentially damaging to the producing formations should not be considered for use in reservoir sections unless perforating or fracturing beyond the invasion area.

6-3

Barite Sag

Barite settlement (sag) is a key issue for high angle wells. The current thinking is that barite sag can never be totally eliminated. In practice the problem needs to be managed. This can be achieved by a combination of mud design and good operational practices.

Barite sag in deviated wells can result in:

• Fluctuations in mud weight in and out

• Well control problems

• Downhole mud losses

• Induced wellbore instability

• Stuck pipe

Recent studies into the problem demonstrated:

• Sag is a DYNAMIC phenomenon which may not occur when mud is static

• Sag is exacerbated by low annular velocities

• Hole inclinations close to 75 degrees are most critical

• Drillpipe rotation significantly reduces sag

• Mud rheology at low shear plays a key role in controlling sag

Wellbore Stability/Inhibition

Borehole instability due to overpressured or water-sensitive formations must be minimized when drilling an extended reach well. Mud/rock interaction must be minimized by careful screening of mud type and properties. A wellbore stability study should be instigated for any initial ERD project in a particular asset. This will address optimum mud weight selection and highlight any possibility of instability.

For further information see Section 5, “Mechanical and Chemical Wellbore Stability”.

6-4

Hole Cleaning Capability

Flow rate (i.e. annular velocity) is the single most important factor relating to hole cleaning in deviated wells. Typically, most problems associated with hole cleaning occur in the 30 - 60 degree section where gravity effects can cause cuttings beds to slump down the hole. The BP Hole Cleaning Model should be used in the planning of all wells, most especially in extended reach applications. Generally, higher flow rate is better if it can be economically achieved. Typical flow rates to aim for in ERD wells are:

Hole Size Typical Flow Rates 17-1/2 in Aim for 1100 gpm. Some rigs achieve 1250 -1400 gpm.

12-1/4 in Typically 950 - 1150 gpm. If not available, ensure that tripping procedures are in place for probable dirty hole.

8-1/2 in Aim for 500 gpm.

High rotary speeds greatly enhance hole cleaning potential. Discuss limitations of rotary speeds when using downhole motors with the directional drilling company. Trend sheets should be used to log all hole cleaning parameters for future use, i.e. flow rate, rpm, mud rheology vs. depth, and evidence of dirty hole on trips, etc. Trip procedures should be prepared in advance, with guidance on tripping intervals, backreaming rates, and maximum overpull. These procedures can be modified over the well as necessary.

See Section 11, “Hole Cleaning and Hydraulics”, for more information.

Mud Lubricity - Torque and Drag Reduction

In extended reach drilling, frictional forces may limit the possible extent of step-out. It is therefore important that every effort is made to reduce the coefficient of friction of the mud to levels that allow the well to be successfully drilled. In both the laboratory and the field, water-base muds exhibit a higher coefficient of friction than oil muds. The friction coefficients of water-base muds can be improved by the addition of lubricants. The currently available lubricants are only of significant benefit in low weight, low solids muds. By virtue of its film forming capability, oil is inherently a better lubricant than water. Some of the synthetic (pseudo) oil-base fluids exhibit lubricity superior to conventional mineral oil-base muds. Some lubricants are available for use in OBM. However, their use is restricted, as a correctly formulated oil mud will normally exhibit sufficient lubricity for most wells.

• When using water-base mud, adequate supplies of an approved and compatible lubricant must be available at the rigsite prior to drilling critical intervals.

• After additions of lubricant, surface torque must be monitored to assess the effectiveness of the treatment.

• Mechanical devices typically have a more positive effect than chemical additives, and should be considered prior to fluid enhancement.

Many lubricants are available on the market. The rapid development in mud lubricants makes it inappropriate to nominate specific lubricants. Also, the specific requirement depends upon the mud system being run and the particular downhole environment. Consult your local Fluids Specialist and/or XTP Fluids Team to get an update on currently available high-performance lubricants and recommended concentrations.

6-5

Filtration Control/Differential Sticking

Maintain good filtrate control when drilling in an overbalanced situation through porous formations, particularly when these formations are a potential reservoir. Low filtrate helps minimize potential formation damage and reduces the possibility of differential sticking. Oil-base muds (including pseudo-oil muds) generally exhibit lower fluid loss than water-base fluids and consequently lower sticking tendencies. For this, and other reasons discussed above, they are the preferred fluid for extended reach wells. Additives are available for both oil- and water-base fluids that will reduce differential sticking tendency. These include filtrate reducers, lubricants, and bridging agents. Filtercake thickness increases with time when the mud is static in the hole - keep such periods of non-circulation to a minimum. High gel strengths should be avoided, as they increase the likelihood of sticking and make the spotting of pipe releasing agents more difficult. Pipe freeing procedures must be reviewed prior to drilling in porous formations. Details of options and procedures can be found in the Stuck Pipe Handbook.

Solids Control Management

The control of low gravity solids is paramount in the successful and economical application of all drilling fluids. Effective removal of drilled solids will minimize pressure losses, optimize filtercake characteristics, and reduce formation damage potential. In ERD applications, the problem of the removal of the drilled solids is exacerbated by down hole attrition of the solids, by saltation, and mechanical re-grinding between the drill pipe and the wall of the hole. This attrition may be so effective as to reduce the solids to sizes too small to be removed by conventional shale shaker screens. The lack of cuttings seen at the shakers could then lead to the potentially false conclusion that the hole was not being cleaned. A subsequent increase in rheology would reduce the effectiveness of the secondary equipment (hydrocyclones and centrifuges) that offer the only means of removing these fine solids. This larger-than-normal fine drilled solids content requires that care is used when assessing the requirements for solids removal equipment for ERD applications. Experience has shown that even with the use of the best available solids control equipment, ultrafine solids inevitably build up in muds used on ERD wells. High rheology and gel strengths will result and it may prove necessary to change out mud systems (or part of the system) with the solids-laden mud being returned for treatment (i.e. dilution). The stage at which this would be initiated is judgemental by the mud engineer. The decision would normally be based on ineffective removal of solids by the high-speed centrifuges and by the requirement for greater than normal surfactant additions.

As stated above, primary removal of much of this fine material will be difficult with conventional elliptical motion shakers. Linear motion shakers will allow the use of fine screens (200 or 230 mesh) assuming that sufficient units are available to handle the anticipated flow rates. In unweighted, water-base muds, desilters and clay ejectors (small 1 inch diameter hydrocyclones) may have an application assuming that all underflow is discarded. Mud cleaners are not recommended, as they allow the return of the very fine material that needs to be removed.

6-6

Hydrocyclones are not recommended for use with weighted, water-base muds or oil muds of any kind. In these applications, the preferred mechanism for the removal of fines is by centrifuge. High speed centrifuges are required to remove fine solids from viscous mud. In the case of weighted muds, a low speed unit in series with a high speed unit is required. In some cases, it is commercially advantageous to return the barite underflow from the low speed centrifuge to the active system via some mixing equipment. When running in this “barite recovery” mode, the overflow from the low speed unit is fed to the high speed unit, which is capable of removing some of the fine LGS and barite. High speed centrifuges are rarely capable of processing more than 1.0 bbl/min. Remember this when assessing the requirements for solids removal equipment.

To aid in the determination of the suitability and efficiency of solids removal equipment, two spreadsheets, the Super Volume Estimator and the Equipment Performance Evaluation Spreadsheet, have been generated by XTP.

Formation Damage Aspects

Minimizing formation damage is critical to the success of an ERD well. The fact that the reservoir is often drilled at high angle in such wells results in longer sections of reservoir being exposed for greater amounts of time. Any potential damage caused by mud filtrate and solids can be expected to be exacerbated under these conditions. Compatibility of mud filtrate with formation fluids and interstitial clays must be established at the earliest opportunity. For production wells, the required information regarding reservoir characteristics should be available for use in well planning. Core samples may even be available to allow appropriate testing to be carried out. When prior knowledge of reservoir characteristics is not available, avoid using known, potentially damaging products. Mud solids can enter porous rock if the fluid possesses high spurt loss before an adequate filter cake is built up. This can usually be minimized by the addition of a small concentration of correctly sized bridging material. Again, knowledge of the pore diameters of the reservoir will allow the selection of suitable bridging material at the planning stage. An understanding of how an ERD well is to be completed is essential when selecting a mud. The drill-in fluid properties will need to be modified according to the completion type to ensure maximum productivity. For example, the filter cake clean-up potential of a mud becomes very important for a well with a non-perforated completion.

GENERAL CONSIDERATIONS

• Fluid related aspects of ERD wells require considerably more planning than conventional wells. Consequently, planning must be started at an earlier stage to allow fluid selection, wellbore stability, hydraulics, and rig modifications to be addressed and completed in a timely manner.

• Run two mud engineers with ERD experience on the rig. • Mud systems are large in volume. Treatments take a long time to effect because of this. • Do not rely on high rheologies for hole cleaning. Pump hard. High rheologies make

casing cementations difficult. • It is not unusual to have lost circulation problems when running long casing strings, the

tendency to pack off, and ECD values running close to frac gradient. Have a logistics plan to cover losses running the casing. Consider circulating occasionally to reduce gel strengths when tripping long strings of casing.

6-7

REFERENCES

1. BPX Horizontal Drilling Manual

2. BPX Well Productivity Manual

3. Critical Technologies for Success in ERD - M L Payne et al SPE 28293 (1994)

4. Stuck Pipe Handbook

5. The Super Volume Estimator Spreadsheet

6. The Equipment Performance Evaluation Spreadsheet

7. BP Barite Sag Guidelines, P. Bern, November 1995.

CONTACTS

Specialty Name Location Telephone Fax Mud Programming Bryan Chambers PSR Dyce 44 (0)1224 833635 44 (0)1224 833577

Pete Wilson XTP Sunbury 44 (0)1932 763346 44 (0)1932 764183

Torque and Drag - Prediction/Monitoring

Phil Hearn XTP Sunbury 44 (0)1932 763226 44 (0)1932 764183

Hole Cleaning Peter Bern XTP Sunbury 44 (0)1932 763469 44 (0)1932 764183

Yuejin Luo XTP Sunbury 44 (0)1932 762424 44 (0)1932 764183

Mud Lubricity Greg Elliot XTP Sunbury 44 (0)1932 764213 44 (0)1932 764183

Torque Reducers Colin Bowes XTP Sunbury 44 (0)1932 762049 44 (0)1932 764183

Kamal Jardaneh XTP Dyce 44 (0)1224 833664 44 (0)1224 833586

Phil Hearn XTP Sunbury 44 (0)1932 763226 44 (0)1932 764183

Solids Management Paul Page XTP Sunbury 44 (0)1932 763125 44 (0)1932 764183

Formation Damage Sarah Browne XTP Sunbury 44 (0)1932 762068 44 (0)1932 764183

Well Clean-Up Dan Ryan XTP Sunbury 44 (0)1932 762859 44 (0)1932 764183

6-9

Section 7

Tubular Design and Running Guidelines

In this Section...

• ERD Well and Casing Program Design Issues

• Severe ERD Casing Running - Critical Casing Pickup Loads - Critical Casing Slackoff Weights

• Liner Running and Rotation

• Casing Wear - Wear Modeling - Wear Management - Wear Monitoring and Measurement

• Casing/Liner Centralization

• Tubular Design and Running Summary

• References

7-1

ERD WELL AND CASING PROGRAM DESIGN ISSUES

ERD tubular design differs from conventional casing design. Pressure considerations will be analogous to conventional wells, with the exception of influx and well control considerations inherent to long high-angle or horizontal sections (see Section 15, “Well Control Guidelines for Drilling High Angle or Horizontal Wells”). Pickup tension during running and bending from doglegs generates casing loads beyond those seen in conventional wells. For deep ERD wells, pickup tension may approach or exceed hoisting limits. In these cases, casing flotation may be required. For shallow ERD wells, it may be risky or impossible to run casings to section total depth (TD) using conventional running techniques. For these applications, a variety of modified running procedures and contingencies are detailed below.

ERD wells may pose significant uncertainty with regard to open-hole section stabilities and torques. The casing program should allow a contingency string or liner.

• One combination is a contingency 7-5/8 inch liner in a nominal 9-5/8 inch casing by 5-1/2 inch liner configuration.

• A second combination is a contingency 11-3/4 inch liner in a nominal 13-3/8 inch casing by 9-5/8 inch casing configuration.

High-clearance or flush joints will be required on the contingency string and on the nominal string run within the contingency liner, so make your connection selection for these strings carefully. If an ERD well requires the inclusion of additional casings to surface relative to the standard development wells, the requirement for a modified wellhead can result in lead times of up to 12-16 months. In terms of longer section lengths, ERD wells may pose significant logistical issues with regard to casing delivery and storage, especially offshore.

Several other special casing program modifications have been pursued or evaluated for ERD wells. The use of heavier weight and/or higher strength casing through intervals of possible casing wear is one example, although other casing wear mitigation methods are discussed below. In Statoil's deep ERD wells, the 9-5/8 inch casing was redesigned as a liner to improved runnability and to reduce equivalent circulating density (ECDs) while drilling the 8-1/2 inch reservoir section. This modification also allows the use of 5-1/2 inch DP with conventional tool joints above the 9-5/8 inch liner. After achieving total depth of the well and running the 7 inch or 5-1/2 inch production liner, the 9-5/8 inch liner is tied back to surface. For surveying requirements to accommodate a pump-down gyro inside the 9-5/8 inch, the 9-5/8 inch tieback was run for the survey then pulled from the well prior to drilling the 8-1/2 inch section. These types of special requirements are driven by specific well conditions, such as reservoir ECD limits and how critical the surveys are assessed relative to target certainty (see Section 11, “Hole Cleaning and Hydraulics” and Section 13, “Surveying Principles and Practice”). In this scenario, take care to protect the 9-5/8 inch PBR during drilling. Local drilling conditions and the need for contingencies drives the final casing program selected. Comprehensive load prediction, comprised of all conventional considerations and specific focus on running loads, then drives the individual casing and liner designs. With specific designs established, ERD casing running will then require careful attention.

7-2

SEVERE ERD CASING RUNNING

Successfully running casing to bottom is critical to getting the ERD well drilled and involves different challenges other than running pipe in vertical or moderately directional wells. Depending on the trajectory, true vertical depth (TVD), lubricity, etc. of the ERD well, the casing running job may be critical in terms of being able to pickup or run (i.e. "slackoff") casing at depth. These issues are discussed below:

Critical Casing Pickup Loads

In deep ERD wells, long casings can cause problems in terms of the rig’s maximum hoisting capacity. In these cases, it is important that running weight forecasting be carefully executed and that measures be identified to provide adequate safety margins for the casing job. One example of a case where hoisting limitations were critical was on Gyda South Well 2/1-A13. In this case, Drill String Simulator (DSS) was used to calculate up and down weights for the 9-5/8 inch casing at the section TD of 21280 ft. (6486m). Estimated up weight was 795 kips while estimated down weight was 394 kips (excluding traveling equipment). The maximum continuous load the drawworks can raise with 10 lines strung was 785 kips and the maximum pull was 886 kips. As a result of these conditions, it was recommended that the top 2625 ft. (800m) TVD (1000m MD) of the 9-5/8 inch casing be floated to reduce the running weight. Up and down weights were also to be closely monitored every 820 ft. (250m) during running to ensure actual weights were following DSS trends. The resultant reduction in buoyant weight was on the order of 100 kips. Collapse safety margins of the floated section of the casing were very high. and not an issue. Note that as a contingency for the possibility of float equipment failure, the mud could u-tube rapidly and leave the annulus underpressured. Thus, one mud pump should be lined up on the annulus so it can fill it with mud should the floats fail. The actual running weights from the Gyda South well where this partial floating technique was used to reduce running weight are shown in the following figure:

Gyda South 9-5/8" Casing Job

0

100

200

300

400

500

600

700

800

900

0 1000 2000 3000 4000 5000 6000 7000

Up Weight (kips)

Dow n Weight (kips)

Last 1000 m of casing not filled

7-3

Figure 7-1

7-4

Critical Casing Slackoff Weights

The severity of the ERD profile may prevent the casing from going into the well under its own weight, or it may have only slight downward weight. Forecasting casing running weights and planning for contingencies thus requires an understanding of casing drag.

Friction Considerations

Three factors determine the limits of running casing in an ERD well:

• The maximum available running weight • Frictional running weight losses • Mechanical running weight losses

The maximum available running weight is determined by the "sub-critical" portion of the well or specifically the TVD at which the critical friction angle is encountered. The critical friction angle (αc) is defined from the simple inclined block analogy for the well’s overall friction coefficient (μ). Specifically:

α c = tan − 1 1 μ

⎛ ⎝ ⎜ ⎞

⎠ ⎟ (7.1)

Overall lubricity determines the critical angle, thus critical angles vary depending on lithology, mud, and other factors. Critical angles have been reported in the range of 70°- 72°. At Wytch Farm, the lubricity of the OBM has resulted in a 12-1/4 inch open-hole friction coefficient of 0.21, which results in a critical angle of 78°. Lower friction, hence higher critical angles, have been seen on wells using synthetic OBMs. With the critical angle defined for a specific well, the maximum available running weight can be found by the buoyed casing weight at the TVD at which the critical angle is reached:

(Weight lbft

TVDmud

steel CsgCmax = −

⎛

⎝⎜

⎞

⎠⎟⎛⎝⎜

⎞⎠⎟1

ρρ α ) (7.2)

Above the critical angle, casing requires force to be pushed into the hole. This force constitutes the frictional loss of running weight. Frictional weight loss in a tangent section can be calculated by DSS or with the equation:

F Weight Tangent Lengthmud

steelCsg= −

⎛

⎝⎜

⎞

⎠⎟ −1

ρρ

α μ α ( )( )(cos( ) sin( )) (7.3)

7-5

An example of frictional casing resistance for 9-5/8 inch 40 lb./ft casing at various tangent angles with μ of 0.21 is shown:

9-5/8" Casing Running. Resistance

0

20000

40000

60000

80000

100000

120000

140000

160000

180000

200000

0 2000 4000 6000 8000

Tangent Section Length (m)

808284868890

Figure 7-2. Frictional casing resistance for 9-5/8 inch 40 lb./ft casing at various tangent angles with μ of 0.21.

7-6

These equations are provided for insight into the governing issues. For projections, DSS can be used to generate a running weight profile. An example profile is shown which illustrates how the maximum running weight and frictional considerations determine running limits:

DEPTH

CA

SIN

G W

EIG

HT

Sub-CriticalWell Section

Well SectionAbove Critical Angle

Maximum Running Weight

Frictional Weight Loss

Maximum Running Depth w/o Weight Assistance Figure 7-3.

Mechanical Weight Loss Considerations

Distinct from frictional losses, mechanical losses occur which reduce casing running weight. Mechanical losses can be caused by cuttings, casings, ledging, differential sticking, and centralizers embedding into formations. ERD casing running experiences showed mechanical losses can occur anywhere in open-hole and can be much larger than frictional losses. Mechanical weight losses may be as high as 100 kips while frictional losses may be much lower, i.e. 25 kips.

7-7

Circulation is usually effective in working through mechanical weight losses. As a result, fill-up/circulation tools are mandatory on critical ERD casing jobs to ensure that the string can be quickly circulated when problems appear. These tools, available from TAM, Frank’s, etc., are made up into the top-drive and allow simultaneous circulation and reciprocation of the string. This Wytch Farm casing job shows the effectiveness of circulation in removing excessive drag and restoring the casing running weight to normal levels.

F20 9-5/8" Casing Job.

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Figure 7-4. Wytch Farm casing job showing the effectiveness of circulation in removing excessive drag and restoring

the casing running weight to normal levels.

If local casing running experience indicates that conventional running procedures may pose unacceptable risks in terms of getting to bottom, various modified running techniques and contingency measures are available as discussed below.

Partial Flotation Techniques

Unocal developed techniques for partially floating casings in their Platform Irene ERD operations which are now marketed by Davis-Lynch. Flotation greatly reduces buoyed casing weight and frictional losses. The basis of partial flotation is to float the lower casing section which extends into the long tangent or horizontal section. At some depth, a sub is made-up into the casing which allows filling the casing above the lower floated section with mud. The upper section provides normal buoyant casing weight to push the floated section into the well.

7-8

Although early partial flotation subs were mechanical and required tripping in the casing with DP, the tools are now hydraulic. Their operation is designed in two stages, the first being a release of the seal at one pressure, and the second being a shearing of the tool internals as part of the cement job. The seal release allows venting of the air in the floated section and a complete filling of the string with mud. Circulation is then established, and the casing cemented. A lead or tail cement plug is used to fully shear the sub internals and leave the sub with full drift.

Field experience (Hamilton Brothers in Liverpool Bay using Davis-Lynch subs) was, however, that the process was effectively one-step. This was due to the pressure surge from the initial release pressure causing a shearing of the sub internals, with those internals falling to the casing float collar during filling and mud circulation. This outcome had no impact on the operation and the jobs were successful in terms of flotation function of the subs and the cement job. A diagram illustrating the tool and the technique are shown:

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Figure 7-5. Casing Floatation Sub

7-9

Design issues for partial flotation include:

• Optimum placement of the flotation sub • Shearing pressure margins

The releasing pressure must account for the initial hydrostatic imbalance between the mud-filled upper section and the lower evacuated (air-filled) section, and for pressure surges during running. Partial flotation precludes circulation while running, so selecting partial (or full flotation) relies on the prediction that frictional weight losses will dominate mechanical weight losses. In one Gulf-of-Mexico operation, an independent operator applied the Unocal partial flotation technique successfully only to find the casing moved freely after the sub was released and the casing had been fully filled with mud. This observation contradicted the pre-well prediction that the casing would not have remaining weight at the subject depth and, in this case, indicated that partial flotation may not have been required.

Full Flotation Techniques

ERD casings may also be fully floated. As with partial flotation, casing collapse must be checked and running weights projected. An additional issue is the casing may have little weight or in fact be buoyant. This impacts running equipment such as spiders and back-up tongs. If the projection shows that casing may be buoyant, slips should be acquired which can hold upward loads.

On Wytch Farm Well M3, the 9-5/8 inch 40 lb/ft C-95 casing was run to TD at 17,535 ft (5,346m) fully floated in a 10.4 ppg (1.25 SG) mud. This casing was buoyant and was pushed into the well using the top-drive and swivel. A drive-sub comprised of a drive shoulder welded onto a short DP pup was made-up into the top-drive. The drive-sub was lowered into the casing until the drive-sub shoulder contacted the coupling looking up. Top-drive and swivel weight were then applied to push the casing into the well. The M3 casing flotation was performed as a test to determine if the technique would work and to identify constraints and issues for its use on very long reach wells. The test was successful, although improvements were identified. On subsequent ERD well M5, the 9-5/8 inch was run to greater depths, i.e. 19708 ft. (6007m), with conventional mud filling and periodic circulation. Wytch Farm's experience to date has been that with good lubricity from OBM, their 9-5/8 inch casings can be run to bottom with conventional procedures and patience (pipe working) in the lower 12-1/4 inch section. The M3 casing flotation experience also shows that the procedure could be used for even higher departure wells with higher inclination and longer 12-1/4 inch sections.

7-10

Top-Drive Manipulation

As a contingency for unexpected problems while running casing conventionally, or as a planned procedure on very high departure wells (beyond those currently being drilled), procedures can allow top-drive manipulation of the casing to assist running. Top-drive manipulation could include the ability to circulate, reciprocate, rotate, and compress the casing. To provide these capabilities, a cross-over from casing to top-drive, high-torque casing connections and solid-body centralizers is required. The cross-overs should be made of integral stock and have at least matched-strength to the casing. Rotation of the casing by the top-drive would provide mechanical assistance in breaking up cuttings beds (and other obstructions) and removing friction. Rotation of filled casing would be limited due to high torque levels, but rotation of floated casing is predicted to be feasible even in deep sections.

Compression of the casing by the top-drive provides added running weight, and is applicable to filled or floated casing. Use of top-drive and swivel weight to compress the casing should be pursued only after analysis of the involved load path and component reactions. Analysis of the procedure on the Deutag T-47 rig, which has a Varco TDS-4H top-drive suspended under a National P-500 swivel, resulted in several conclusions. These involved the reaction of the load through the top-drive main shaft and into the swivel cover housing and the fact that the limiting structural factor was the swivel cover bolts. As a result, these bolts were changed to a higher strength type. Enhanced casing shoes should also be considered (i.e., the “Silver Bullet” float shoe developed by BP Colombia). For severe ERD wells, it should be clear that enhanced (ribbed and tapered) float shoes, flotation methods, and top-drive manipulation can be engineered to produce a casing running system capable of flotation and rotation to extreme TDs.

7-11

LINER RUNNING AND ROTATION

Completion types vary for ERD wells. If cemented liners are desired, liner rotation or reciprocation can be critical to improving cement bond. Rotation may also be critical to getting the liner to bottom. Without rotation, drag can accumulate to the extent that significant buckling (as discussed in the Torque and Drag Projection section) can occur leading to lock-up. Thus, liner running tools, hangers, and liner connections should be designed to allow rotation. This means all liner equipment must have make-up torques above torque levels which may be experienced downhole, i.e. as with drill strings, downhole make-up must be avoided.

If liner rotation is used, hangers should allow setting of the hanger, DP release, and rotation by setting DP weight back onto the hanger. Liner cementing torques will vary substantially. Torque variations occur due to buoyancy changes from the various densities of mud, spacers, and cements. Torque increases have also been observed during cement displacement into the annulus which are not accounted for by buoyancy. Sources for these torques include high friction between the liner and centralizers following contact with water-base spacers and/or cement invasion and the viscous effects of the cement. In addition to these “cement torque” components, torque spikes have been measured when the leading edge of the cement passes the liner top area. This torque spike is associated with the solids-laden lead cement interface passing the critical liner and hanger bypass areas. Lower liner torques can be engineered through use of specific "low-rheology" cements which also offer advantages in terms of ECDs. Thus, design of the liner, liner equipment, and cement slurry should be pursued in an integrated fashion. An example of liner torque behavior during cementing showing these effects is shown:

F21 Liner Torques During Cementing

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Figure 7-6. Liner torque behavior during cementing.

7-12

These torque behaviors make the liner and hanger torque capacities critical. To obtain high torque capacities, premium connections with torque shoulders should be used. Most premium connections, i.e. VAM, NK3SB, TC-II, NSCC, etc., have designs which are optimized around a metal-to-metal (M-M) gas seal. These types of premium connections have good torque capacities, but have not been designed for maximum torque capacity, nor are the published make-up torques for these connections their actual maximum sustainable torques.

Example: A modified VAM connection (known as VAM-4001) was produced for 5-1/2 inch 17 lb./ft L-80 pipe for increased torque capacity. The published optimum make-up torque for this connection is 8,250 ft-lbs. Physical testing showed the connection could sustain torque near 13,000 ft-lbs or nearly 60% above the recommended "maximum." This is one example of the design margins that typically exist on torque capacity of premium M-M seal connections.

Wytch Farm has additional experience in the qualification of 9-5/8 inch 40 lb./ft C-95 BOSS to nearly 40,000 ft-lbs, and ARCO has similar experience with high torsional testing of the Hunting/Kawasaki FOX connection.

No premium connections have been designed specifically for torque capacity except for the Hydril wedge thread. Hydril’s wedge thread involves interlocking pin and box dovetail threads that fully lock at make-up. As a result of the large “shouldering” area comprised of load flank, stab flank, crest and root areas, the wedge thread has very high torque capacity.

Example: Hydril’s 521 wedge connection for 5-1/2 inch 17 lb./ft L-80 is rated to about 24,000 ft-lbs for yield torque and has been run with 16,000 - 18,000 ft-lbs of make-up torque at Wytch Farm. These make-up torques have not caused any problems with the connections and are prudent given the above torque behaviors. It is necessary to ensure that proper tongs, dies, etc. are available so the torque can be applied without pipe-body damage. Once a proper liner torque rating has been developed, it should be added to cased hole surface torque taken at the shoe during the last (pre-liner) trip in or out of the well to establish a surface torque limit for the liner job.

A final liner issue is the setting of top-set packers above the hanger. Weight-set top set packers (TSPs) require significant compression be applied by the drill string at depth which can be difficult to achieve and measure in extreme ERD wells. An enhanced TSP setting system has been engineered by Nodeco for Wytch Farm which involved a bearing on the TSP setting shoulder. This bearing enhancement allowed the drill string to be rotated at slow RPMs while weight was applied to the TSP. Rotation of the string for this procedure eliminates frictional resistance to the weight application and allows for a more accurate surface assessment of how much weight has been applied.

7-13

CASING WEAR

Wear Modeling

A casing wear model from Maurer Engineering is available to perform sensitivity analyses for casing wear. The location of the predicted wear will correspond to intervals of high drill string-casing contact. As a result, contact loads predicted by DSS, Super Drill String Simulator (SDSS), or other torque/drag model provide an equivalent prediction of probable wear intervals. Although casing wear magnitude is calculated by the Maurer model, this is not viewed as a reliable prediction due to the extreme variations in wear factors that have been seen through field experience. A good correlation of wear factors may be possible within local operating areas. Use of the most conservative casing wear rates, i.e. those correlated from severe casing wear events, will likely result in the prediction of severe casing wear on any significant well. Conversely, use of the low range of wear rates can result in false confidence that wear will not be an issue. Casing wear prediction should not be viewed as quantitative unless wear factors have been validated by caliper data. Statoil are using wear factors for planning Statfjord and Gullfaks wells based on caliper log data. Focus should instead be placed on avoiding casing wear by implementing critical measures to minimize it.

Wear Management

Various casing wear management measures are inherent to several aspects of proper ERD well planning and execution and are thus likely to be addressed:

• Dogleg control

• Optimal trajectory design

• Minimizing rotating hours

• Increased wear tolerance (WT)

• Increased strength - progressive integrity

Use of Drill Pipe Protectors (DPP) for casing wear avoidance across intervals of probable wear is an additional measure, but more direct means of wear control are recommended.

Substantial experience indicates casing wear can be minimized with chromium alloy hardfacings. These materials were identified in joint-industry research and have been field tested by major operators. Despite overwhelming evidence that tungsten carbide hardfacings wear casing even in their most benign forms, tungsten carbide hardfacings remain in use and are repeatedly associated with serious casing wear failures. The success of new hardfacings in avoiding casing wear and the repeated correlation of casing wear with tungsten carbide should be appreciated when planning ERD projects. The cost of hardfacing a drill string is minimal compared to the cost of a single casing wear failure.

To date, no casing wear failures have occurred with the new hardfacings anywhere in the world under normal drilling conditions. One casing wear incident was reported in Colombia but involved extremely high rotating hours in the involved hole section due to the challenging drilling conditions in that operation. The bulk of current experience with the new hardfacings is with Arnco-200XT and Armacor-M, but other alloys exist and may also become qualified.

7-14

To minimize steel-to-steel wear caused by contact between the base tool joint material and casing, these hardfacings should be applied proud by 3/32 - 1/8 inch and may be used in the as-welded state. However, these new hardfacings must be applied properly. Parameters for their application, i.e. welding temperatures, etc., vary from tungsten carbide, and shops need to demonstrate that they can provide reliable application. Experience indicates that attempting to apply these hardfacings without proper technical support from the supplier can cause significant problems, including debonding of the hardfacing from the tool joint.

Wear Monitoring and Measurement

Ditch magnets should be run and the recovered metal weight reported at least daily. This will allow trends to be established. No guidelines for correlating metal recovered to the degree of wear are currently available, but data may be collected from offset wells and industry ERD wells to establish empirical guidelines in the future. At a minimum, specific trends on wells can allow identification of any significant increases in recovered metal thereby warning of possible casing wear. There are three wear mechanisms:

Mechanism Will produce...

Galling flake-like debris.

Machining long chips or “steel-wool”.

Grinding a fine powder.

Examination of the metal recovered can help identify the wear mechanism and therefore the severity as galling and machining are two to three orders of magnitude greater in terms of wear rate. For casing wear logging, various tools are available including mechanical multi-finger calipers, such as Schlumberger, Kinley, and Sondex. Ultrasonic inspection tools are available from Schlumberger and Halliburton. Since all casing wear inspection logs can be affected by centralization and calibration issues, nominal remaining thickness should be established by the minimum radius indicated by the tool itself. Wall loss can then be evaluated based on the difference between the maximum and minimum radius indications. Casing wear in ERD wells should be oriented on the high side in the upper section of hole, then transitioning to low-side orientation near the end of the build and throughout the long tangent and horizontal sections.

7-15

CASING/LINER CENTRALIZATION

Centralization for ERD well tubulars is an area of ongoing debate. Claims are made that centralizers reduce casing running friction by providing “sleds” or “skis” for the casing to “glide in the hole.” These claims are controversial but centralizers can often add to frictional running weight losses. This effect is difficult to isolate with field data, but it can be clearly observed in the following figure:

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Hookload (Metric Tons)

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Weight in MudUpstroke (theor.)

Downstroke (theor.)

Upstroke (actual)Downstroke (actual)

Agostino 34 Dir

Activated DAC

Figure 7-7.

Figure 7-7 shows up and down weights on casing which used downhole-activated centralizers or DACs. Weatherford's DACs are bow-type centralizers which are restrained when run. Downhole, they are released by pressure and expand to normal size. As shown above, as the DACs opened below 800m, they added incremental drag to the casing string. It is considered likely that centralizers will also add incremental drag in ERD wells. Thus, centralization should be minimized and solid-body centralizers are preferred.

Bow-type centralizers are not acceptable products for high-inclinations. Although some may argue double-bow or “semi-rigid” styles are acceptable, these still pose substantially more risk than a solid-body centralizer. Common practice for the intermediate casing is to run only about 6-8 solid-body centralizers in total over the bottom few joints to assist is securing pressure isolation at the shoe. Centralization back up the hole, i.e. around DV tools, inside the previous shoe, or at the wellhead, does not affect runnability of the string and can be pursued per normal policy.

7-16

M5 TORQUE DURING LINER CEMENTING

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For ERD liners, centralization should be designed to provide good standoff of the liner. Since the liner should be rotatable during running, solid-body centralizers should be used, and they may be used in greater numbers than for casing. The type of solid-body centralizer used should also be considered. Experience has been related from Shell in the North Sea where a liner was pulled from a high-angle well due to problems with the hanger. Upon retrieval of the liner, severe wear of the aluminum solid-body centralizers was noted. As a result, solid-body centralizers are now offered using zinc-based alloys, which are tougher and more wear resistant than aluminum. As solid-body centralizers are almost all manufactured using casting techniques, zinc-based materials should be available from a variety of manufacturers at minimal premiums compared with aluminum. In some cases, solid centralizers can significantly reduce liner torque.

TUBULAR DESIGN AND RUNNING SUMMARY

• ERD wells, particularly in a new area, should include contingency liner options due to uncertainties with open-hole stabilities and drilling mechanics (torque, drag) trends.

• In certain applications, special casing programs such as the design of 9-5/8 inch as a liner/tieback may be required to address ECD and surveying issues.

• ERD wells impose more critical running load scenarios which may exceed hoisting capacities and thus require rig/equipment upgrades or flotation running procedures.

• For shallow ERD wells or severe profiles, casing may not be reliably run to bottom under its own weight. In these cases, full or partial flotation, top-drive compression, and even top-drive rotation are available measures to develop effective running procedures.

• ERD production liners should be designed for rotation. That design process impacts liner connections, the liner hanger and running tools and the drill string design. For top-set packers, special modifications to allow drill string rotation during TSP weight setting may be advised.

7-17

• Minimal intermediate casing centralization is generally recommended to improve runnability. Liner centralization can be extensive.

• Casing wear is a serious risk on all ERD wells. ERD drill strings should be rehardfaced with chromium alloy hardfacings. Additional measures are inherent to optimal well design and drilling, and may include the use of non-rotating Drill Pipe Protectors (DPP).

7-18

REFERENCES

1. Ruddy, K. E. and Hill D., "Analysis of Buoyancy-Assisted Casings and Liners in Mega-Reach Wells", IADC/SPE 23878, 1992 IADC/SPE Drilling Conference, 18-21 February 1992, New Orleans.

2. Bell, R.A., Jr., Hinkel, R.M., Bunyak, M.J., Payne, J.D. and Hood, J.L., III., "Application of Innovative Extended Reach and Horizontal Drilling Technology in Oilfield Development", IADC/SPE 27463, 1994 IADC/SPE Drilling Conference, 15-18 February, 1994, Dallas, Texas.

3. BPX Hardfacing Specification, BP XTP, August, 1994.

4. BPX Casing Design Manual, Section 10.

7-19

Section 8 Cementing

In this Section...

• Option Selection - Considerations When Selecting ERD Candidates - Theory and Introduction

• Pre-Drill Data Package - Required Prospect Information

• Well Planning - Feasibility Through Detailed Drilling Procedures - Equipment

• Slurry Design and Testing Requirements

• Implementation - Operational Issues, Rig Practices - Cement Placement and Mud Removal

• Centralization - Setting Cement Plugs in ERD/Horizontal Sections

• Post Analysis/Performance Measurement

• Wytch Farm Case History - ERD Stage III Development - Wells F18-F21 and M-1-M15 - Future Wells

• References

• Contacts

8-1

OPTION SELECTION - CONSIDERATIONS WHEN SELECTING ERD CANDIDATES

Theory and Introduction

Cementing ERD wells is more challenging because of:

• Generally higher mud weights required for wellbore stability • Poor hole cleaning and possible pack off when circulating casing • Poor knowledge of hole size • Mud losses

The high angle hole and high step-out of ERD wells make it significantly more difficult to displace drilling mud and place cement, than in conventional drilling applications. This makes several factors even more critical in the cementing of ERD wells. These factors include equipment selection, slurry and spacer properties, job design, centralization, and pipe-movement.

The success of the entire project can hinge on getting a good cement job. Failure to do so may result in inability to isolate water or thief zones, resulting in poor productivity and potential high treatment costs.

An excellent and recommended reference is the BPX Horizontal Well Drilling Manual (1990), the majority of which holds true for the greater part of cementing in ERD wells today. Some slight differences, which account for hole angle variations and recent advances in drilling technology, are covered here.

The factors which need attention to detail over-and-above the normal practices for conventional cementing are:

• Planning • Equipment • Cement placement • Centralization • Slurry Designs

8-2

PRE-DRILL DATA PACKAGE - REQUIRED PROSPECT INFORMATION

It is critical at this stage to define the cementing objectives. Questions to identifying objectives that are critical and those which are "nice to have", include:

Structural Engineering Issues

• Buckling • Casing wear • Trapped pressure in sealed annuli during production

Planning Issues

• Possible future side-track potential • Well abandonment issues • Zonal isolation • Temperatures (see later) • Pore and fracture gradients, particularly any possible variation in pore pressure in

horizontal sections which may result in cross flow after cementing

8-3

WELL PLANNING - FEASIBILITY THROUGH DETAILED DRILLING PROCEDURES

Planning, Design, and Acquisition of Equipment

Planning and an integrated approach are critical. Planning, operational decisions, and changes can significantly impact the success of the cement job, and vice versa.

Cement placement simulations and pilot testing should be carried out at least 2-4 weeks in advance, to allow time for any necessary changes to the design. A final slurry test must be done with samples of materials to be used on the actual cementing operation.

There may be long lead times for the acquisition of special float shoes, stage collars, and combination plugs (> 6 weeks). These, together with stage tool requirements, should be planned well in advance.

Equipment

Side-Ported Float Shoes

It is good practice to run an extended shoe track on ERD wells, particularly when only top cement wiper plugs are used (e.g. liners). Common practice is to run 3 or even 4 joints to prevent contaminated cement being displaced into the annulus. New developments such as extending and side-ported float shoes, float shoes with hard banding (or even polycrystalline diamond compact (PDC) inserts), and hole finding shoes (bullet shoes or Weatherford hole finder) , are particularly useful for washing down casing through long and troublesome sections. The side-ported float shoe also improves all-round cement placement directly at the shoe. A number of these shoes are available (Ray, Davis Lynch, Halliburton, and Weatherford), most of these being PDC drillable.

Auto-fill float equipment and spring-assisted valves (not ball types) may be useful in highly deviated sections. Use double float valves where part of the shoe track is to be drilled for liners with one below clean out depth in liner shoe track since cement quality in shoe track of ERD casing strings and liners is usually poor.

Cementing Heads

There are no ERD specific issues. However, there may be issues where tapered strings are used. There may be some benefit from remote release heads on safety grounds and to minimize U-tubing, since plugs can be launched without stopping displacement.

8-4

Plug Systems

• Casing - For Subsea launched plugs, the main issues are PDC

drillability and anti rotation. Recent success has been achieved using the Halliburton system. However, not that it is not possible to launch Halliburton plugs using a 6-5/8 inch running string. With extended shoe tracks there has been downside in launching top plug only on ERD wells. With 6-5/8 inch by 5 inch tapered running strings, plugs may leave cement in 6-5/8 inch.

For surface-released plugs, the main issues are anti-rotation and pressure testing capability. Systems are available from Weatherford and Halliburton (high pressure versions may be needed with Halliburton).

• Liner - It is not common practice even on very long liners, to use top and bottom wiper plugs. Launch darts are available for use in 6-5/8/5-inch combination running strings.

ECP

ECPs can be used for additional contingency isolation when cementing long sections. Cement inflated packers are generally more durable than mud inflated. We do not recommend mud inflating an ECP after cementing, as failure of the ECP may impact the cement quality. The main role of ECPs are seen when run in combination with stage or full opening (FO) collars, to prevent fluid migration / cross flow where it has proved impossible to solve in a primary cementing operation (e.g. gas migration, aquifer isolation). Good results have been achieved using Baker (CTC) tools.

Stage Tools

Hydraulic stage tools are preferred because of problems getting opening bombs to land in high angle wells. Liner stage tools are particularly useful for cementing long sections where high ECD may result in losses and poor zone isolation. Care must be exercised when using a hydraulic stage tool on liners with a number of hydraulically operated components, particularly if a loss zone was covered by first stage where an integral stage tool / ECP would be required. For 9-5/8 inch casing jobs, Davis-Lynch stage collars have been used with good success.

8-5

SLURRY DESIGN AND TESTING REQUIREMENTS

Acceptable Slurry Properties

Slurry testing must be carried out with representative samples of cement and additives from the rig, prior to cementing. Use of different cement samples (though the same manufacturer) can result in cemented pipe. By nature, ERD cementing slurry volumes can be large and carry an increased risk of using multiple batches of cement. Where possible, a single batch should be used. Otherwise, all component batches should be tested independently.

Slurry density control is also critical, particularly since batch mixing is often not an option with large slurry volumes. Density control during the cement job should be kept to Design density +0.1 ppg/ -0.2 ppg (e.g.. for a 16 ppg slurry 15.8 ppg to 16.1 ppg). Mixing over the design density reduces the available slurry pumping time and risks cemented pipe. Mixing below target density risks poor cement quality (free water, fluid loss, rheology). Lab testing can determine thickening time sensitivity to density changes. Batch mixing is still the best way of controlling slurry density. However, where slurry volumes prevent this, a recirculating mixer should be used (when mixing on the fly, slurry quality is only as good as the bulk supply).

If batch mixing slurry, be aware that high shear can significantly reduce thickening time. Once mixed, the slurry should be agitated with low shear paddles and not continually recirculated.

Stability and Settlement

Critical slurries should be designed with zero freewater and low settlement to prevent communication along the topside of the hole. Use the BP settlement test procedure. As a general rule of thumb for horizontal liners, reduction in height of the cement column must be less than 3mm (1 mm preferred) with a change in density gradient from top to bottom of no more than 0.5 ppg.

Design Temperatures

Design temperatures are critical to the success of the cement operation. With high step-outs and long sections, bottom hole circulating temperature (BHCT) is frequently much higher than API tables predict, because the slurry spends more time exposed to formation close to bottom hole static temperature (BHST). Using API tables for design temperatures in ERD can seriously risk flash set of the cement. Measurement while drilling (MWD) temperatures should not be solely relied upon, since these cannot accurately predict temperature at the time of the cement job. Temperature modeling programs are needed to predict BHCT accurately. The BPX recommended simulator is Welltemp by Enertech (a new PC version - Wellcat - is now available). The temperature model in Cemcade also gives acceptable results, though it may be less reliable when fluids (mud and or brine) are in turbulence. BHCT needs to be calculated several weeks in advance to allow for adequate slurry design and testing.

8-6

Thickening Time Verification

Thickening time tests need to simulate the job as closely as possibly. API testing procedures are a starting point, but additional testing needs to take into account surface mixing time, placement time, and expected temperature/pressure. Pumping time needs to account for all operations and safety. For lead slurries, there is usually no down side from having thickening time equal to twice the job time on an ERD well (except where gas migration is a consideration). For tail slurries and liners, pumping time should be based on job time (at lowest expected displacement rate assuming total losses) plus time for shutdowns (e.g. setting liner top packer) plus at least two hours safety margin.

• Lab thickening time (TT) should be performed at expected temperature (see design temperature) and at +/- 15° F (10° C) of design temperature (guideline only) to check for sensitivity to temperature variation. This is critical where temperature recommendations above have not been completed.

• A second sensitivity test is recommended for retarder concentration. Test at design concentration of retarder and at +/- 0.02 gal/sk or +/-10% of retarder (guideline only). If TT is significantly different between tests, re-design may be necessary using an alternative retarder. If slurries are sensitive and re-design would compromise optimum slurry, precautions must be taken to ensure accurate additive addition (premixing mix water and eliminating the liquid additive system (LAS), re-calibrating the LAS, or using a computer-operated LAS).

IMPLEMENTATION - OPERATIONAL ISSUES, RIG PRACTICES

The following factors have all been shown to save time (stuck-pipe prevention) and have improved cement job quality in ERD applications. Neglect them at your peril.

• Cement Job simulation of ECD and cement placement (including U-tubing) • Welltemp design temperature modeling (API spec may not be appropriate for ERD) • Pipe rotation and reciprocation • Good centralization • Side-ported float shoes • Zero settlement in BP settlement test • Zero freewater • Slurry density control to within +/- 0.1 ppg • Testing with representative samples • Slurry Volumes to guarantee zone coverage • Liner top packers and removal of excess cement • Slurry design and testing

8-7

Cement Placement and Mud Removal

Optimizing Cement Placement

Isolation and good cement placement requires careful planning and optimization of all cementing parameters, including:

• Good centralization ( >80%) where good zonal isolation is critical • Reduced mud viscosity and gels for good mud removal • Fastest displacement rate as possible (washes and spacers should be designed for

turbulent flow) • Pipe movement (preferably rotation) - the impact on pipe make up torque needs to be

considered • Spacer weighted to halfway between mud and cement • Spacer viscosity less than cement but more than mud • Conditioning mud prior to the cement job

Consideration needs to be given to the impact such parameters might have on other factors such as:

• ECD (See Section 11, “Hole Cleaning and Hydraulics”)

• Swab and surge pressures (See Section 11, “Hole Cleaning and Hydraulics”)

• Barite sag (See Section 6, “Drilling Fluids Optimization”)

• Hole cleaning (See Section 11, “Hole Cleaning and Hydraulics”) Cement Placement Simulation

All Cementing Service Companies and BP (via DEAP) are capable of predicting ECD, surface pressures, and U-tubing during cementing operations. DEAP, BJ Services new version of Cemfacts, and Dowell's Cemcade can model the actual mud displacement process, enabling spacer and cement rheologies and densities to be optimized using engineering criteria.

Liner Cement Volume Selection

It is rare to have caliper data on which to base volumes on an ERD well. If calipers are available for offset wells, the degree of washout and excess on gauge hole should be based on the offset data. If no data is available, the recommendation is 20% on 5-1/2 inch - 8-1/2 inch OH geometry and 30% on 7-inch - 8-1/2 inch geometry. Where a caliper is available, pump 10% excess on caliper or those on OH, whichever is greater.

8-8

Spacers

Turbulent flow spacers are preferred. Where turbulence cannot be guaranteed because of large annulus and low displacement rates, laminar flow spacers should be designed. These should be thicker than the mud, but thinner than the cement. Single spacers should also be weighted halfway between the mud and cement, to enhance removal of fluids by the buoyancy effect.

Spacer trains of two or more spacers can enhance mud removal and/or reduce ECD. For example, using a turbulent water-wetting flush ahead of the weighted spacer, if pore pressures permit. An additional bottom plug is recommended to separate the spacers. However, for liners where no bottom plug is employed, intermixing of spacers is possible, and they should have a minimum volume of 50 bbl. When a wash and a weighted spacer mix, the benefits of both are reduced. With long casing strings in a poorly cleaned hole, pumping a turbulent flow wash ahead may increase the possibility of a pack off.

Where fracture gradients are low, large low-density pills (treated water or base oil) ahead of the spacer significantly reduces the ECD during cementing, to reduce losses. Pay attention to well control issues. Chemical compatibility tests should be done to identify optimum spacer selection.

Pipe Movement

Pipe movement greatly increases effective mud removal and cement placement, particularly on the narrow side, and should be used to compliment good centralization. Rotating liner hangers allow the liner to be hung off prior to cement placement. Rotation also causes a swirling effect which reduces channeling. Reciprocation can risk getting stuck, particularly on the up-stroke.

Lubricity

Lubricity additives and friction reducers may also help reduce ECD and rotational pipe torques.

8-9

CENTRALIZATION

Calculating Stand-Off

Stand-off is the parameter used to define the eccentricity of the annulus, where 100% stand-off is a perfectly centralized casing. For critical cement jobs, particularly liners, minimum stand-off should be no less than 70% (preferably 80-85%). Poor stand-off generally results in poor cement placement in the narrow side. The calculation for stand-off is shown as follows:

Stand-Off = (W/Rhole-Rcasing )* 100 (8.1)

Legend: W = Minimum gap R = Radius

100% STANDOFF STANDOFF = 100[(x-y)/x] %

x = (hole diam - casing diam)/2

x x

x+y

x-y

Wellbore Center

Casing Center

Figure 8-1.

x+y

d

wellborecasing

centralizer

d = deflection (ins)

minimum standoff = 100[(x-y-d)/x] %

x-y

Figure 8-2. Refer to Section 7, “Tubular Design and Running Guidelines” for a discussion of centralizer selection.

8-10

Stand Off at the Centralizer

For rigid centralizers, this is easily calculated:

An 8-3/8 inch rigid centralizer on 7 inch casing always gives a gap between the casing and hole of (8.375-7)/2 = 0.6875”, no matter what the hole size, because the centralizer will always be against the hole as a worst case.

Standoff at the centralizer in 8-1/2 inch hole is therefore: (0.6875/0.75) x 100% = 92%.

Note this will reduce as hole size increases, e.g. standoff at the centralizer in 9-1/2 inch hole is: (0.6875/1.25) x 100% = 55%.

For bowspring centralizers, charts of API restoring force tests must be consulted for the type of centralizer to be used.

As an example, the Weatherford charts for a standard 7 inch casing centralizer give a gap of 0.668” for a restoring force of 1120 lbs. Standoff using once centralizer per joint is therefore: (0.668/0.75) x 100% = 89%.

Using two centralizers per joint, a restoring force of 1120/2 = 560 will give a gap of 0.723 feet. Standoff will be: (0.723/0.75) x 100% = 96%.

Using one centralizer every two joints, a restoring force of 1120 x 2 = 2240 lbs will give a gap of 0.545 feet. Standoff will be: (0.545/0.75) x 100% = 73%.

8-11

Standoff Between Centralizers

Casing will sag to some extent between centralizers, whether rigid or bow. Deflection is calculated using the formula:

d = s5*w*sinJ/192*P4/[(s3*t/26*P2) + (h4 - c4) *s * P * 117188]

Where:

d = additional gap from sag effect, ins

s = space between centralizers, ins

w = casing weight, lbs/ft

J = deviation angle of well, deg

t = effective tension in casing, lbs (from DSS)

(NB. can be negative, for compression)

h = hole diameter, ins

c = casing diameter, ins

P = Pi

Standoff between centralizers is then calculated by the formula:

Standoff = 100[2(gap at centralizer - d)/h-c)] %

(all units in inches)

In this example, using 1 bowspring centralizer per joint gives a deflection of 0.081” and minimum standoff of: [2(0.668-0.081)]/1.5 x 100% = 78%

Using 1 bowspring centralizer every two joints gives a deflection of 1.269” and a negative minimum standoff, i.e. casing is lying against the side of the hole. For any horizontal 8-1/2 inch hole with 7 inch casing, the same result will apply. So one centralizer every two joints is unacceptable.

There is some advantage in placing centralizers half way along a joint instead of close to or over the couplings, as the couplings themselves provide a small amount of standoff and may help to reduce the sag between the centralizers.

8-12

Setting Cement Plugs in ERD/Horizontal Sections

This has been a serious problem on many wells to date. For wells from 0 to 80 deg, setting using a conventional stinger is acceptable. However it is recommended that a firm base is set on the hole, preferably use of the new BJ Parabow tool. Alternatively use a weighted, viscous reactive pill built from bentonite and sodium silicate as the second choice. In addition a minimum plug height of 500 ft in 12 1/4" section and 750 ft in 8 1/2" section are recommended with 30% xs on OH if no caliper is available.

Setting a plug in a horizontal section may require additional consideration, depending on the condition of the hole. Several successful cement plugs have been set in very high angle and horizontal 8 1/2" holes in Wytch Farm using 220m 2 7/8" stinger and rotating pipe during placement. The procedures are attached in the appendix as guidelines, but it should be noted that the mud weight was only 0.94SG (7.8ppg) which assists the mud removal in this case.

For washed out or problematic horizontal hole the proposed technique (as yet unused) is to run in with 500 ft of centralized pipe (aluminum or composite), set a balanced plug around the "open hole liner" and release from the top of sacrificial pipe.

HORIZONTAL CEMENT PLUG SETTING PROCEDURES (WYTCH FARM)

Very high angle and horizontal cement plugs have been successfully placed on several Wytch Farm wells in 8.1/2" hole. The following procedures have been developed from that experience. It should be noted that the mud weight is only 0.94 sg (7.8 ppg) and this probably assists with mud - cement separation.

1. Aim to set a 150m plug. Top of cement is usually found 20 - 40m lower than expected.

2. Use a 220m 2.7/8" DP stinger.

3. Rotate the pipe whilst spotting the slurry.

4. Don't worry too much about trying to balance the plug with the spacer as this is not very critical in high angles.

5. Pump 40 bbls of spacer ahead of the cement at 1.50 sg. Follow the cement with 5 bbl spacer.

6. Displace the lead spacer into the annulus at high rate.

7. Displace the cement slurry into the annulus at a slow rate, 2 bbl/min, rotating the pipe throughout. In order to calculate the displacement volume, use the measured capacity of the drillpipe (preferably by calibrating it experimentally). Our experience is that 5" 19.5 lb/ft pipe is 0.0172 bbl/ft (not 0.01776). Dart type indicators have not been used but should assist if there is doubt over drillpipe capacity.

8. Underdisplacing on its own will not cause cement to fall out the bottom of the pipe. Therefore pump a heavy slug as the final part of the displacement. Also under-displace to prevent U-tubing (say 10 bbl).

9. POOH from cement very slowly at 3-5 minutes per stand (a stopwatch is useful as this is very slow!).

10. Once above the cement, circulate conventionally at a high rate while rotating the pipe (watching closely for losses) to clear cement from the pipe. Do not reverse circulate if there is a danger of initiating losses.

8-13

POST ANALYSIS/ PERFORMANCE MEASUREMENT

Acquisition of caliper and cement bond information is difficult in ERD wells. However, indication of hole size can be obtained with MWD density tools. The attached case history shows a good example of a post analysis process for cementing.

8-14

WYTCH FARM CASE HISTORY

ERD Stage III Development - Wells F18-F21 and M1-M5.

Well F18

• Data (example early well):

Table 10.1 Early Well Data

Date of Job Hole Size Casing MD (m) TVD (m) BHST (ºF) BHCT (ºF)) 19/4/93 24 inches 18 5/8 234 234 71 64

30/4/93 17 1/2 inches 13 3/8 927 670 95 79

11/6/93 12 1/4 inches 9 5/8 (2 stage)

2136 3686

1000 1545

112 142

90 110

28/6/93 8 1/2 inches 5 1/2 4449 1667 146 113

• Use of 5-1/2 inch liner in 8-1/2 inch hole to reduce ECD, because of low frac gradient. Would prefer 7-inch to allow larger tools inside liner.

• Cementing policy put together by BP Sunbury for optimizing Liner cementing practices (Wytch Farm specific).

• Inability to run 9-5/8 inch casing to TD with recommended number of bow type centralizers, probably due to high friction and ledging below the 13-3/8 inch shoe. Casing was eventually run slick apart from two centralizers around stage collar. Intend to run solid undergauge centralizers in future. Don’t run many centralizers on 9-5/8 inch.

• Ran two ECPs on liner as additional water shut-off. Only partial success, with poor inflation indicated.

• Good Liner CBL. Well Description/Result F19 • Centralizers for 9 5/8 included 5 x semi-rigid and 10 x solid spiral centralizers. Liner utilized 2

spirals per joint.

• Good 9 5/8 and liner CBL.

F20 • Underdisplacement on liner cement job of approximately 30bbls, coinciding with time that cement reached liner hanger. Suspected cuttings pack-off at liner packer (cement acting as a viscous pill).

• Good 9 5/8 and liner CBL.

• ECP failure.

F21 • No underdisplacement problems seen on liner.

• Used 40lb/ft 9 5/8 inch instead of 43.5lb/ft casing at the liner hanger, to give approximately 25% more annular clearance.

• Used viscous sweep prior to liner cement job to remove any cuttings.

• Decided not to run additional ECPs on liner, since confidence in cement quality was good.

M1 • No 8 1/2 drilled.

8-15

M1 • No 8 1/2 drilled.

Well Description/Result M2 • Several problems on liner cement job contributed to cement setting up inside liner and no cement

in annulus.

• Significant change in cement batch properties and consequent testing of non-representative samples, lead to incorrect properties in slurry pumped, resulting in reduced thickening time. Changed out cement manufacturer, added additional cement silo for intermixing batches, and improved sampling and testing procedures.

• Cement unit pumps failed three times during cement job. Back-up pump unit (truck) recommended in future.

• Temperature modeling highlighted need to raise test temperatures for 9 5/8 and liner, well above API recommendations, as a result of longer exposure to formation temperature in highly deviated sections. Liner BHCT raised to 141degF (very close to BHST of 146deg F).

M3 See Table 10-2, M3 Late Well Data

M4 • Special case well (Frome), which targeted a shallow depth sand. The horizontal liner was an open hole completion using three cement inflated ECP’s.

M5 • Successful record well.

• 8km step-out.

• 2.9km horizontal liner cemented successfully.

• These practices are recognized as having vastly increased the chances of a successful liner cement job at Wytch Farm:

• Planning with DEAP CPS - Cement placement simulations helped considerably in optimizing necessary volumes, flow rates and rheologies to reduce ECD’s. This was critical for the prevention of losses and ensuring good cement placement in a formation with such a narrow window between the pore pressure (c. 0.92 SG) and the low frac gradient (c. 1.02-1.06SG).

• Good centralization - Two solid zinc alloy spiral centralizers were run per joint of liner, giving approximately 80% stand-off. Zinc-alloy centralizers are used in preference to aluminum, because they are much harder and resistant to wear in long runs. There is also evidence that zinc-alloy may be a better bearing material. (Reduced friction coefficient)

• Reduced ECDs - 400 bbls of base oil pill, ahead of a reduced density weighted spacer (1.35SG) helped minimize hydrostatic head and reduce the ECD in the low frac gradient reservoir.

• Back-up cement pumping unit - A contingency pumping truck was hooked up and ready should the site cement unit have failed during the job. The low frac gradient meant that in the event of a problem, it would not be possible to (reverse) circulate out cement.

• Good sampling procedures - Written sampling procedures which were strictly followed, including clean, well labeled containers for large samples.

• Good quality slurry - The slurry was designed for zero settlement (critical), long thickening time, but short strength development, fluid loss <100ml and reasonably low rheology.

• Rotation - Rotation was maintained throughout the job at torques less than predicted. Torques were reduced by good liner centralization an centralizer type.

• As low a mud weight and rheology as possible - critical for reducing ECDs.

• Closely monitor losses throughout the cement job - reduce/increase displacement rate accordingly.

8-16

Table 10-2

M3 - Late Well Data Date of Job Hole Size Casing MD (m) TVD (m) BHST (°F) BHCT (°F) 28/12/94 24 inches 18 5/8 218 218 71 64

2/1/95 17 1/2 inches 13 3/8 854 744 100 84

25/1/95 12 1/4 inches 9 5/8 (2 stage)

2210 5338

1007 1557

112 142

105 125

8/3/95 8 1/2 inches 5 1/2 7259 1596 146 141

• With increased step-out and longer liners, there was a need to reduce ECDs. This was achieved by reducing mud density and viscosity, reducing spacer density and volume, and by pumping a large base oil flush ahead of the spacer.

• Unable to run logging tools on coil tubing due to high step-out.

Future Wells

• CBL will not be attempted on future wells, unless a problem is indicated during the cement job (i.e. no rotation/ high losses/ no returns). This is because three CBLs to date have shown good cement quality and there is no indication that cement job quality has changed. There is also the added problem of trying to run logging tools successfully to TD.

• A large mixwater preparation tank (800bbls) is proposed for future liner jobs, to ensure mixwater consistency throughout the job and to allow testing of the mixwater prior to cementing.

REFERENCES

1. BPX Horizontal Well Drilling Manual, Cementing section (1991).

2. 'BP Settlement Test improves Measurement of Cement Slurry Stability' C. Greaves and A.P. Hibbert (1990) Oil and Gas Journal, Feb. 12 1990.

CONTACTS

Specialty Name Location Telephone Fax Robert Dallimer XTP Sunbury 44 (0)1932 764136 44 (0)1932 764183

Daryl Kellingray PSR Dyce 44 (0)1224 833571 44 (0)1224 833577

Chris Greaves BPX Colombia 57 1 623 4077 57 1 618 3215

8-17

Section 9 Drill String Design

In this Section...

• Non-Cyclic Load Trends - Torque - Tension and Combined Tension/Torsion - Estimating Non-cyclic Loads in a Well - Handling High Non-cyclic Loads - Reduction and Redistribution of Non-cyclic Loads - Cyclic Loading and Fatigue - Buckling - Cyclic Stress Induced by BHA Sag

• Other Drill String Design Issues - Annular Velocity and Drill Pipe Size - Hydraulics and Drill Pipe Size - Casing Wear Issues - Jar Placement - Drill String Inspection Practices

• References

9-1

INTRODUCTION

The primary differences in mechanical design issues that separate ER from more conventional drill string design are:

• The magnitude of expected drill string loads • The need to apply bit weight with normal weight drill pipe

Aside from these mechanical issues, several other interdependent considerations come into play when selecting drill string components for an ER well, as shown in Figure 9-1. We use an iterative three-step process to optimize our drill string configuration:

1. Use torque-drag software to estimate the non-cyclic loads that the drill string will experience.

2. Select components that can safely carry these loads. 3. Reduce or redistribute the loads as required by modifying the drill string, the trajectory,

the mud properties, or the casing program.

Another important mechanical consideration for ER drill string design (not shown on Figure 9-1) is fatigue mitigation. Fatigue is discussed in this section after the discussion of non-cyclic loads.

9-2

NON-CYCLIC LOAD TRENDS

TORSIONFATIGUE (BUCKLING, BENDING)TENSIONCOMPRESSIONPRESSURE

1. DETERMINE THEEXPECTED LOADS

2. SELECT THEDRILL STRINGCOMPONENTS(DESIGN)

3. VERIFY EACHCOMPONENT'SCONDITION

4.

5.

SET OPERATING

LIMITS FOR RIGTEAM

MONITORCONDITION

DURING DRILLING

ECONOMIC ISSUES

AVAILABILITYLOGISTICSCOST

RIG ISSUES

STORAGE SPACESETBACK SPACEACCURACY OF LOAD INDICATORSPUMP PRESSURE/VOLUME CAPACITYTOP DRIVE OUTPUT TORQUE

HOLE ISSUES

HOLE CLEANINGHOLE STABILITY

CASING WEARHYDRAULICS, ECD

DIRECTIONAL OBJECTIVES

OTHER ISSUES

JAR PLACEMENTMUD TYPE & WEIGHT

Figure 9-1. ER well Drill String design is an Iterative process involving variable and often conflicting issues. In a typical ER well rotary torque loads are higher and tension loads lower than for a vertical well of the same measured depth. This arises from the fact that a large part of the drill string weight is supported by the side of the hole in an ER well, reducing the portion of drill string weight that must be supported by the block. At the same time, friction from this side-wall support of the drill string makes the string more difficult to rotate, increasing the rotary torque load on the string.

36

Tangent Angle (degrees)

To

rsio

n (

1000

ft-lb

s)

30

24

18

12

6

0

15 30 45 60 75 900

TensionTorsion

420

350

280

210

140

70

0

Han

gin

g T

ensi

on

(10

00 lb

s)

Figure 9-2. Drill string loads in a series of 20,000 ft MD wells vary with

hole angle.

Figure 9-2 shows the expected surface hanging load and rotary torque to rotate the drill string off bottom in a series of hypothetical wells with a 2° /100 ft (30m) build rate and with tangent angle varying between 0 and 90 degrees. It also shows that rotary torque in an ER well may be a limiting load, especially at higher tangent angles and longer reaches. Figure 9-2 is given only to illustrate the expected drill string load trends as our drilling moves from conventional toward ER, and not to show loads for any particular case.

9-3

Given the design constraint that non-cyclic loads may not exceed yield stress tension, rotary torque and their combined effects should be evaluated in appropriate reference materials:

• Standard DS-1 Drill Stem Design and Inspection • BPX Equipment Manual • API RP7G

Torque

Key Points:

• Torsional capacity of string is typically limited by tool joint capacity • Actual tool joint dimensions (box OD, pin ID, and connection type) are required to

determine tool joint capacity and makeup torque • Rotary torque is limited by makeup torque of the connection • Makeup torque can be increased within pin neck tensile load constraints if required

"Standard" tool joint dimensions are those which are 80% as torsionally strong as the drill pipe body. Therefore, the tool joint is likely to be the limiting component for typical ERD non-cyclic loads. Contractors often purchase nonstandard tool joints for a variety of reasons. Therefore, it is essential to verify the actual dimensions of the tool joints in the string to be used to ensure that it has adequate torsional strength for the application.

Since all API tool joints are made from material having the specified minimum yield strength of 120,000 psi, tool joint torsional capacity is determined only by connection type, pin ID and box OD. Makeup torque is the operating torque limit for a rotary shouldered connection. Table 9-1 lists standard tool joint dimensions for NC-50 tool joints on 5-inch 19.50 ppf, S-135 drill pipe. Also shown are the tool joint torsional capacities and makeup torques using standard thread dope.

Table 9-1 Performance Properties of "Standard" Sized Tool Joints on 5-inch 19.50 ppf Drill Pipe

Grade Standard ID (in) Standard OD (in) Makeup Torque (ft.-lb) Torsional Yield (ft.-lb.) E 3-3/4 6-5/8 22840 38060

X 3-1/2 6-5/8 27080 45130

G 3-1/4 6-5/8 31020 51700

S 2-3/4 6-5/8 38040 63400

9-4

If predicted operating torque in an ER well exceeds standard makeup torque, then there are three potential solutions:

• Increase makeup torque

• Replace the drill string with one with stronger tool joints

• Lower the friction forces in the hole

Since the first alternative is always cheaper, it's usually the solution of choice, provided it can be done safely. Always check the remaining pin neck tensile capacity at the increased makeup torque levels by using the combined load curves for tool joints in DS-1 as shown in Figure 9-3.

For stronger tool joint selections and to reduce friction forces in the wellbore, refer to the ‘Handling High Non-cyclic Loads’ discussion later in this section.

Tension and Combined Tension/Torsion

Key Points:

• Drill pipe tubes are typically the weak link in tension and combined tension/torsion loading.

• Simultaneous application of rotary torque loading reduces the tensile load capacity of the string and vice versa.

• Combined load curves in DS-1 will help define limits. • Be aware of combined load situations such as pulling on stuck pipe and backreaming

with high drag. Unless we have inadvertently reduced the tool joint tensile capacity by excessive makeup, the tensile capacity or combined tension-torsion capacity of the string will probably be limited by the capacity of the drill pipe tubes. Both of these quantities are given in tables and curves in DS-1. The combined tension/torsion curve for 5-inch, 19.50 ppf drill pipe is reproduced as Figure 9-4. The curves for combined load capacity for tubes and tool joints (Figures 9-3 and 9-4) can be used to estimate the tensile and combined tension/torsion load capacity for the string as a whole. This is easily done by superimposing the combined load curve for the appropriate tube onto the combined load chart for the tool joint. An example is shown in Figure 9-5 for 5-inch 19.50 ppf, grade S tube with a 3-1/4 inch ID NC-50 tool joint.

9-5

These comments refer to Figure 9-5 and illustrate the process. Keep in mind that the torsion axis applied to tool joint capacity refers to makeup torque, while for tubes it refers to externally applied (rotary) torque:

1500

1250

1000

750

500

250

00 10 20 30 40 50 60

Box O.D.

6-3/8 6-1/2 6-5/8

Shoulder separation

Pin yield

3-3/4

3-1/2

3-1/4

3

2-3/4

BoxyieldPin I.D.

MAKEUP TORQUE (1000 ft-lbs.)

TE

NS

ILE

CA

PA

CIT

Y (

1000

lbs.

)

Figure 9-3. Pin neck tensile capacity of a rotary shouldered connection decreases as the applied makeup torque

increases. ((DS-1, Figure 2.5i)

600

500

400

300

200

100

00 10 20 30 40 50

Torsion (1000 ft-lbs.)

Ten

sio

n (

1000

lbs.

)

60

5" 19.50 lb/ft.

E

X

G

S

Figure 9-4. Drill pipe combined tension-torsion load capacity may be a concern in an ER well when backreaming a

dirty hole. (DS-1, Figure 2.4p)

9-6

1500

1200

900

600

300

00 12 24 36 48

Torsion (K ft-lbs.)

Ten

sio

n (

KIP

S)

60F G C E

A

1050 KIPS

561 KIPS

B

H

5" 19.50 lb/ft. Premium Class PipeNC50 Tool Joint with 3-1/4 inch ID

30800 ft-lbs

40200 ft-lbs

D

I

Figure 9-5. Drill pipe combined tension-torsion load capacity is superimposed over the combined load capacity of the

tool joint to estimate the combined capacity of the string as a whole.

These illustrations are for conceptual purposes only. Appropriate safety factors must be applied before using the curves.

The following comments refer to Figure 9.5 and illustrate the process. Keep in mind that the torsion axis applied to tool joint capacity refers to makeup torque, while for tubes it refers to externally applied (rotary) torque:

Area Description Line ABC The area above and to the right of this line represents all the

conditions of combined external (string) tension and makeup torque that would yield the tool joint pin.

Point F The normal makeup torque, and point I is the pin neck capacity to carry external tension at that makeup torque.

Point D The tensile capacity of a 5-inch, 19.50 ppf, grade S premium class tube in the absence of applied torsion on the tube. The weaknesses indicated of figure 9.5 (tube weakness in pure tension, tool joint weakness in pure torsion) are typical for common tube/tool joint combinations.

Line DE The combined load capacity of the tube under simultaneous tension and torsion such as during backreaming with high tensile drags.

Point G The absolute limit of makeup torque without reducing the pin neck’s ability to carry external tension to less than the tensile capacity of the tube.

9-7

Make the combined load curves for your drill string immediately available to the driller on the rig floor. They should be used to define the drill string load limits for:

• Pulling on stuck pipe where simultaneous torque is applied • Backreaming to clean out cuttings beds with high drag

Estimating Non-cyclic Loads in a Well

Key Points:

• Use torque and drag programs to predict non-cyclic drill string loads • Choose friction factors carefully, based upon mud type and field case histories

Torque and drag loads on the string can be estimated by using PC-based torque and drag models as discussed in Section 10, “Torque and Drag”.

Drill string loads estimated in the torque and drag model for an ER well will vary widely depending on the operation being performed and the drill string configuration at the time. Therefore, a summary for each hole section should be used to keep track of the various load conditions as shown in Table 9-3 for a recent North Sea ERD well.

Table 9-3 ER Load Summary (Example 12-1/4 inch Section - North Sea)

(Loads at surface, string at casing point except as noted. Drill Pipe: 5-inch, 19.50 ppf, S-135 PC, NC-50, 6-5/8 inch x 3 1/4 inch)

Load Capacities Applied Loads Percent Of Tube Tensile Cap.

(Klbx) TJ

Torsion Limit

Tension Torsion Tool Joint Tube

Operation

No Torsion

W/ Torsion

MUT (Kft-lbs)

(Klbs)

(Kft-lbs)

Tensile cap.

MUT

Min. Yield

Combined Cap.

Pickup 1. W/rotation 561 472 34.0 231 32.9% 35% 97% 64% 49% 2. W/O rotation 561 561 34.0 322 - 49% - - 57% Slackoff 3. W/rotation 561 495 34.0 112 27.2 17% 80% 53% 23% 4. W/O rotation 561 561 34.0 56 - 9% - - 10% Drilling 5.W/rotation 561 482 34.0 116 30.3 18% 89% 58% 24% 6. W/O rotation 561 561 34.0 33 - 5% - - 6% 7. Rotating off bottom

561 480 34.0 167 31.2 26% 92% 63% 35%

Assumptions:

Measured depth (ft): 21,200 BHA torque (ft-lbs): 3,000 Mud weight (ppg): 14.5 BHA drag (lbs): 30,000 WOB (lbs): 20,000 RPM: 120 Bit torque (ft-lbs) 2,000 Friction factors: 0.17 (casing), 0.2 (open hole)

9-8

Handling High Non-cyclic Loads

Key Points:

• Special tool selections can increase the load capacities of the drill string such as tool joints and non-API material grades

• Consider high friction thread dope to increase makeup torque • Enhanced Performance Drill Pipe provides increased critical load capacity for reduced

buckling Non-API Tool Joints

As mentioned previously, the limiting factor in ERD drill string design is often rotary torque. Other tool options may need to be explored if the predicted rotary torque for the well is higher than can safely be achieved by increasing the makeup torque, as discussed earlier. One option is to select a string with proprietary tool joints which have higher torsional capacity. The most commonly used tool joint design for these situations is the Grant -Prideco HT-Series or “High-Torque” connection. It employs the API NC threadform with a second torque shoulder on the nose of the pin. Makeup torque is typically 40% higher than the comparable API NC tool joint.

High Friction Thread Dope

High friction thread dope can also be used to increase the torsional capacity of the tool joint. With higher friction in the thread dope, a higher makeup torque is required to achieve the standard target stress in the connection. Since makeup torque is the rotary torque limit, a higher makeup torque means a higher rotary torque limit.

Special Tools

Another more exotic solution to increase load capacity may be the use of non-API drill pipe grades. Various drill string materials are discussed in Section 17, “Emerging Technologies”, such as one with a minimum yield strength of 165 ksi and one made of a titanium alloy.

In-situations where high loads are the result of buckled drill pipe, consider the use of Enhanced Performance Drill Pipe. This is essentially stabilized normal weight drill pipe which provides a higher critical buckling load capacity with only a nominal increase in string weight versus regular drill pipe. Additional benefits include improved mechanical agitation of cuttings beds for improved hole cleaning. This drill pipe design is discussed in Section 17, “Emerging Technologies”.

9-9

Reduction and Redistribution of Non-cyclic Loads

Key Points:

• High loads can be reduced by choosing lighter materials and smaller sizes for the string. • Consider the use of non-rotating string stabilizers to reduce rotary torque.

High non-cyclic loads can be reduced by selection of lighter materials and smaller tool sizes. Aluminum drill pipe tubes are one option that have been in limited use for many years, but may not be suitable for some mud systems. Steel tool joints are attached to each end of the aluminum tubes to provide adequate torsional capacity and wear resistance. Another lightweight material option may be composite drill pipe tubes, again with steel tool joints. Composite pipe is discussed in Section 17, “Emerging Technologies”.

Lighter weight strings can also be achieved by reducing the size of the string. The “slim-hole option” has often been reserved as a contingency hole interval in case of hole problems. However, in many ERD applications and particularly for sidetracks from existing wellbores, it may be the only adequate alternative.

High rotary torque loads result from high drill string sideloads as discussed in Section 10, “Torque and Drag Projections”. Redistribute and reduce these sideloads by using non-rotating string stabilizers such as the Diamant-Boart-Stratabit (DBS) or Western Well Tools (WWT) tools. These tools allow the string to rotate smoothly on a bearing while the non-rotating stabilizer pad provides standoff for the drill string from the casing. This reduces rotary torque, casing wear, and drill string wear.

Cyclic Loading and Fatigue

Key Points:

• Prevent simultaneous buckling and rotating of normal weight drill pipe. • Configure the drill string to position buckling-tolerant components in the string segments

which are expected to be buckled. • Buckling will tend to occur in a straight segment of the wellbore immediately above or

below a curved segment prior to occurring in the curved segment itself. • Avoid fatigue due to BHA sag by adding undergauge stabilizers.

9-10

Drill string fatigue from cyclic loading can be a major concern in an ER well. However, with care in managing bit weights and in BHA design, fatigue will often be less of a problem in an ER well than in a vertical well because of the stabilizing effect of hole angle on drill string components. Fatigue is a complicated mechanism whose control requires concerted attention to material properties, cyclic stress levels, and the corrosiveness of the environment. Our purpose here is only to discuss two fatigue control steps that often require special attention in an ER well.

A. Preventing buckling and rotating normal weight drill pipe at the same time. Because of the high hole angles, it's often necessary, while rotating, to apply bit weight with normal weight drill pipe (NWDP) run in mechanical compression. However, as long as the pipe is not buckled, no significant fatigue damage will normally be expected from this practice. In sliding mode drilling, hole friction may cause NWDP buckling while we are attempting to apply weight on bit. In the absence of rotation, no significant fatigue damage is likely. Therefore, our discussion here will concentrate on managing bit weights while rotating in order to stay below the buckling point in NWDP.

B. Lowering stress induced by BHA components abruptly sagging toward the low side of a high angle hole.

Buckling

To retard fatigue damage, rotating any buckled drill string component should be avoided. When buckling is unavoidable, (as in the bottom part of the string in vertical and near-vertical hole sections), long practice has established that only more "buckling tolerant" components (drill collars and heavy weight drill pipe) should be run in the buckled zone.

In an ER well, high hole angle often means that bit weight can not be efficiently applied with the traditional BHA, and it becomes necessary to mechanically compress the normal weight drill pipe to apply bit weight. Fortunately, the high hole angle helps stabilize the drill pipe and allows a certain amount of mechanical compression. As long as the magnitude of mechanical compression does not exceed the critical buckling load (FCRIT), the drill pipe remains stable. Dawson and Paslay showed that the critical buckling load in a straight wellbore could be predicted by the relationship

F CRIT = 2 • EIw K B sin θ

r (9.1)

If bit weight is applied with normal weight drill pipe in a straight wellbore, the Dawson-Paslay equation predicts the onset of buckling from mechanical compression, and therefore provides a convenient limit for the extent the drill pipe can be used to apply bit weight. The Dawson-Paslay limit is also thought to be conservative when the hole is not enlarged, as the formula does not consider the benefit gained from the presence of tool joints on the drill pipe. Use the Super Drill String Simulator (SDSS) to calculate which segments of the drill string are buckled for given drill string configuration, mud property, and wellbore trajectory combinations.

9-11

Curves that give quick solutions to this equation are also available in DS-1, and an example is shown in figure 9.1. Also note that a curved wellbore section provides additional stability to the string above the critical buckling load predicted by Equation 9.1. Comparison of the predicted buckling loads in a curved section of the wellbore and the straight sections immediately above and below the curve will show that the drill string will tend to buckle in one of the straight hole sections before it will buckle in the curve.

90

80

70

60

50

30

40

10

20

HOLE ANGLE

66

56

46

36

26

16

6 11 166

218-1/2 9-7/8 12-1/4 17-1/2

CR

ITIC

AL

BU

CK

LIN

G L

OA

D (

1000

lbs)

HOLE DIAMETER, INCHES

5" , 19.50 lb/ft., 15.5 lb/gal.

Figure 9-6

Cyclic Stress Induced by BHA Sag

If the BHA configuration includes one or more drill collars above the topmost stabilizer, the top connection in the stabilizer is vulnerable to fatigue because the collar immediately above sags abruptly. This overstresses the connection at the top of the stabilizer and shortens its fatigue life. The problem will be worse as stabilizer gauge to body ratio increases because the collar above has farther to sag. Eck-Olsen, et al reported fatigue failures in BHA connections from this cause, and corrected them by running intermediate gauge tools to decrease the abruptness of the sag.

9-12

OTHER DRILL STRING DESIGN ISSUES

Annular Velocity and Drill Pipe Size

Annular Velocity (AV), is a key factor in hole cleaning. Since, for a given pump rate, AV is directly related to the annular area between the wellbore and drill pipe, AV considerations will figure into drill string design. At moderate build rates, larger pipe will usually be preferable because it will offer lower system pressure drop and higher annular velocities for a given pump rate. As build rate increases however, the higher stiffness of larger pipe may create casing wear problems. Table 9.4 shows the AV for several different drill pipe and hole sizes. The AV figures in this table are based on the assumption that 1100 gpm can be pumped in the 17-1/2 inch or 16-inch hole and 900 gpm for the 12-1/4 inch hole. As Table 9.4 illustrates, going from a 17-1/2 inch hole with 5-inch drill pipe to a 16-inch hole with 6-5/8 inch drill pipe increases the AV from 96 fpm to 117 fpm, or 23%. (Another benefit of a 16-inch hole if hole cleaning is a problem is that it generates 16% less cuttings volume). Going from 5-inch to 6-5/8 inch drill pipe in a 12-1/4 inch hole increases the AV from 176 fpm to 208 fpm, an increase of 18%.

Table 9.4 AV With Respect to Hole and Drill Pipe Size

HOLE (in) DP (in) FLOW (gpm) AV (fpm) 17-1/2 5 1100 96

16 6-5/8 1100 117

12-1/4 5 900 176

12-1/4 6-5/8 900 208

Hydraulics and Drill Pipe Size

With very long hole sections, high mud viscosity, and high flow rates, hydraulics can quickly become an issue. Larger drill pipe reduces the pressure drop on the bore of the drill string, which allows better bit and PDM hydraulics and higher flow rates. This beneficially raises the AV as previously stated. However, as AV increases, the ECD also increases. Check to make sure that the ECD does not exceed the strength of the open hole.

9-13

Casing Wear Issues

Backreaming: Casing wear is affected by rotating time, build rate, and drill pipe tension below the build section. The more rotating time, the higher the build rate and the greater the drill string tension, the higher the casing wear rate. If the well has a relatively low build rate (1 to 3 degrees/100 ft. (30m)) and a high angle so that tension is minimal, the well designer may not suspect casing wear as a potential problem. However, low build rates and reduced drill pipe tension may be offset by the practice of backreaming to keep the hole clean. Backreaming maximizes tension and side-wall forces through the build section at the same time the string is being rotated.

Hardbanding: Refer to Section 7, “Tubular Design and Running Guidelines” for a discussion of casing wear mitigation through proper selection of hardbanding materials.

Jar Placement

Placement of jars in the drill string should be evaluated for each string and wellbore configuration using the placement program from the jar company. In general, there are two objectives in jar placement:

• Place the jar to provide maximum impact to the stuck point, typically in the BHA. • Do not place the jar in a drill string segment which is expected to be buckled.

Achieving the first objective may require any of a variety of tool configurations:

Description Explanation Jar in or near BHA. This is the traditional choice for jar placement in low inclination wells. The jar is

typically run above the neutral point to reduce the chance of it buckling when mechanical compression (WOB) is applied.

Jar and accelerator in or near BHA.

An accelerator is added to the system to increase the efficiency of impact transmission to the stuck point. The accelerator is placed above the jar with a prescribed length of drill collars separating them. When the jar is tripped, the accelerator helps to reduce the drag on the hammer mass and therefore concentrates the energy near the jar.

Double jars. With the first jar in or near the BHA out in the open hole, the second jar is placed I the string so that it remains in cased hole. This reduces the risk that poor hole conditions will render it non-functional. In the case where the lower jar does not function due to hole conditions, the upper jar can be used to transmit loads to activate the lower jar.

Double jars and Accelerator(s).

Similar to Option 2, the accelerator is placed in the string to improve the efficiency of the nearby jar.

Achieving the second objective requires that a buckling analysis be performed for the string segment adjacent to the jar. Torque and drag predictions are used to determine whether the string is buckled near the jar. Since jars are not buckling tolerant components, they should not be placed in a string segment which is expected to buckle. The primary features which make jars buckling intolerant are the mid-body connections where the jar is disassembled for service. These connections typically have threads with sharp thread roots, making them more prone to fatigue. Buckling the jar increases the stress on these connections and makes them fail more rapidly.

9-14

Drill String Inspection Practices

Typical ERD operations involve over 2000 downhole tools rented from various suppliers, the vast majority of which are used. Once a drill string design is developed and suppliers identified, steps must be taken to ensure that the delivered components meet the load requirements for the project. This is accomplished by inspection of the tools prior to their arrival at the rig. Also as the well progresses, regular inspections are required to ensure that the tools are not rendered unfit for continued service due to wear or damage. Refer to the BP Drill String Inspection Manual for guidance concerning inspection frequency and which inspection procedures to employ.

NOMENclature

a Inclination of the straight hole section above the kickoff point (degrees) AV Annular velocity (ft./min) BR Build rate (degrees/100ft) E Young's Modulus (Approximately 30,000,000 psi) FCRIT Critical buckling load (lbs)

FCRIT-ADJ Critical buckling load adjusted for mud weight variations (lbs)

I Moment of Inertia (in4) KB Buoyancy factor (unitless)

L Length of a drill string section (ft) LDA Length of a Drilling Assembly (ft)

LDP Length of a drill pipe section (ft)

MD Measured depth (ft) PV Plastic viscosity (centipoise) r Radial clearance between pipe and hole (in) w Unit weight in air of a drill string component (lb/ft) wDA Unit weight in air of a drilling assembly (lb/ft)

wDP Unit weight in air of drill pipe (lb/ft)

Weight(BS) The total buoyed weight of pipe in a positive build section (lbs)

Weight(BS-ADJ) The total buoyed weight of pipe in a positive build section adjusted for mud weight variations (lbs)

Weight(TS) The total buoyed weight of pipe in a tangent section (lbs)

WOB Weight on bit (lbs) YP Yield point (lbs/100ft2) θ Hole inclination (degrees) θ T Hole inclination in a straight tangent section (degrees)

9-15

REFERENCES:

1. Guild, G.J., Seymour, D.A., Hill, T.H., Munro, R., “Designing Extended Reach Wells”, Presented at the 1993 Offshore Technical Drilling Conference, Aberdeen, Scotland, November 17, 1993.

2. "Standard DS-1, Drill Stem Design and Inspection", T H Hill Associates, Inc., Houston, Texas, December 1992.

3. Brett, J.F., Beckett, A.D., Holt, C.A., Smith, D.L., "Use and Limitations of Drill string Tension and Torque Models for Monitoring Hole Conditions," SPE Drilling Engineering, September 1989, pp 223-229.

4. Johancsik, C.A., Friesen, D.B., Dawson, R., "Torque and Drag In Directional Wells - Prediction and Measurement," JPT, June 1984, pp 987 - 992.

5. Alfsen, T.E., Heggen, S., Blikra, H. and Tjotta, Helge, "Pushing the Limits for Extended Reach Drilling: New World Record From Platform Statfjord C, Well C2", Presented at the 68th Annual Technical Conference and Exhibition of SPE, Houston, TX., 3-6 October 1993.

6. Mueller, M.D., Quintana, J.M., Bunyak, M.J., "Extended Reach Drilling From Platform Irene," SPE Drilling Engineering, June 1991.

7. Kimball III, C.F., Colwell, C.N., Knell, J.W., "A 78o Extended Reach Well in the Gulf of Mexico, Eugene Island 326 No. A-6," OTC 6711, Presented at the Offshore Technology Conference, Houston, TX., May 1991, pp 143-156.

8. Hill. T.H., Seshadri, P.V., Durham, K.S., "A Unified Approach to Drillstem Failure Prevention", SPE Drilling Engineering, December, 1992.

9. Rollins, H.M., "Drill Pipe Fatigue Failure", Oil and Gas Journal, April 18, 1966.

10. API RP 7G, “Recommended Practice for Drill Stem Design and Operating Limits”, Fourteenth Edition, American Petroleum Institute, August 1, 1990.

11. Casner, John A, “Drill String Design”, Youngstown Sheet and Tube Company, July 1973.

12. Dawson, R., Paslay, P.R., “Drill Pipe Buckling in Inclined Holes”, Journal of Petroleum Technology, October 1984.

13. Schuh, F.J., "The Critical Buckling Force and Stresses for Pipe in Inclined Curved Wellbores", SPE/IADC 21942, 1991.

14. Wu, J., Juvkam Wold, H.C., "The Effect of Wellbore Curvature on Tubular Buckling and Lockup", ASME PD-Vol. 56, Drilling Technology-1994.

15. Eck-Olsen, J., Sletton, H., Reynolds, J.T., Samuell, J.G., "North Sea Advances in Extended Reach Drilling", SPE/IADC 25750, 1993 SPE/IADC Drilling Conference, Amsterdam.

16.BPX Equipment Manual

17.BPX Inspection Frequency Guidelines

18.Guild, G.J., Hill, T.H., Summers, M.A., “Designing and Qualifying Drill Strings for Extended Reach Drilling”, SPE/IADC 29349, 1995 SPE/IADC Drilling Conference, Amsterdam

9-16

10-1

Section 10 Torque and Drag Projections

In this Section...

• Torque Projection - Torque Components - String Torque - Bit Torque - String Torque Prediction - Torque Monitoring and Management Measures

• Drag Projections - Drag Friction Factors and Monitoring - Buckling Behavior During Sliding or Tripping - Predicting Drag and Buckling Severity - Buckling Impact on the String - Drag Monitoring and Management Measures

• Torque and Drag Projection Summary

• References

INTRODUCTION

Projecting torque and upward drag for ERD operations is critical to ensuring that the rotary and hoisting equipment of the rig are properly sized and that the drill string is properly designed. Projecting downward drag is critical to evaluating the limits for the abilities to slide oriented motors and run tubulars. Like many engineering tasks, a critical aspect of these projections is to ensure accuracy with some level of conservatism, without incurring excessive overdesign.

10-2

TORQUE PROJECTION

Torque Components

Analysis and projections of torque should recognize that total surface torque is comprised of: Total Surface Torque = String torque + Bit torque + Mechanical torque + Dynamic torque

Clearly, separating these torque components allows more accurate definition of friction for torque projections and for prioritizing measures for torque management. With means of predicting bit torque, the implications of using different bit types can be assessed. Dynamic torque can significantly impact operations and should be minimized (see Section 14, “Drill String Dynamics”).

Similarly, mechanical torque sources, such as cuttings beds, stabilizer effects, etc., can be significant and should also be minimized (see Section 11, “Hole Cleaning and Hydraulics” and Section 5, “Wellbore Stability). Fundamental concepts associated with string torque and bit torque are illustrated as shown:

Torque

Friction

Wall force

Axial load

Weightof pipe

WallForce

Friction

Axial load

Axial velocity

RPM

Dog leg severityForces due to

fluid flow

Bending Moment

Hydrostatic pressure Simulates downholeconditions by analysingthe forces acting on each element ofthe drill string.

Figure 10-1.

10-3

String Torque

Frictional Torque

Frictional drill string torque is generated by the contact loads between the string and the casing or open-hole. The magnitude of contact loads is determined by the amount of tension/compression in the drill string, the severity of doglegs, the DP and hole size, the string weight, and the inclination angle.

The use of optimized profiles (see Section 3, “Trajectory and Directional Drilling Optimization”) and the control of dogleg severity are important measures to minimize contact loads. While severe doglegs high in the well (where drill string tension is large) can significantly increase torque, the impact of doglegs deeper in the well is not as critical in terms of torque generation. However, well tortuosity should be minimized and this should be set as a primary performance measure for the directional drilling contractor. When performing pre-well projections or evaluating field torque with an actual survey file, the reduction in open-hole tortuosity by casing should be accounted for.

Independent from contact load magnitude, lubricity is another major factor controlling frictional loads. Lubricity is largely controlled by the mud and formation types (see Mud Selection section). Lubricity should be distinctly defined for cased-hole and open-hole intervals of each hole section. Within the open-hole section, distinct friction behaviors may be imposed by the different formations and significant torque changes can be seen when certain abrasive formations are encountered. Basic factors controlling frictional torque are shown in Figure 10-2.

RotaryFriction

AppliedTorque

Mech. AxialCompression

FNORMAL

AxialDrag Resultant

FrictionVector

FNORMAL

AppliedTorque

AxialMovement

Figure 10-2.

Specific procedures should be used when defining cased-hole and open-hole friction factors. The cased-hole friction factor should be based on cased-hole torque prior to drilling out, and by correlating torque

10-4

measured at the shoe during subsequent bit runs. With the cased-hole friction factor defined, open-hole friction factors can be independently assessed based on the increase of torque in the drilled open-hole section. During drilling, the cased-hole friction factor may increase when cuttings are brought back into the casing.

Because many variables impact friction, both cased- and open-hole friction factors should be derived for each hole section in the well, i.e. 12-1/4 inch and 8-1/2 inch sections may behave differently. There are various implications of using inaccurate friction factors. If the open-hole factor is overestimated, torque projected with increasing open-hole length will be excessive and may appear prohibitive. Similarly, if the cased-hole friction factor is overestimated (and hence open-hole underestimated), the torque increases with increasing open-hole length will be underestimated and false confidence could develop. Torque trends are not likely to be very precise, and lower and upper bound trends are suggested, i.e. the variability should be accounted for with proper engineering judgment.

Mechanical Torque Factors

Frictional torque should be viewed as the minimum torque associated with the drill string rotating in a clean wellbore with a specific mud. Other effects aggravate this optimal situation and cause increases to torque, including cuttings beds, sloughing formations, swelling clays, unstable formations, and excessive drill string-wellbore interaction (e.g. stabilizer blades digging into formations, undergauge bits causing working of stabilizers, etc.). These effects are considered mechanical torque sources because they are distinct from simple frictional interaction. Measures can be taken to minimize these mechanical effects. For example, higher flow rates, careful rheology controls and drill string rotation can improve hole cleaning to minimize cuttings beds. Analysis of mechanical and chemical wellbore stability can result in mud weight and chemistry recommendations to minimize instabilities. Identification of excessive torque associated with stabilizers or other equipment can lead to selection of better equipment, with smoother torque behaviors. Bit gauge wear optimization can be pursued, etc.

The aggravation of basic frictional torque due to mechanical problems is illustrated in the following figure, which shows the rapid buildup of torque in the 8-1/2 inch section of Wytch Farm Well F21. Although cased-hole torque inside the 9-5/8 inch was only 14 ft-kips at 17225 ft. (5250m) MD, surface torque rapidly increased by 9 ft-kips in the drilling of only 279 ft. (85m).

This dramatic torque increase was due to cuttings beds, and demonstrates the significant impact that mechanical effects have in elevating torque levels above simple frictional trends.

10-5

DE

PT

H (

mB

RT

)

5200

12

DRILLING TORQUE (ft -kips)

5225

5250

5275

5300

5325

53501614 18 20 2422

GAINED 9 ft-kips IN 85m8 1/

2" R

ES

ER

VO

IRS

EC

TIO

N

9 5/8" SHOE

F21 8 1/2" SECTION TORQUE INCREASEDUE TO CUTTINGS BEDS

Figure 10-3. F21 8-1/2 inch Section Torque Increase Due to Cuttings Beds

Upper and Lower Bound Trends: 12-1/4" Section Torques, Wytch Farm

Str

ing

To

rqu

e (k

ft.lb

s)

Measured Depth (m)

7000

5

10

15

20

25

1200 1700 2200 2700 3200 3700 4200 4700 5200 5700

Local Friction Factors

Upper Bound Trend

1 uuo

1uoL

Lower Bound Trend

11

cL

uuc( )

o

o

u( )

Figure 10-4. Upper and Lower Bound Trends: 12-1/4” Section Torques, Well F21

10-6

8-1/2" Section Average Surface Torque: Wytch FarmA

vera

ge

Su

rfac

e T

orq

ue

(kft

.lbs)

40

35

30

25

20

15

10

5

04000 4500 5000 5500 6000 6500 7000 7500 8000

Depth (m) Figure 10-5. 8-1/2” Section Average Surface Torque: Wells F19, F20, F21, M02

Bit Torque

Bit torque (TOB) is dependent on bit type, the formation being drilled, and drilling parameters. Bit torque models have been developed for both roller cone and PDC bit types, but have largely been based on laboratory measurement of bit torque. The Drill String Simulator (DSS) includes the Warren bit torque model from Amoco. While these lab-based measurements are informative, field torques vary dynamically and substantially during drilling and are influenced by many factors. These include formation characteristics such as shear and compressive strength, polycrystalline diamond compact (PDC) bit design variations, bit wear, and hydraulics. Specific areas where bit torque models can show substantial inaccuracy include:

• Non-ductile formations such as sandstones and carbonates. In these formations, the ratio of shear to penetration strength varies dramatically from behaviors seen in ductile shales.

• PDC bit torques have not been as thoroughly studied as tri-cone bits and are generally higher. PDC bits have high torque/weight ratios and torque can be very high in high shear strength formations. Further, PDC bit designs vary considerably in terms of cutter size and orientation, body profile and hydraulic design.

• Bit torque models currently do not account for bit wear state or bit cleaning due to hydraulic considerations.

The implication of these complexities for torque forecasting is that a conservative upper bound for TOB should be selected, preferably from field data. TOB should be monitored in ERD wells using a drilling mechanics sub in the measurement while drilling (MWD). Measurement of TOB (and weight on bit (WOB)) downhole provide various advantages for ERD operations (see Torque Dynamics Monitoring and Section 11, “Hole Cleaning and Hydraulics”). Alternately, basic TOB measurements can be taken by

10-7

monitoring off-bottom and on-bottom surface torque, although this is only approximate since the WOB causes variations in the drill string tension/compression profile.

To illustrate the variability of TOB, the following figure shows a composite plot of DTOB measurements for 12-1/4 inch PDC bits run at Wytch Farm:

Figure 10-6. F18, F19, F20, F21, M1, M2: 12-1/4 inch Hole Section

In examining Figure 10-7, it should be clear that an upper bound TOB for 12-1/4 inch PDC drilling in these conditions is 8,000 - 9,000 ft-lbs. Use of an upper bound for DTOB is conservative and appropriate for torque forecasting. However, this conservative margin should be kept in mind when comparing projections to field data. The majority of surface torque from the field will be taken with DTOB below this upper bound. Thus, projections can appear inaccurate and result in confusion regarding friction factors unless this "safety margin" is recognized.

10-8

For example, the following 12-1/4 inch torque trend plot from Niakuk Well 23 shows the offset from the tri-cone torque trend of 7-10 ft-kips for a PDC bit run:

PDC TREND

TRI-CONE TREND

Max

Trq

(ft-

kips

) / %

Sig

ma

45.00

40.00

35.00

30.00

25.00

20.00

15.00

10.00

5.00

0.0010000 10500 11000 11500 12000 12500 13000 13500 14000 14500 15000

Figure10-7 NK23 12-1/4 inch Torque and Dynamic

String Torque Prediction

Default Friction Factors

Standard default friction factors have been derived from analysis of well data covering normal drilling operations in a range of wells. Torque/drag predictions are typically within 10-15% using the default friction factors provided by DSS:

Mud Type Cased Hole Friction Factor Open Hole Friction Factor WBM 0.24 0.29

OBM 0.17 0.21

Brine 0.30 0.30

In certain cases, actual torque can vary substantially from those predicted with these defaults. Specific cases below are highlighted where default friction factors have required adjustments to match field experience. Deviations can occur due to variations in lubricity, hole cleaning efficiency, and surge/swab effects.

In choosing among these options, a useful concept to keep in mind is the critical tangent angle. This angle represents the limit beyond which a tool will not slide downhole under its own weight, meaning that it will have to be pushed from above. The critical angle is represented by:

q cos α = μ q sin α

or

tan α =1μ

where q is pipe buoyant weight, μ is friction factor and α is critical tangent inclination angle.

10-9

Variability of Friction Factors

Torque trends have been studied extensively in support of the Wytch Farm ERD program. Those analyses have shown substantial variability in torque behaviors. Relative to DSS defaults, torque trends in WF 12-1/4 inch sections have been below those predicted with the oil-base mud (OBM) defaults. This is attributed to good hole cleaning and the predominant formation in that section- mudstone. By contrast, torque trends in WF 8-1/2 inch sections have been well above those predicted with the OBM defaults and have, in fact, behaved more closely to WBM trends.

Detailed analysis of WF torque data indicates that variability in friction occurs even on ongoing operations and even in single-hole sections of a particular well. To quantify this variability, observed field torque were bound by an upper and lower trend. Specific cased- and open-hole friction factors were then derived for these two trends. Results from that analysis are shown in this table:

Wytch Farm Torsional Friction Factors

Size F-18 F-19 F-20 F-21 M-01 M-02 12.25 Csg OH Csg OH Csg OH Csg OH Csg OH Csg OH

Lower Bound Upper Bound

0.08 0.35

0.17 0.22

0.08 0.28

0.14 0.18

0.22 0.42

0.12 0.16

0.14 0.34

0.1 0.13

0.17 0.21

0.09 0.13

0.07 0.17

0.12 0.15

8.5 Csg OH Csg OH Csg OH Csg OH Csg OH Csg OH

Lower Bound Upper Bound

- -

- -

0.21 0.32

0.4 0.4

0.11 0.17

0.55 0.52

0.14 0.19

0.09 0.10

- -

- -

0.17 0.3

0.08 0.07

As a final example of the variability of drilling torque depending on local conditions, Wytch Farm drilling data has been compared to data from Niakuk operations in Alaska and from Statoil's C2 well. The data comparison for the respective 12-1/4 inch sections is shown below:

10-10

Figure 10-8 Composite Wytch Farm, Statoil, Niakuk Plot

Clearly, distinct torque trends can be seen in this plot. These are governed by differences in target TVD, trajectory, formations, mud types (Niakuk-WBM, Wytch Farm-MOBM, and Statoil- SOBM), hole cleaning efficiency, and other factors. These torque trends are provided as “order of magnitude" bounds on 12-1/4 inch section torque for screening ERD candidates and as a final example of the need for careful and thorough analysis of torque behaviors for specific ERD candidate projects.

10-11

Torque Monitoring and Management Measures

An active program should be implemented to measure drilling torque in real-time and, to the maximum extent possible, compare these torque values with predictive models. Even in the absence of model application, deviations to field torque trends provide a valuable early-warning to inadequate hole cleaning or problems with the bit/BHA. All service companies provide torque monitoring as a standard component of a comprehensive mud-logging service. Enhancement of this service by integrating surface torque measurements with DTOB MWD measurements is also strongly recommended. Deviation of torque trend behavior is shown in the following figure:

0.20/0.18 (plan)

0.18/0.14 (plan)

0.16/0.17 (actual)

accepted h.c.

optimum h.c.

TDS: Max Torque in high gear

D Torq: 5000Nm

D Torq: 2000Nm

DEPTH (M MD)

TorqueNm

PredictedTorque

44000

41500

39000

36500

34000

31500

29000

26500

24000

21500

19000

16500

14000

11500

9000

6500

40002100 2600 3100 3600 4100 4600 5100 5600 6100 6600 7100

Figure 10-9. Torque Trend example

Torque reduction should not necessarily be pursued if the operation has an adequate drill string and rotary and power capacity to handle high torque. Attempts should always be made to reduce cyclic torque, i.e. slip-stick. In cases where specific limits are being approached, various measures exist which may be pursued to reduce torque or to improve the capacity of the limiting equipment. Such measures include:

• Optimization of drill string strength and effectiveness. Substantial increases in nominal torsional capacity of existing drill strings can be obtained through tool joint stress-balancing and high-friction thread compounds. Where options exist for specific drill string design, selection, or even rental, consideration should be given to the use of high-torque (double-shoulder) tool joints and to the use of high-strength (higher than S-135) material grades. Aside from strength, Enhanced-Performance Drill pipe is available with integral blades which can enhance hole cleaning and thereby reduce mechanically induced torque from cuttings. See Drill String Design (Section 8) and Emerging Technologies (Section 17) for more information.

10-12

• Reduction of mean and dynamic torque. Cased-hole torque reduction can be achieved with non-rotating DP protectors (e.g. Western Well Tool's plastic sleeve DPP). Open-hole torque reduction can be achieved with tools such as the DBS open-hole torque sub which involves a non-rotating metal sleeve mounted on bearings. Torque reduction can also be pursued with lubricants, lubricating beads, and optimization of mud lubricity. Forthcoming releases of DSS will include the ability to optimize placement, estimate torque reduction, and assess ERD envelope extension as a result of torque reduction tools.

• LCM. At Wytch Farm, dramatic open-hole torque reductions of up to 30% have also been observed through the use of high concentrations of fibrous Lost-Circulation Materials (LCM). These LCM appear to form a low-side bed which exhibits much reduced friction on the drill string as opposed to direct contact with the sandstone and casing. Actual drilling limits determined by rotary stalling can be controlled by torsional dynamics. Thus, monitoring for torsional dynamics and implementation of rotary feedback control systems should be considered. See Section 11, “Hole Cleaning and Hydraulics” and Section 14, “Drill String Dynamics” for more information. To achieve such large torque reductions requires the continual addition of 5-10 sacks per hour to the active system. This can become extremely expensive, and a simple LCM recovery system is used to keep consumption down. The coarse top screen discharge is almost all LCM and this is fed back to the active. The bottom screen discharge is all cuttings and is dumped. It can often take 8-12 hours after starting to add LCM before the torque reductions are observed. Occasional LCM pills have also proved very effective at carrying large volumes of cuttings from the well, and are often used prior to trips and intervals of slide drilling. The best results have been achieved with Barafibre and Sandseal.

10-13

DRAG PROJECTIONS

Like torque prediction, drag prediction is influenced by various factors including:

• Trajectory design • Drill string design • Mud and formation lubricity • Wellbore condition • Tortuosity

An issue unique to drag prediction is the potential buckling of the string under axial compression. Buckling is an important consideration in severe ERD wells because while tripping in or sliding, the drill string and other tubulars (liners, workstrings, tubing, TCP guns, coiled tubing, etc.) are subjected to compressive forces. These forces can exceed the critical buckling load and lead to sinusoidal (moderate) or helical (severe) buckling. The wall forces resulting from buckling create additional drag which, in severe cases, can cause string lock-up. When predicting drag, it is therefore important to quantify the extent and severity of buckling when it occurs.

Drag Friction Factors and Monitoring

The information concerning friction factors for torque prediction is equally valid for drag prediction. Drag prediction is only as good as the friction factors applied and they are also influenced by many factors. In some cases, deviations from drag predictions when tripping can be due to surge/swab effects which can result in significant pressure, hence load changes in the well. Forthcoming releases of DSS will account for these surge/swab contributions. Field hookload data can be used to determine representative drag friction factors and should be continually analyzed to improve the accuracy of projections. As with torque, variations in drag friction factors are significant and should be monitored as shown in the following figure:

0.5

F19

Well Number

Fri

ctio

n F

acto

r

0.4

0.3

0.2

0.1

0F20 M02F21

DSS Cased/OpenHole Nominal

Friction Factors (0.24/0.24)

8-1/2" Section Slinding Hookload Friction Factors: Wells F19, F20, F21, M02

0

LO

UO

LC

UC

Figure 10-10 Example from WF showing change in FFs from well to well

10-14

Analogous to torque monitoring, drags should be carefully monitored to highlight problems when hookload measurements deviate from simulated trends. Clear deviations from predicted drag trends have been seen on trips and in ERD casing running hookloads (see Section 7, “Tubular Design and Running Guidelines”).

Buckling Behavior

When the critical buckling load is exceeded at a given location, the string first buckles into a sinusoidal geometry along the low side of the hole. At higher compression loads, the pipe coils up against the wellbore, in a state known as helical buckling. These buckling severities are shown below:

Pipe Deforms Slightlyalong Low Side of Well

Pipe Deforms More Severely AroundComplete Circumference

SinusoidalBuckling

HelicalBuckling

Figure 10-11 Example of Sinusoidal and Helical Buckling

10-15

Sinusoidal buckling can be tolerated as it does not cause large wall forces. Buckling severity is quantified by defining how far above the low-side of the hole the string is displaced. This is measured in degrees from the low-side of the hole, with a 180° buckling displacement correlating to full helical buckling to the high-side, as shown below:

Buckling Amplitude

Figure 10-12.

Predicting Drag and Buckling Severity

Conventional torque/drag simulators assume the pipe remains unbuckled and are therefore limited to modeling situations only where there is no buckling. DSS includes calculations for the onset of buckling and post-buckling wall forces, but DSS assumes helical buckling based on the Lubinski model, which is conservative with regard to predicting buckling drag, hence lockup. Thus, when critical buckling loads are exceeded, the drag model should have more sophisticated capabilities including:

• Full buckling and post-buckling analysis capability, and • Analysis of the effect of 3-D wellbore geometry, curvature and friction on buckling

In these cases, modeling should be performed with the latest version of the Super Drill string Simulator (SDSS - Version 2.3). SDSS will predict the:

• Transition from sinusoidal to helical buckling • Extent of buckling, i.e. the intervals of drill string buckling • Severity of buckling, i.e. sinusoidal or helical • Associated wall forces and drag • Onset of string lock-up • Resultant forces and stresses in the string

10-16

An example of SDSS analysis for an operation with buckling is shown in the following figure, from Wytch Farm.

Measured Depth (m)

Bu

cklin

g A

mp

litu

de

( )

00

10

20

30

40

50

60

70

80

90

100

1000 2000 4000 5000 6000 80003000

Buckling Amplitude

5" DP BHA5 1/2" DPDO

7000

Wytch Farm 1M-02SP: Buckling Amplitude While Sliding in 8-1/2" Section(7123 m MD)

Figure 10-13 Wytch Farm IM-U2SP: Buckling Amplitude While String in 8-1/2 inch Section

DSS and SDSS will be merged in the next release of DEAP so that drag analyses with buckling can be properly handled.

Buckling Impact on the String

Sliding/Tripping

If the buckling amplitude remains below 40°, the buckling is generally tolerable and does not cause great increases to drag. However, more severe sinusoidal buckling and helical buckling should be avoided as it can cause dramatic increases in wall forces and can lead to string lock-up.

Both sinusoidal and helical buckling impose additional stresses in the string when sliding or tripping in the hole. Due to wellbore confinement, the string remains elastic and does not get damaged (i.e. come out of the hole yielded or "corkscrewed") unless the hole section is heavily washed out.

Rotating

When rotating, string-wellbore axial friction is virtually eliminated, hence string buckling becomes less likely. However, if the string is buckled, rotation should not be initiated until the buckling is relieved by pickup then reaming back to bottom. Rotating a buckled string is not recommended and can lead to very high cyclic bending stresses, severe dynamics, and possible fatigue failures.

10-17

In one of the Statoil ERD wells, drill string buckling was detected while rotary drilling the deep high angle (75o) 17-1/2 inch sections. This is one of the only reported cases of buckling while rotating and resulted in higher than normal torque. When the buckling occurred, a 17-1/2 inch tri-cone bit with high WOB was being used. To complete the section while avoiding further buckling, a PDC bit which could drill with a lower WOB was picked up.

The presence of buckling in the rotating string in the Statoil 17-1/2 inch section is shown below:

3600034000320003000028000260002400022000200001800016000140001200010000

1200 1400 1600 1800 2000 2200 2400 2600 2800 3000 3200 3400 3600

Measured depth (m)

Tor

que

(Nm

)

Measured torque

Theoretic torque with 5 tonweight on bit (WOB).

Rockbit PDC bit

Buckling

Figure 10-14. Statoil 17-1/2 inch Torque Figure with Elevated Torque from Buckling

10-18

Drag Monitoring and Management Measures

The use of downhole torque and downhole WOB at Wytch Farm has proved to be an important tool in qualitatively assessing hole cleaning efficiency. Trend analysis can clearly indicate the condition of the hole while drilling, as well as the effectiveness of any remedial action such as reaming, circulating and wiper tripping.

The response of these parameters to hole cleaning efficiency is very dependent upon the formation drilled. It has been established that while drilling mudstones inefficient hole cleaning is indicated by an increasing drag trend with very little increase in drilling torque as shown in figure 10-16. However, both torque and drag will increase with poor hole cleaning while drilling the Sherwood sandstone resevoir section. Analysis is not always straightforward though, as a decrease in wellbore lubricity with increasing amounts of sandstone cuttings may play a significant role in determining the drillling mechanics response.

DWOB

DWOB

0 801

%

0 80100

0 20

0 200 150

0 100

0 100

0 200

ROPM/hr

STORQ

DTORQ

SURFACERPM

DRAG

FRIC

API GR%

CIRC HOLE CLEAN35 STD WIPERTRIP @ 3168m

3150m

3150m

Figure 10-15. Drag Trend in Mercia Mudstone

10-19

Measures exist to reduce drag and to develop improved or alternative means of achieving the desired operation. Techniques to directly reduce drag include:

• Lubricating mud additives and lost circulation materials (LCMs) • Optimizing the well trajectory (see Directional Drilling and Trajectory Optimization) • Bullet shape casing shoes with side jets • String design to minimize the extent of buckling • Casing flotation (see Tubular Design section) • Non-rotating dill pipe protectors used to reduce torque may reduce drag, hence buckling

tendencies and severities due to lower friction.

Techniques to assist in achieving the desired operation, i.e. overcoming the existing drag, include:

• Use of drill-collars and/or HWDP in the near vertical well section • Extensive hole-cleaning and pipe working prior to slides • Use of thrusters or bumper subs to improve WOB delivery while sliding • Use of extended or double power section motors to increase stalling resistance • Application of traveling equipment weight to push the drill string or casing down • Qualifying the subject string (liner, completion string, TCP string) for rotation • Use heavier tubulars in areas of expected buckling

10-20

TORQUE AND DRAG PROJECTION SUMMARY

1. Surface torque must be analyzed by careful examination of its two major components - string torque and bit torque. Dynamic torque and mechanical torque sources should be recognized and isolated where possible.

2. String torque/drag must be analyzed based on examination of distinct friction factors for the cased-hole and open-hole. Torque/drag friction factors can vary significantly from DSS defaults and should be derived from field data for each hole section.

3. String torque/drag analysis must also consider the planned trajectory, probable doglegs, tortuosity, and drill string design.

4. Cased-hole and open-hole friction factors can vary substantially between wells and even in single hole sections of a given well as a result of wellbore condition with regard to cuttings beds, etc. Collection and analysis of field data is critical to being able to quantify these variations.

5. Bit torque while drilling will vary substantially and dynamically. For projection purposes, a conservative upper bound should be used for DTOB. Preferably, this DTOB upper bound can be set using field data from a drilling mechanics MWD sub.

6. Simulation tools, such as the Drill String Simulator (DSS) are valuable as diagnostic tools to identify deviations from predicted values and trend/sensitivity analysis. However, predictions are only as good as the friction factors used, thereby making analysis of field data equally, if not more, important.

7. Drag prediction is also dependent on accurate diagnosis of frictional drag in the well and the extent of buckling in the string. Moderate sinusoidal buckling can be tolerated and does not lead to severe increases in drag. Extensive helical buckling of the string should be avoided and can lead to severe drag and lock-up. Washout sections can result in large deformation of the drill string under compression and can lead to damaged dill pipe. Washouts should be avoided for this and other reasons in ERD operations.

8. The Super-Drill String Simulator (SDSS) should be used if DSS predicts buckling. SDSS has more advanced features than DSS for estimating buckling onset and the severity of post-buckling deformation. Note, however, that SDSS has limitations for normal drilling operations in that it lacks hydraulics, ripple factors, etc. Thus, DSS should be used where feasible, with SDSS used to focus specifically on buckling behavior.

9. Various measures are available to reduce drag friction factors and to overcome existing drag to achieve the desired operation.

10-21

REFERENCES

1. Payne, M. L., Cocking, D. A., and Hatch, A. J., "Critical Technologies for Success in Extended Reach Drilling", SPE 28293, presented at the 69th Annual SPE Fall Conference, 25-28 September, 1994, New Orleans. Reprinted as SPE 30140 Brief by editorial selection, Journal of Petroleum Technology, February 1995.

2. Child, A. J. and Cocking, D. A., "Drill string Simulator Improves Drilling Performance", Oil & Gas Journal, 28 August 1989, pp. 41-47.

3. Belaskie, J. P., McCann, D. P. and Leshikar, J. F., "A Practical Method to Minimise Stuck Pipe Integrating Surface and MWD Measurements", IADC/SPE 27494, 1994 IADC/SPE Drilling Conference, 15-18 February, 1994, Dallas, Texas.

4. Aarrestad, T. V. and Blikra, H., "Torque and Drag - Two Factors in Extended Reach Drilling, Journal of Petroleum Technology, September 1994, pp. 800-803.

5. Abbassian, F., Mason, C., Luo, Y., Brown, C. and Payne, M., "Wytch Farm 7/8 km Stepout ERD Wells", Internal Report DCB/11/95, May 1995.

6. Abbassian, F. and Mason, C., "Buckling Simulation for Gun Running and Hole Cleaning Operations in 2 km Reservoir Section of M2 Well", DCB File Note, November 1994.

7. Mason, C., "Buckling Simulation for Gun Running and Hole Cleaning in 3 km Reservoir", Wytch Farm 1M-03SP ERD Well, Internal Report, DCB, February 1995.

8. Super Drill string Simulator User Manual, BP Exploration Technology Provision, Sunbury, England.

9. Lubinski, A., Althouse, W. S. and Logan, J. L., "Helical Buckling of Tubing Sealed in Packer", Journal of Petroleum Technology, June, 1962.

10. Paslay, P. R. and Bogy, D.B., "The Stability of a Circular Rod Laterally Constrained to be in Contact with an Inclined Circular Cylinder", ASME Transactions, Journal of Applied Mechanics, Volume 31, 1964.

11. Dawson, R. and Paslay, P. R., "Drill Pipe Buckling in Inclined Holes", SPE 1167, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, September, 1982.

12. Chen, Y. C., Lin, Y.H., and Cheatham, J. B., "Tubing and Casing Buckling in Horizontal Wells", Journal of Petroleum Technology, February 1990.

13. Chen, Y. C. and Cheatham, J. B., "Wall Contact Forces on Helically Buckled Tubulars in Inclined Wells", Journal of Energy Resources Technology, Volume 112, June 1990.

14. Kyllingstad, A., "Buckling of Tubular Strings in Curved Wells", Journal of Petroleum Science and Engineering, Volume 12, pp. 209-218, 1995.

15. Mitchell, R. F., "Effects of Well Deviation on Helical Buckling", SPE 29462, presented at the Production Operations Symposium, Oklahoma City, April 1995.

16. Hearn, Phil, "Drill String Simulator (DSS) - Application for Completion Operations", BP XTP, Sunbury, England.

17. Justad, T., Jacobson, B., Blikra, H., Gaskin, G., Clarke, C., Ritchie, A., “Extending Barriers to Develop a Marginal Satellite Field from an Existing Platform”, SPE 28294.

Section 11 Hole Cleaning and Hydraulics

IN THIS SECTION...

• Hole Cleaning - Well Plan - Mud Properties - Drilling Practices - How Cuttings are Transported - Cuttings Transport Models

• Hydraulics - System Pressure Loss - Mud Rheology - Hydraulics Modeling

• References

11-1

INTRODUCTION

Removal of cuttings from the wellbore is essential to the drilling operation. Failure to effectively transport the cuttings can result in a number of drilling problems including:

• Excessive overpull on trips • High rotary torque • Stuck pipe • Hole pack-off • Formation break down • Slow rate of penetration (ROP)

The key to optimizing hole cleaning in ERD wells is integrating a good well plan, with good mud properties, and good drilling practices — supported by careful monitoring and observation at the rig site.

HOLE CLEANING

Well Plan

In specifying fluid properties and flow rates for optimum hole cleaning, remember that the fluid design is only one part of an integrated process. Factors which assist hole cleaning may have a detrimental effect on other well processes. In practice, a compromise is often necessary. Frequently it is necessary to use a range of well engineering design tools to develop the most appropriate balance of well conditions.

Hole angle Deviated wells require higher annular velocities than vertical. Plan large diameter hole sections closer to vertical.

Hole size Minimize hole size where possible to maximize hole cleaning.

Hydraulics Plan for high flow rate (Large diameter dp / minimize restrictions in mwd / motor / collars).

Bit Hydraulics Select nozzles to balance ROP optimization Vs annular velocity to clean the hole.

Mud Pumps Determine flow rate and horsepower requirements for all critical sections.

Slide Drilling Maximize use of rotary drilling which helps stir-up cuttings beds.

BHA Select simple BHA with high bypass area to assist tripping in and out of hole.

Casing Program Plan minimum rathole consistent with safe running of casing.

Floating Vessels Consider using riser booster pump. May require an additional pump.

Planning Tools Use DEAP / Hole Cleaning Charts / Guidelines / Stuck pipe handbook.

11-2

Hole Angle

As a hole angle increases from vertical, cuttings transport becomes more difficult. The flow rate required to carry cuttings out of the hole increases rapidly from 0o to 60o. Above 60o the rate of flow rate increase levels off. Hole angles between 45o and 60o frequently present the most problems because cuttings tend to slide back down the annulus and pack-off.

Hole Enlargement

Sections where the wellbore is enlarged are more difficult to clean. This applies to washed out open hole sections as well as liner tops. Cuttings tend to accumulate in pockets where the annular velocity is significantly reduced. Every effort should be made to avoid enlargement of the open hole. Common causes are: insufficient mud weight, chemically reactive formations, and wellbore erosion. In situations where enlargement exists, mud flow rates need to be increased to compensate for the reduction in annular velocity.

Mud Flow Rate

The mud flow rate is the most important factor for hole cleaning in deviated wells. Mud pumps and liner sizes should be selected to ensure a sufficiently high flow rate when drilling ERD wells. Pump pressure is often the limiting factor for achieving the required flow rate. Consideration should be given during the bottom hole assembly (BHA) design and bit nozzle selection to reduce pump pressure. The frictional pressure drop in 6-5/8 inch pipe is approximately half the value for 5-inch drill pipe.

Hole Size Typical Flow Rates 17-1/2 in Aim for 1100 gpm. Some rigs achieve 1250 -1400 gpm.

12-1/4 in Typically 950 - 1150 gpm. If not available, ensure that tripping procedures are in place for probable dirty hole.

8-1/2 in Aim for 500 gpm. Drill Pipe Rotation

Movement of the drill pipe (rotation and/or reciprocation) will mechanically disturb cuttings beds and assist hole cleaning. Rotation is more effective since this helps equalize fluid velocities on the low and high side of the hole. The influence of drill pipe rotation is more pronounced in viscous muds and in smaller holes (<17-1/2 inch). In cases where the pipe is not rotated (e.g. slide drilling), cuttings beds are more difficult to remove. Under these special circumstances, increased flow rate or changes in operation practices (e.g. rotary wiper trips) may be necessary to improve hole cleaning.

11-3

Mud Properties

Mud Chemistry Ensure chemical compatibility to prevent cuttings swelling

Wellbore Stability Avoid hole enlargement (washout and break-out)

Flow Regimes Generally use thick muds in laminar flow (unless ECD is critical)

Mud Rheology Select muds with high YP/PV ratios and enhanced low shear viscosity

Pump Rate Use DEAP hydraulics to determine minimum mud flow rate

Mud Weight

Increasing mud weight provides buoyancy and reduces the effective weight of cuttings. Effective transport will occur at lower annular velocities. In practice, the selection of mud weight is generally governed by other drilling considerations (e.g. well control, wellbore stability and losses). Heavy weight mud can be used in small volume pills to assist hole cleaning.

Mud Rheology The influence of mud rheology on cleaning deviated wells depends upon the annular flow regime. In laminar flow, increasing mud viscosity (YP) will improve hole cleaning by raising fluid drag and causing cuttings to slide. By contrast, in turbulent flow, lowering fluid viscosity increases turbulent intensity. This provides a greater lift force to transport cuttings by saltation.

Hole Cleaning Pills The properties for the mud in circulation should always be optimized to provide adequate hole cleaning. Under certain conditions, it may be necessary to supplement hole cleaning with “viscous” pills. Excessive use of pills should be avoided since they can contaminate the mud system. Generally a high viscosity (and preferably high weight) pill is effective at removing accumulated cuttings. Low viscosity pills can also be effective in smaller hole sizes (12-1/4 inch and below). Low and high viscosity pills can also be pumped in tandem. The maximum volume of the pills should be based on hole size and changes in hydrostatic. Similar improvements in hole cleaning have been achieved using lost circulation material (LCM) pills.

Typical Operating Conditions

It is recommended that DEAP hydraulics and hole cleaning simulations are run for all ERD wells. This enables mud properties and flow rates to be optimized to provide adequate hole cleaning in all sections of the well.

11-4

The table below gives typical ranges of fluid properties for a selection of hole sizes. The values are specified by either the Yield Point (based on Bingham Model) or the Power Law Index (n).

Hole Size Recommended YP Limits (lb/100 ft2)

Recommended “n” Range Flow Regime

17-1/2 inch 28 Min 0.5 - 0.7 Laminar

12-1/4 inch 21 Min 0.5 - 0.75 Laminar

12-1/4 inch 5 - 10 Max 0.5 - 0.95 Turbulent

8-1/2 inch 22 Min 0.5 - 0.7 Laminar

8-1/2 inch 5 - 12 Max 0.5 - 0.9 Turbulent

In general higher viscosity muds pumped in laminar flow are preferred.

Drilling Practices

ROP Control instantaneous drill rate to avoid overloading annulus with cuttings

Pump Failure Stop drilling and circulate until full pump capacity is restored

Slide Drilling Conduct rotary wiper trip after prolonged periods of sliding

Viscous Pills Use only when essential. Take special care with lo-vis pills to maintain high flow rate

Dense Pills Use only when essential. Limit volume to avoid fracturing formation

Tripping Circulate the hole clean with rotation prior to tripping. A single bottoms up is not sufficient

Overpull Pull through tight spots ensuring the pipe is free to go down. Work gradually up to predetermined maximum overpull limit

Backream Only when essential. Use DEAP to control maximum backreaming rate

ROP

Increasing ROP will result in more cuttings being generated at the bit and so increase the cuttings loading in the annulus. Higher penetration rates require higher flow rates to clean the hole. It is good practice to maintain steady ROPs and to avoid high instantaneous penetration rates. Mud properties and flow rates should be adjusted to ensure the hole is cleaned as fast as it is drilled. This is a primary criteria (total pump capacity) to consider when selecting the rig.

Rig Site Indicators

There are a number of rig site indicators that should be used to monitor the hole condition. These should normally be examined for trends and sudden departures rather than absolute values.

• The shape and size of the cuttings coming over the shaker should be regularly monitored. Small rounded cuttings indicate that cuttings have been spending extended periods downhole being reground by the BHA. The cuttings return rate at the shakers should also be measured and compared with the volume predicted from ROP.

• Torque and drag can be used to determine whether cuttings beds are adding to the wellbore friction. Simulations should be conducted in advance using the DSS part of the DEAP program. Deviations from

11-5

the normal trend line can be indicative of cuttings beds forming. Erratic signals in torque or SPP can also be an early warning of cuttings beds.

• Record pickup, slackoff and off-bottom rotating torque regularly at connections to establish actual trends for comparison to predicted trends.

Cutting size & shape

Rounded cuttings indicate poor carrying capacity

Cuttings Return Use ROP to estimate anticipated cuttings rate at shakers

Torque & Drag Use DEAP to predict torque and drag. Look for deviations from trend

Erratic Torque / SPP

Look for indicators of cuttings beds & packing-off

Trend Analysis Compare drag trends on subsequent trips to indicated presence of cuttings beds

Hole Fill Monitor string weight for indications of fill on bottom Operational Practices

Successful hole cleaning relies upon integrating optimum mud properties with best drilling practices. When difficulties are encountered, it is essential to understand the nature and causes of the problem. This allows options to be focused to determine the most appropriate actions. This list below should be used as a guide to identifying possible courses of action:

• Poor hole cleaning will result in high cuttings loading the annulus. When circulation stops these cuttings can fall back and pack-off the BHA. When packing-off occurs, the flow rate is too low or the well has not been circulated for sufficient time.

• Typical volumes (50+bbl for 17-1/2 inch; 30-50 bbl for 12-1/4 inch; 20 bbl for 8-1/2 inch). It is not advisable to use low viscosity pills in weakly consolidated formations.

Limit the use of viscous pills to supplement hole cleaning. Control the mud in circulation properties to provide sufficient hole cleaning.

Typical Volumes:

Hole Size Volume

17-1/2 inch 50+bbl

12-1/4 inch 30-50 bbl

8-1/2 inch 20 bbl

11-6

• Treat the hole gently. Avoid sudden mechanical or hydraulic shocks

which may cause cuttings to avalanche. • Control tripping rates to avoid pulling rapidly into a cuttings beds or

causing excess swab/surge pressure. • Pulling through tight spots is OK, provided the pipe is free going

down. Agree to a maximum allowable overpull in advance with the Company Man/Drilling Superintendent. Do not go immediately to the maximum overpull, but work up progressively ensuring that the pipe is free to go down on every occasion.

• Stop and circulate the hole clean if overpulls become excessive. • Avoid precautionary backreaming - only backream when essential from

torque and drag trends. Use DEAP to determine the maximum allowable backreaming rate.

• Anadrill’s on-line drillstring simulator using data from the drilling mechanics sub is capable of calculating the variations in friction factors and can provide early indications of hole cleaning problems.

• The use of downhole torque and downhole WOB at Wytch Farm has proved to be an important tool in qualitatively assessing hole cleaning efficiency. Trend analysis can clearly indicate the condition of the hole while drilling, as well as the effectiveness of any remedial action such as reaming, circulating and wiper tripping.

• The response of these parameters to hole cleaning efficiency is very dependent upon the formation drilled. It has been established that while drilling mudstones inefficient hole cleaning is indicated by an increasing drag trend with very little increase in drilling torque as shown in the following figure. However, both torque and drag will increase with poor hole cleaning while drilling the Sherwood sandstone resevoir section. Analysis is not always straightforward though, as a decrease in wellbore lubricity with increasing amounts of sandstone cuttings may play a significant role in determining the drillling mechanics response.

11-7

DWOB

DWOB

0 801

%

0 80100

0 20

0 200 150

0 100

0 100

0 200

ROP

M/hr

STORQ

DTORQ

SURFACERPM

DRAG

FRIC

API GR

%

CIRC HOLE CLEAN35 STD WIPERTRIP @ 3168m

3150m

3150m

Drill String RPM Guidelines

Normal range of drill pipe RPM's is typically 90-180 rpm (up to 120 rpm on bottom, up to 180 rpm off bottom). In practice, there needs to be a balance between good effects for hole cleaning versus possible detrimental effects (e.g. vibration causing premature failures of downhole equipment). High rpm should also be avoided in unstable formations since the string action can knock off loose sections of the wellbore. Limitations on downhole tool components (e.g. downhole motors) can also restrict the maximum allowable rpm.

11-8

How Cuttings are Transported

In deviated wells, cuttings tend to settle on the low side wall and form cuttings beds. These cuttings are often transported along the low side of the hole either as a continuous moving bed or in separated beds/dunes. The figure below is a schematic representation of the transport mechanisms for a range of well inclinations.

�y�y ��yyyy��yyyy

��yy��

yyy

��

yyy

WELL INCLINATION (DEGREES)

INCREASINGANNULARVELOCITY

ZONE 5

NO HOLE CLEANING

ZONE 3

SLOW REMOVALOF CUTTINGS

ZONE 4

SOME HOLE CLEANINGCUTTINGS BED FORMED

ZONE 2

GOOD HOLE CLEANINGWITH MOVING CUTTINGS BED

0 30 60 90

ZONE 1

EFFICIENTHOLE CLEANING

��yy��yy��yy ��

��yyyy

In holes inclined less than 30o , the cuttings are effectively suspended by the fluid shear and beds do not form (Zones 1 and 3). For such cases conventional transport calculations based on vertical slip velocities are applicable. For these shallow angles, annular velocity requirements are typically 20-30% in excess of vertical wells. Beyond 30o, the cuttings form beds on the low side of the hole which can slide back down the well, causing the annulus to pack-off. Cuttings which form on the low side of the hole can either move en-masse as a sliding bed (Zone 4), or alternatively may be transported at the bed/mud interface as ripples or dunes (Zone 2). Drill pipe movement (rotation and reciprocation) can help mechanically disturb the cuttings beds and distribute them in the faster flowing mud towards the high side of the hole.

11-9

Flow patterns in the annulus depend strongly upon flow rate and mud rheology. Thin fluids with low YPs tend to promote turbulence and cuttings saltation. Thick fluid with high YPs increase the fluid drag force and causes the cuttings beds to slide.

The ideal zones for good cuttings transport are Zones 1 and 2. Zone 5 is virtually a guarantee of tight hole problems.

Cuttings Transport Models

• Modeling Approaches: Analytical and numerical methods have been used successfully to model fluid flow in eccentric annuli. In practice, the complexity of cuttings transport in deviated wells rules out the use of pure analytical approaches to modeling heterogeneous cuttings/mud mixtures. Most modeling attempts to date are based on purely empirical methods of using laboratory data to fit a physically based model.

• BP Model: The model is based on the fluid forces acting on cuttings within a settled bed. The model takes into account both lift and drag forces to predict the minimum flow rate required to prevent formation of a stationary cuttings beds. The model was originally developed from flow loop data and has been validated against numerous ERD wells drilled by BPX and other operators.

The main features of the model are:

− Allows for rheology and flow regime

− Models washed-out hole

− Takes account of drill pipe rotation

− Predicts flow rate requirements with changing ROP

11-10

The model demonstrates that either thick or thin muds can be used to clean high angle sections. Intermediate viscosity muds provide the worst conditions and should be avoided. In-situations where ECD is not a limiting factor, thick muds with high YP/PV ratios are preferred. These results agree qualitatively with recent models developed by Tulsa University and Exxon.

EFFECT OF YIELD POINT ON CRITICAL FLOW RATE(8-1/2" Hole at 60 deg., ROP-20m/hr, PV=19cP and 1.45 sg Mud)

0

300

200

100

400

500

600

5 2010 15 25 30 35

Turbulent flow Laminar flow

Low ViscousMuds

High ViscousMuds

Mud Yield Point (lbf/100sqft)

CriticalFlow Rate(gpm)

The figure above shows how increasing the mud yield point causes the flow mechanism to change from turbulent to laminar. Intermediate values of YP should be avoided since they produce the worst conditions for cuttings transport. In general the higher YP (and hence laminar flow) regime is preferred because the higher viscosity mud provides better cuttings suspension and improved transport in the near vertical regions of the well.

Under conditions where ECD is a limiting factor, the use of thin muds in turbulent flow should be considered. Thin fluids reduce annular frictional pressure drops, and hence result in lower ECD’s. Turbulent flow in the annulus should be avoided with weakly consolidated formations.

Circulation Prior to Tripping

The BP model simply predicts the minimum flow rate required for adequate cuttings transport. No predictions are available for the rate at which cuttings are removed. Because the cuttings move more slowly than the circulating mud, it is essential that sufficient bottoms-up are circulated prior to tripping. A SINGLE BOTTOMS-UP IS NEVER ENOUGH!

The minimum on bottom circulation time prior to tripping will be influenced by hole size, inclination and flow history (i.e. mud properties and flow rate). These factors will affect the height of any residual cuttings beds. Recent work by Exxon has indicated that the volume of cuttings left behind during normal drilling operations can be considerable. They recommend selection of bits/BHAs with large bypass areas to facilitate tripping out of the hole.

11-11

Before tripping, monitor the shakers to ensure the cuttings return rate is reduced to an acceptable background level. The figures in the table below are guidelines based on simple slip velocity considerations and field experience:

WELL INCLINATION SECTION LENGTH FACTOR RANGE 17-1/2 inch HOLE 12-1/4 inch HOLE 8-1/2 inch HOLE 0o - 10o 1.5 1.3 1.3

10o - 30o 1.7 1.4 1.4 30o - 60o 2.5 1.8 1.6

60o + 3.0 2.0 1.7

Procedure

1. Effective length = Section length x section length factor.

2. Circulation time = ∑Effective Length

Measured depth at Bit x B/U

Example

Since in practice not all of the section back to surface will be deviated at the same angle, the overall minimum circulation time prior to tripping should be apportioned in direct relation to the relative lengths of section at each angle. This is illustrated in the following example for tripping out of 17-1/2 inch hole at 7,710 ft. (2,350m).

850m x 1.5

(0 deg)

300m x 1.7(10-30 deg)

400m x 2.5(30-60 deg)

800m x 3.0(60 deg)

18 5/8csg

Number of circulations

= ∑Effective Length

Actual Length

= 5,185m2,350m

= 2.2 * B/U

11-12

Access to Hole Cleaning Models

The BP cuttings transport model is accessible through the DEAP Hydraulics application program. For critical wells, the model should be used ensuring the most appropriate range of input data. Factors such as cuttings density, cuttings size, and hole washout should be based on best available local knowledge.

A simplified version of the model is available through a series of simplified charts. These charts are based on average input data for North Sea conditions. Caution should be exercised when applying these results to areas elsewhere.

The charts are available in the BP Stuck Pipe Handbook and in IADC/SPE 27486.

HYDRAULICS

For ERD wells it is essential to balance the hydraulic requirements at the bit with the flow rates necessary to keep the hole clean. Another important factor in high step-out wells is the increase in Equivalent Circulating Density (ECD) which can result in mud losses. In the extreme case of a horizontal well the ECD increases with section length, whereas the fracture gradient remains constant since it is a function of true vertical depth (TVD). System hydraulics depend upon:

• Flow rate

• Mud density

• Mud rheology

• Geometry

System Pressure Loss

The circulating mud system brings cuttings to surface and provides hydraulic energy to the bit. The overall system pressure loss is the summation of losses: at surface; through the drill string; through motors/MWD; through the bit nozzles and in the annulus. Flow regimes are generally turbulent in all areas except in the annulus. Here, flow is either laminar, transitional, or turbulent.

Conventional drilling hydraulics rely upon optimizing hydraulic horsepower or hydraulic impact at the bit. This requires approximately 60-70% of the system pressure loss to be dissipated at the bit. For ERD wells where the flow rates for hole cleaning are higher, it is often necessary to reach a compromise and reduce the energy spent at the bit. This is achieved by selecting larger nozzle diameters. The distribution of pressure losses throughout the circulating system depends upon well geometry and fluid properties. In conventional drilling the annular pressure drop is generally <5% of the overall system loss (this proportion increases dramatically for slimhole configurations). The annular pressure loss, while only a small fraction of the total loss, is critical for determining ECD.

11-13

Mud Rheology

Most drilling muds are shear thinning. This means they are non-Newtonian fluids whose viscosity reduces with increasing shear rate. Most muds are "viscoplastic". This means that a certain pressure needs to be exceeded before the mud can flow. There are many mathematical models that can be used to describe the flow behavior of drilling muds. It should be remembered however that these are simply mathematical descriptions of ideal behavior. In practice, most muds fall somewhere between "Power Law" and "Bingham Plastic" behavior.

The DEAP hydraulics model allows hydraulics predictions for both Power Law and Bingham Plastic fluids. In general, the Bingham Plastic calculations will give the higher pressure drop predictions.

The DEAP program also provides the option of using the Yield Power Law Model (referred to as Herschel Bulkley). This exhibits intermediate behavior between the Power Law and Bingham and gives pressure predictions somewhere between the two extremes. The Yield Power Law model requires a minimum of three (3) Fann viscometer readings to compute the flow parameters. It is recommended that a minimum of six (6) values over a range of shear rates be used.

Mud rheology is a sensitive function of temperature. Generally muds get thinner as temperature increases. With oil muds and synthetics, increases in confining pressure cause the viscosity to increase. This affect also occurs in water-base muds, but to a lesser degree.

Mud gels are important to help suspend barite. Ideally, these should be fragile (non-progressive). Excessive gel strengths can lead to high intermittent pressure surges to break circulation. These effects can be minimized by rotating the drill string prior to establishing circulation. High gels are also detrimental for swab-surge pressures.

Hydraulics Modeling

There are many published methods for calculating pressure drops of non-Newtonian fluids in complex geometries. In laminar flow, it is possible to derive exact analytical solutions. In turbulent flow, all correlations for non-Newtonian fluids are based on empirical correlations. The DEAP model uses a different turbulent flow correlation depending upon whether the mud is oil-base or water-base. Oil muds give rise to higher pressure losses under comparable conditions (typically 20% above WBM).

11-14

The influence of mud properties, flow rate and geometry on pressure loss vary depending upon flow regime. These principles apply to specific areas of the circulating system:

• Drill Pipe and Surface Pipework Flow will always be turbulent. Pressure loss is a strong function of flow rate ( approx flow

rate squared) and pipe internal diameter (approx diameter raised to fifth power). For example, pressure loss in 6-5/8 inch drill pipe is approximately half the value of conventional 5-inch drill pipe. Pressure loss increases linearly with increasing mud density, but is only a weak function of mud rheology.

• Motors and MWD Tools Pressure losses here are generally turbulent. Flow rate and mud density affect pressure

drop, mud rheology does not. Service company literature is available which provides hydraulic performance of the various tools. These are included within the DEAP hydraulics program.

• Bit Nozzles Flow is highly turbulent with shear rates approaching 10 ^ 5 reciprocal seconds. Pressure

loss is purely due to changes in inertia (flow velocity and density). Flow velocity is directly related to mud circulation rate and nozzle size (open flow area). Mud viscosity does not influence pressure loss at the bit.

• Annular Pressure For most common cases, flow in the annulus is laminar. Under these conditions pressure

loss is less sensitive to flow rate, but is a very strong function of mud rheology. Mud density does not affect the frictional loss in the annulus.

The overall accuracy of the DEAP model generally falls within 10-15% for the total circulating system. This is adequate for well planning purposes. During the actual drilling phase it is important to fine tune the predictions based on actual SPP. This allows the optimum balance between nozzle selection and hydraulic requirements for hole cleaning. Also remember that the DEAP program does not take account of changes in rheology with temperature and pressure. This, combined with the uncertainties in drill pipe eccentricity, can lead to errors in predicting the annular pressure loss. This is important in-situations where ECD is critical. In these situations, it is important to accurately monitor mud volumes to ensure the fracture gradient is not exceeded. If necessary, trends from the DEAP predictions should be used to modify operating parameters to reduced ECDs.

11-15

REFERENCES

General

1. Applied Drilling Engineering - K Millheim et al SPE Textbook Series

2. Theory and Application of Drilling Fluids Hydraulics - Exlog

3. BP Rigsite Handbook - Stuck Pipe Prevention (1992)

4. Hole Cleaning Charts - Y. Luo & P. Bern (1992)

5. Unique Hole Cleaning Capabilities of Ester-Based Drilling Fluid Systems - P. Kenny et al SPE 28308 (1994)

Flow Loop Studies

1. Practical Analysis of Drilling Mud Flow in Pipes and Annuli - M Zamora & D Lord SPE 4976 (1974)

2. Hole Cleaning in Full Scale Inclined Wellbores - T.R. Sifferman & T.E. Becker SPE 20422 (1990)

3. Experimental Study of Cuttings Transport in Directional Wells - J.J. Azar et al SPE 12123 (1983)

4. Cleaning Deviated Holes; New Experimental & Theoretical Studies - N.P. Brown et al SPE 18636 (1989)

5. Cuttings Transport in Inclined Boreholes - J.T. Ford et al SPE 20421 (1990)

Mathematical Models

1. Simple Charts to Determine Hole Cleaning Requirements - Y. Luo et al IADC/SPE 27486 (1994)

2. Transport of Cuttings in Directional Wells - M. Martin et al SPE./IADC 16083 (1987)

3. A Model for Transport of Cuttings in Highly Deviated Wells - A. Gavignet & I. Sobey SPE 15417 (1986)

4. Hole Cleaning in Large Angle Wells - M. Rasi IADC/SPE 27464 (1994)

5. A Mechanistic Model for Cuttings Transport - R. Clark & K. Bickham SPE 28306 (1994)

Field Monitoring of Hole Cleaning

1. Field Measurement of Circulating Pressure Drops - R Minton & P Bern SPE/IADC 17242 (1988)

2. Hole Cleaning and Pump Pressure Projections for Wytch Farm - Y Luo DCB Report (Jan 1995)

3. Uses and Limitations of Drill String Tension and Torque Models for Monitoring Hole Conditions - J.F. Brett et al SPE Drilling Engineer (September 1989)

4. Hole Cleaning Program for Extended Reach Wells - G.J. Guild et al SPE/IADC 29381 (1995)

5. Problem Detection During Tripping Operations in Horizontal and Directional Wells - J.V. Cardoso et al SPE 26330 (1993)

11-16

Section 12 Rig Sizing and Selection

In this Section...

• Rig Sizing - Well Design - 12.2 Operational Requirements - Hydraulic Requirements - Torque and Drag Predictions

• Equipment Sizing and Specifications - Efficiencies

• Evaluation

• Example

• References

• Rig Sizing and Selection

INTRODUCTION

Recent successes in extended reach projects have resulted in drilling engineers being asked questions like:

• Can the rig drill this target?

• How far can it reach?

• What rig upgrades or specifications are required to develop this field?

The answers to these questions are not straight forward - many factors affect the answer.

12-1

RIG SIZING

The rig sizing process can be divided into these sections:

• Well Design - specify drilling, evaluation, completion, and well servicing requirements. • Operational Requirements - define the hydraulic, torque, and hoisting requirements based

on the well design. The requirements are based on a combination of modeling and historical data, and are specified in terms of force, velocity, pressure, flow rate, torque, and RPM.

• Equipment Sizing and Specification - determine the equipment specifications based on operational requirements.

• Evaluation - review the equipment specifications to determine if objectives were met.

This process is not unique to ERD wells. The differences are in the results - the equipment requirements for a 30,000 ft. (9144m) ERD well will be different than for a 30,000 ft conventional well.

Well control and monitoring are not discussed in this Section. They are important in ERD operations, but are outside the scope of this document or discussed in other Sections. Since these systems are part of the drilling rig, they must be compatible with other rig systems.

Well Design

The first step in determining the performance requirements of a rig is to specify the well design. The well design must consider evaluation, completion and well intervention requirements as well as drilling needs. These requirements must be reasonable and necessary; requirements that are too restrictive will result in over-stated rig specifications and higher well costs.

Critical issues regarding equipment sizing may be identified during the rig sizing process. Changes to the well design may resolve them. For example, it may be determined the drill pipe is inadequate for various reasons—inadequate flow rates, high pipe body stresses, or excessive tool joints loads. Each situation may have a different solution, which affects the well design and rig requirements differently. It's up to the drilling engineer to evaluate the alternatives and determine the best solution for their project.

Operational Requirements

Operational requirements—hydraulic, torque and hoisting—are specified in terms of loads, speed, pressure, flow rate, torque, and RPM. For conventional wells, these requirements are determined from offset well data, rules-of-thumb, or simple calculations. For ERD wells, offset data may not be available or apply to the well design, and rules-of-thumb and simple calculations may not be adequate. This section discusses how the Drill String Simulator (DSS) and the Hydraulic Model applications in DEAP are used to determine the operational requirements.

However, offset well data, rules-of-thumb, etc. should not be ignored. This information can be useful in defining friction factors, ripple factors, flow rates, etc. Comparisons with wells of similar hole size and measured depth will give a "reality" check even if the directional plans are different. Significant variations should be evaluated to determine if valid assumptions were made in the modeling process.

12-2

Table 12–1 lists the well information needed for DEAP modeling. Much of the data is based on the well design, but some operational data is required—bit type, total flow area (TFA), weight on bit (WOB), anticipated rate of penetration (ROP), etc. As with the well design, it may be necessary to modify these during the rig sizing process.

Table 12-1 Requirements for DEAP Modeling

Casing Program Directional Program Mud Program Operation Data • Hole size and depth • Casing size & weight

• Directional plan • BHA • MWD/LWD

• Type • Density • Rheology

• Bit type/TFA • WOB • RPM • Flow rate • Pressure drop in downhole tools • ROP

Hydraulic Requirements

Meeting the hole cleaning and hydraulic requirements can be the most difficult part in rig sizing. So many factors are involved a unique solution doesn't exist: minimum flow rates are determined from hole angle, ROP, annulus size, mud properties, cuttings size and density, and drillpipe rotation. (Section 11, “Hole Cleaning and Hydraulics”). Pressure losses are determined from hole size and drill string dimensions, length of pipe and annular sections, number and type of downhole tools, TFA, and mud properties. Pumps are limited by pressure ratings and horsepower. Many solutions are possible—in certain cases reduced ROPs, low flow rates, and backreamming may be a better solution than high ROPs and flow rates.

Use DEAP Hydraulic Model to determine the flow rate and circulating pressure at TD of each hole section, or that part of the hole where the hydraulic requirements are greatest. If the minimum flow rate is not obtainable then some changes must be made.

Determine the limiting or critical criteria—ROP, maximum allowable flow rate, maximum surface pressure, etc. Modify the criteria easiest to change, usually the mud properties, ROP, liner size, and TFA. If the pump pressure is the limiting factor, eliminating downhole motors or MWD/LWD may allow reaching TD. Major changes may be required to meet the hydraulic requirements—additional pumps, large diameter (5-1/2 and 6-5/8 inch) drill pipe and high pressure (6,000–7500 psi) pumps and surface lines.

12-3

Torque and Drag Predictions

Use DSS to predict the torque and/or drag for various operations conducted in each hole section. The predictions should be in the most severe part of each hole section—generally at TD of each section. Define friction factors as appropriate for each hole section and operation. Conduct sensitivity studies on critical cases to determine the effect of assumptions—friction factors, ripple factors, etc. (Section 10, “Torque and Drag Projections”).

Drilling Predictions should be made for drilling with both PDC and conventional bits

Backreaming Generally uses the most power since hoisting is also required. Use a high hoisting speed—10–20 ft/min.

Tripping Evaluate tripping operations at total depth (TD) of the open hole section and again just inside the casing shoe. Assume cased hole hoisting speeds (60–120 ft/min) are twice open hole (30–60 ft/min).

Casing Evaluate pulling on stuck casing at TD—typically 100 kips overpull.

Liner Evaluate torque and/or drag requirements for rotating liner during cementing operations, if applicable.

Fishing Evaluate pulling on stuck casing at TD—typically 100 kips overpull.

12-4

EQUIPMENT SIZING AND SPECIFICATIONS

This section summarizes the calculations used to determine the size and specifications of the major rig components. These specifications are defined in terms of power, force pressure, and capacity—length and volume; and are determined from various operating parameters defined in the previous section. If the rig sizing objective is to evaluate a specific rig, Table 12-2 is a list of the rig information typically required.

Table 12-2 Rig Information

Mast • Mast rating • Crown rating • Traveling equipment rating • Number of lines normally reaved-drilling, casing

Drill Line • Size • Type • Design factors for drilling, casing and fishing operations

Drawworks • Rating • Input power • Drive efficiency or configuration • Maximum line pull

Rotary/Top Drive • Size, type • Input power • Drive-Independent, etc. • Hanging capacity

Pumps • Number, size, type • Input power per pump • Drive—independent, etc. • Liner sizes and maximum operating pressure

Rig Power • Prime mover type and power rating • Generator type and output rating • Grid power capability

Mud System • Capacity • Solids control system • Surface circulating system size, length and pressure rating • OBM capability (HSE)

Substructure • Racking capacity—length and size of tubulars • Setback capacity • Combined—casing plus setback

Drill String • Length, size, weight, grade, connection, condition

The next three pages include equipment inventories which are representative of rigs that have successfully drilled significant ERD wells.

12-5

Helmerich & Payne IDC Rig 100

Derrick Lee C. Moore bottleneck derrick, 170' x 30' base, rate @ 1,500,000# static load with 14 lines strung to traveling block. Setback load 940,000#, Rotary 1,500,000#. Rotary & Setback loads or Hook & Setback loads may be simultaneous.

Overhead String Lee C. Moore crown block (8 sheaves) Oilwell 650 ton traveling block (7 sheaves) BJ 750 ton model 5750 Dynaplex hook 1-5/8" EIPS drill line (breaking strength = 264,000 lbs)

Drawworks Oilwell E-3000 driven by three GE 752 electric motors, equipped with one Elmagco 7838 electric brake and sandreel.

Rotary Table Oilwell B 37-1/2" rotary table with independent drive and provisions to be chain driven from the drawworks.

Top Drive Varco TDS-4H top drive drilling system with one GE 752 Hi-torque Series motor; PH-85 pipe handler rated at 85,000 ft-lb make-up/break-out torque; video system, raised back-up system; top drive rated @ 50,900 ft-lb continuous torque.

Pipe Handling Varco SSW-30 pipe spinners. Varco AR3200 Automatic Roughneck capable of breaking 3-1/2" to 9-3/4" connections up to 5' - 1" above the rig floor, make-up torque 100,000 ft-lbs, break-out torque 120,000 ft-lbs.

Rig Power Four Caterpillar D-3516 diesel engines each rated @ 1615 HP and each driving Kato 1535 kW AC generator. One Cat. D-399 auxiliary engine rated @ 1215 HP driving a Kato 1050 kW AC generator all feeding a five-bay Ross-Hill SCR system. (Total System Power = 7675 HP, 7190 kW).

Pumps Three Gardner-Denver PZ-11 pumps each rated @ 1600 HP and driven by two GE 752 electric motors. 11" stroke, 115 max spm, 5000 psi fluid end rating, White Rock non-maintenance suction and discharge dampeners, pump synchronization device. Digital gauges are used to monitor standpipe and choke manifold pressures. Liner sizes and operating pressures: 5-1/2"/5000 psi, 6"/47000 psi, 6-1/2"/400 psi, 7"/3450 psi.

Mud System Drilling: 710 bbl Active mud tank, 150 bbl Processing tank, 386 bbl Reserve mud tank (Total Tank Volume = 1,246 bbl). 660 bbl Base Oil Storage tank. Three Derrick Sandwich shakers cascading into three Derrick Flo-Line Cleaners. Swaco Degasser. Swaco Desander with three 12" cones. (Rented Derrick Mud-Cleaner). Completion: 832 bbl Dedicated Completion tank (rig equipped with dedicated completion standpipe and kelly hose also).

Substructure Substructure & Skid base equipped with two Lee C. Moore double acting ram jacks, 120 ton pull, 140 ton push capacity with 33" stroke.

Drill String 17,325' of 5" S-135, 19.5 lb/ft, 4-1/2 IF conn., Premium drill-pipe 930' of 5" Hevi-wate drill-pipe. 6-1/4" and 8" drill-collars are standard. 12,000' of 6-5/8" S-135, 26.2 lb/ft, HT-65 conn., Premium drill-pipe (BP's) 620' of 6-5/8" Hevi-wate drill pipe (BP's).

Cranes One Unit 10,000 hydraulic crane, 100' boom One Link Belt 218A mechanical crane, 90' boom One Link Belt 108B mechanical crane, 80' boom

BOP Equipment Diverter: ABB Vetco Gray KFDJ-J, 2,000 psi fixed diverter. 20/3-4" 3,000 psa single ram preventers, One 20-3/4" 3,000 psa single ram preventer (BP's). 13-5/8" Stack: One Hydril GL type 13-5/8" 5,000 psi annular preventer, One Cameron type "U" 13-5/8" 10,000 psa double ram preventer, One Cameron type "U" 13-5/8" 10,000 psi single ram preventer. Koomey model 330-11SZ type 80 closing unit, 8 station with outlets to four additional stations, remote panel with eight stations.

Additional Two deep well pumps rate @ 1200 gpm, Mathey Standard Suveyor unit with 25,000' of .092 wire line. Three story quarters/heliport with 82 personnel capacity. Rig floor office and mud laboratory. Non-skid stair covers throughout the rig.

12-6

Statfjord 'C' platform

Derrick NPC/Foster 160' x 40' x 40' 597 ton derrick Dreco 650 ton crown block

Traveling Equipment National 760H-650 ton traveling block Normally 12 lines 38mm drill line

Drawworks 426 ton rating 2 x 600kw motors

Rotary/Top Drive Varco TDS4 745kw continuous input power 500 ton rating

Pumps 2 / 16000 HP / National 12-P-160 1200 kw 7", 6-1/2", 6" and 5-1/2" liners Maximum 320 bar operating pressure

Rig Power 2 x 4 MVA - 13,8kw transf. prime mover

Bulk Capacity Bulk stor. 200m3 / 120m3 cement

Mud System 676 m3 pit capacity

345 bar pressure rating Shakers: 4 eq. GM 2000-H Cuttings injection, enclosed mud pits for OBH

Substructure Racking capacity - 4000 m 6-5/8" (inc. dc fingers), Max 6870 m 5-1/2" dp or 7320 m 5" dp 297 tonnes setback capacity 947 tonnes combined casing plus setback

Drill String - 6-5/8", 25.2 lb/ft, S135, FH, Premium - 5-1/2", 21.9 lb/ft, S135, FH, Premium - 5", 19.5 lb/ft, S135, NC 50, Premium

12-7

Magellan Jack-up Drilling Unit

Derrick 160 ft. x 40 ft. Dreco, rated at 2,000,000 lbs. GNC & 1,600,000 lbs. static hook load with 16 lines.

Drawworks National-Oilwell E-3000, driven by three GE 752 Hi-Torque electric DC motors, with National-Oilwell universal hydraulic disc brake and a Baylor 7838 electric brake.

Rotary Table National-Oilwell hydraulic motor driven non-drilling 49-1/2”.

Top Drive Varco BJ model TDS-6S, with two GE 752 Hi-Torque motors; closed loop cooling system; PH-85 pipe handler rated at 85,000 ft./lb. makeup/brakeout torque; integral 7,500 psi CWP swivel, video system, TDS/Block retraction system; top drive rated at 60,000 ft./lb. continuous drilling torque and 1,500,000 lb. hoisting capacity.

Pipe Handling Varco BJ PHM-31, 30,000 ft. racking cap, complete with integrated iron roughneck capable of braking connections up to 20 ft. above floor, makeup torque 100,000 ft./lbs., brakeout 120,000 ft./lbs.

Main Mud Pumps Three National Oilwell 14-P 200 triplex pumps, each driven by two GE 752 hi-torque shunt wound DC motors, driving through a Kevlar V-belt drive system.

Storage Capacities Liquid Mud: 2,900 bbl. (dependent on mud weight and variable load conditions. Base Oil: 850 bbl. Brine: 900 bbl. Bulk Material: 17,400 cu ft.

BOP Equipment Diverter: Drilquip 500 psi fixed diverter with a 2,000 psi pressure rated housing and two 16 in. diameter outlets located on each side of the housing with straight runs to either side of the drill floor. 21-1/4” system: One Hydril type GL 5,000 psi annular preventer, one Hydril 5,000 psi double ram preventer, one Hydril 5,000 psi single ram preventer, both rams with 4-1/16 in. 15m outlets 13-5/8” system: One Hydril type GX 10,000 psi annular preventer. Two Hydril 15,000 psi double ram preventers configured with 4-1/16 in. 15m outlets.

Cranes Three Sea King, Model SK3500 cranes, with 120 ft. booms and rated for 32 tons at 65 ft, radius.

Tender Mode Drill floor/substructure can be skidded from cantilever subbase onto adjacent jacket structure, up to 80 ft. beyond maximum cantilever reach.

Conductor Tension Unit

600 kip C.T.U. suspended from cantilever beams can apply tension at any point within drilling envelope.

12-8

Efficiencies

Several of the rig components—drawworks, rotary and mud pumps—are rated by input power. However, power calculations based on operating parameters determines the component output power. (Note: DEAP calculates output power.) The input power is determined by the ratio of output power to the efficiency of the component. Efficiencies can be defined by function (References 12–1, 12–2):

Transmission Efficiency (Et)

Efficiency of the power transmission system and depends on the rig power system. This includes generators, silicon controlled rectifier (SCR) converter, wiring and drive motors for electric rigs; and torque converter and mechanical or hydraulic couplings for mechanical rigs.

Table 12-3 - Transmission Efficiency Power - Transmission Efficiency (Et)

Electric - SCR 0.85

Electric - DC/DC 0.85

Mech - Torque Converter 0.80

Mech -Hydraulic Coupling 0.98

Drive Efficiency (Ed) Efficiency from the output of the transmission to the input shaft of the rig component. Depends on the number chains and shafts making up the drive system, which differ for.

Table 12-4 - Drive Efficiency

Component Efficiency (Ed)

Mechanical Rig Electric Rig Drawworks 0.83 0.87

Top Drive - 0.96

Rotary - Indep Drive - 0.94

Rotary 0.75 0.79

Pumps 0.90 0.94

Hoisting Efficiency (Eh)

Efficiency of the crown block, traveling block, and drilling line and depends on the number of lines supporting the traveling block.

Table 12-5 - Hoisting Efficiency

Number of Lines Efficiency (Eh)

8 0.842

10 0.811

12 0.782

14 0.755

16 0.728

12-9

Design Factors Uncertainty is a fact of life and needs to be considered when sizing a drilling rig. The uncertainty discussed here applies to the assumptions made regarding the well design, mechanical and electrical efficiencies, historical information and modeling. How well these assumptions match reality is unknown until we've drilled and completed the well. Even with "perfect knowledge" circumstances, Murphy's Law may change the requirements.

Apply appropriate design factors when sizing the equipment in this section. Use caution when specifying design factors to ensure that "hidden" design factors are not already in place. This effectively compounds the applied design factor and may result in over stating the rig requirements. Values generally range from 1.1 to 1.25 and depend on how certain you are of your assumptions.

Derrick/Mast

The crown load determines the derrick/mast capacity and is based on the maximum hook load (including traveling equipment) and the number of lines strung. The number of lines can vary with drilling and casing operations, therefore, the maximum hook load for drilling (typically fishing) and casing operations are evaluated with the number of lines used or required. The crown load is calculated from this equation :

CL = HLN + 2

N⎛ ⎝

⎞ ⎠

(12.1) Where:

CL = crown load, lbsHL = hook load, lbs

N = number of lines strung

A more rigorous relationship for crown load based on sheave and hoisting efficiencies may be used, however the difference is less than 1% from the values determined by the equation above.

Derrick/mast and crown are sized from the maximum crown load, and traveling equipment rating is determined from the maximum hook load.

12-10

Drawworks

A drawworks is typically rated on input power. However, single line pull also determines the capability of the drawworks to hoist a load. Simply put, input power is a measure of tripping capability, single line pull is a measure of the maximum hook load capacity of a drawworks.

Tripping the drillstring usually determines the power requirements of the drawworks. Use the hook loads calculated in the Torque and Drag Predictions section for tripping in open hole and cased hole at appropriate hoisting speeds. The nominal rating of large drawworks is established for hook speeds in the range of 90–120 ft/min with eight lines to the traveling block. The high drag in ERD wells will most likely dictate lower. The input power to the drawworks is determined from the power at the hook plus power losses due to friction of bearings, chains and the wire line that make up the hoisting system (see Efficiencies). The power output at the hook is calculated by:

PHook =

HL S33,000 (12.2)

Where: PHook = power output at the hook, hp

HL = hook load, lbsS = hoisting speed, ft / min

Note: This is the drawworks power calculated by DSS.

Input power to the drawworks is determined by dividing the power output at the hook by the drawworks drive efficiency and hoisting efficiency:

PInput =

PHook

Ed Eh

=HL S

33,000Ed Eh (12.3)

Where:

PEE

Input

d

h

=

==

input power, hpdrive efficiency, Table 12 - 4hoisting efficiency, Table 12 - 5

The drill line breaking strength is calculated from the maximum fast line tension and a design factor. API RP9B (Reference 12-5) recommends using a design factor of 3.0 for normal drilling and tripping operations and 2.0 for running casing and fishing operations. (Note: This design factor is based on the material uncertainty and is independent from the one discussed below.) The drill line size is then determined from the maximum drill line breaking strength requirement.

12-11

Rotary/Top Drive

Rotary requirements are based on the maximum torque and input power. A major limiting factor in ERD operations is the surface torque requirement (which can be calculated with DSS). Rotary power is a function of both surface torque and rotary speed, and is also calculated by DSS. Input power is determined from the rotary power and appropriate drive efficiency. The procedure for sizing top drives and rotary tables is identical. Refer to the manufacturer’s documentation for performance specifications.

The rotary table must also be large enough to accommodate the largest casing size or tool and support the heaviest hang-off load.

Mud Pumps

Mud pumps are rated on input horsepower, which is a function of flow rate and pump pressure. Determine the flow rate and pressure requirement for each hole section from the Hydraulics Model.

Input power requirements are determined from the flow rate, pump pressure, and various efficiencies—drive, mechanical, and volumetric. DSS calculates a hydraulic power requirement, but results from the Hydraulics Model are more accurate. Use these predicted values to determine the number, horsepower rating, and liner sizes of mud pumps required.

Rig Power

In ERD wells, the maximum drilling power requirement generally occurs while backreamming the 12 1/4 inch hole. Determine the maximum drilling power from the sum of the input power of the drawworks, rotary system, and pumps for any operation. The rig generating power requirements is the sum of the maximum drilling power requirements, auxiliaries and hotel loads, taking into consideration the transmission efficiency of the rig power system.

12-12

Substructure

The substructure must have the setback capacity to support the drill string at the TD. There must also be sufficient capacity in the derrick/mast for the drill string. The substructure must support the maximum casing plus drill pipe setback load corresponding to the casing string—normally the 9 5/8 inch casing plus the drill string used to drill the 12 1/4 inch hole.

Mud Processing/ Circulating System

The mud processing system must have sufficient capacity to handle the high volume and flow rates encountered in ERD wells. Oil-base muds play an important part in ERD wells, and the capability to process these mud systems should be considered (see Section 6, “Drill Fluids Optimization”).

The size and pressure rating of the surface circulating system should also be considered to maximize the hydraulic requirements.

Drill String

Drill string requirements are based on hydraulic, torque, and hoisting requirements determined from the DEAP simulation. Use the results of these simulations and refer to Section 9, “Drill String Design” to determine the drill string requirements.

12-13

EVALUATION

The results of the rig sizing process should be evaluated to determine if the objectives were met.

• Can the rig drill the proposed well? • Is there excess capacity? What modifications are required? • Are the specifications achievable and cost effective?

Keep in mind when specifying a new rig or requesting modifications to an existing rig—the systems are not independent and a change to one system may require a change to another. Be aware of the "hidden" costs of these modifications—additional solids control equipment to handle the high flow rates; larger drill pipe may require modifications to the pipe handling system, top drive and monkey boards are just a few.

Finally, the rig sizing process is iterative. Consider the factors effecting critical or marginal rig components. Determine if your assumptions were reasonable or overly conservative. Evaluate the well requirements and design to determine how changes may affect the rig specifications.

Lower design requirements—100 kip overpull on casing and stuck pipe.

Additional factors such as number of wells, geologic uncertainty, timing, availability, logistics, mobility and deck loading must also be considered.

The rig sizing is based on engineering principles and will yield a quantitative result based on many assumptions. When making these assumptions it's important to be aware of the objectives and constraints of the ERD project. Can the project handle the cost of a major rig upgrade? Is it more cost effective to drill at a reduced ROP? A large development project may justify upgrades but a single well project may be completed successfully with less than ideal equipment. Some of these assumptions will result in equipment requirements that are costly or difficult to obtain. However, that specification may be costly. but a clear understanding of the project objectives is necessary.

However, the objective is to determine reasonable operational data to use in sizing rig components, not optimize the well design.

EXAMPLE

An Excel spreadsheet has been developed to summarize the DEAP runs and perform the necessary calculations. Attachment 12-1 is an example of the results.

12-14

REFERENCES

1. Rig Sizing – UK Land Wells - Kelso, Gary, BPX Internal Report, June 1989.

2. Drawworks Depth Ratings: How to Evaluate and Apply Them - Cordrrey, R. N., IADC Drilling Technology Conference Transactions, 1980.

3. Fitting Drilling Rigs to Their Job...Whether Rig is New or Old - Crake, W. S., SPE Reprint Series, 1973.

4. How To Determine Your Rig's Depth Limit - L'Espoir, John, Petroleum Engineering International, April 1984.

5. API RP9B, Recommended Practice on Application, Care and Use of Wire Rope for Oilfield Service, May 1986.

12-15

RIG SIZING AND SELECTION

Data Requirements Well Design Evaluation/completion requirements

Directional plan Casing program Drilling mechanics

Rig specifications

Hydraulic Considerations/Hole Cleaning Define minimum flow rate Hole angle

Mud properties Lithology

Drill pipe considerations Pressure losses Annular velocities

BHA and downhole tools

Torque and Drag Predictions Define friction factors

Drilling Tripping Casing/liner

Define ripple factors (tortuosity)

Predict torque and drag Drilling Backreaming Tripping Casing/liner Fishing

Sensitivity/reality check

Equipment Sizing and Requirements Crown and Derrick/Mast

Hoisting equipment

Top drive

Circulating system Hydraulic power Pressure rating

Power

Substructure

Mud processing equipment

Drill string

BOP equipment

Uncertainty

Evaluation Does rig meet specifications?

Are specifications achievable?

Economic considerations

12-16

Section 13 Surveying Principles and Practice

• Setting Clear Objectives

• Hitting the Target - Anti-Collision - Contingency for Relief Well Drilling - Tools and Techniques - Magnetic Surveys - Magnetic Bias - Magnetic Interference Corrections - In-Hole Referencing - In-Field Referencing - Gyro and Inertial Surveys - Running Methods - Continuous vs. Stationary Tools - Gyro While Drilling - Survey QA Tool Comparison and Learning

• Surveying - Principles and Practice

• Setting Objectives

• Program Design and Tool Limitations

• References

• Contacts

13-1

INTRODUCTION

You can drill a perfectly good ERD well without good wellbore surveys - but chances are it will be in the wrong place. Errors which can be safely ignored for most wells, take on real significance when trying to hit distant targets. Several factors work together to magnify the effects of small errors:

• Systematic errors accumulate over a longer distance • Instrument errors are generally greater at high inclination • Targets appear smaller when approached at high inclination

There is the additional problem of getting wireline tools to bottom in high-angle hole. And, of course, surveys in long wells take longer and cost more.

With all these difficulties to overcome and considering the cost of incorrect well placement, the importance of careful survey management in ERD wells is clear. Stick to these basic principles:

• Set clear objectives • Put together a plan to meet them. This is survey program design which must take

account of each tool's limitations • Monitor performance with Quality Assurance checks and tool comparisons • Don't miss opportunities to learn

SETTING CLEAR OBJECTIVES

Choosing which surveys to run in a well is guesswork, without clear objectives. Examples of the sort which help are:

• Keep the risk of missing the target below X% • Keep the risk of hitting another well below Y% • Take every reasonable precaution against being unable to locate the well with a relief

well

HITTING THE TARGET

Target shapes increasingly reflect geological reality. Whatever the shape of the target, the driller must aim the well somewhere near the center to be sure that unknown survey errors don't carry the actual trajectory outside the boundary. This is called target sizing; the resulting, shrunken target is called the Driller's target. Using DEAP/DDSS, target sizing can be performed on geological targets in the form of convex polygons, at any orientation. Incorporation of the uncertainty in the target boundary itself (a concept being pioneered in Alaska) is planned for release in 1996.

The smaller the tolerable risk of missing the target due to survey error, the smaller will be the Driller's target. In Aberdeen, where quantitative target sizing was introduced, a tolerable risk of 1% has conventionally been used, with relaxation to 5% (i.e. 95% confidence) on occasion. In statistics, 95% is normally regarded as the lowest significant level of confidence, so relaxation beyond this is probably inadvisable.

13-2

In practice, most targets are defined as horizontal despite the increasing difficulty of hitting them at high inclination. The maximum entry inclination for a horizontal target varies from well to well. For Wytch Farm M05, a Driller's target was successfully defined at an entry inclination of 81°.

Horizontal section must be inside this volume

Driller’s Target

Target before sizing

At high approach angles a vertical targetmay be more realistic - and easier to hit

Well Direction

In Northern latitudes, magnetic survey biaswill deflect the Driller’s target to the North.

Driller’s Targets in High Angle and ERD Wells

H = highside uncertainty

Target is foreshortened

cos(incl)H

cos(incl)H H increases at high

inclination

cos(incl)H

Horizontal targets approached at high inclination are greatly foreshortened due to survey errors

by

Anti-Collision

ERD wells are frequently planned to pass close to existing exploration wells near the reservoir. Since the survey uncertainties involved are large, conventional anti-collision rules imply the need for large well separations. In reality, such rules are often grossly over-conservative. In many cases, the probability of a collision is so small that it can safely be ignored. DEAP/DDSS can perform this calculation automatically. To get an approximate value manually, use the equation:

Probability of collision =

d d Dp d+− ☺σ π σ2 2

2

2exp

Where d are the diameters of the planned and drilled wells, D is the separation between the wells and dp , d

σ σ σ= +p2 2

d where σ σp , d are the semi-major axis uncertainties in the planned and drilled wells at 1 standard deviation.

13-3

Contingency for Relief Well Drilling

The contingency for drilling a relief well to intersect a blowout at source must be considered when designing every ERD well. Downhole ranging tools can only detect wells containing casing or drill pipe, which makes a blowout at the end of a long, open hole section particularly difficult to intersect. As a precaution against this, casing must be set, wherever possible, prior to entering any potentially pressure bearing zone. Whether or not this is possible, a multishot survey must be run before drilling ahead.

Tools and Techniques

Survey vendors won't always emphasize their tools' limitations, so make sure each tool in the survey program can perform the job it is being asked to do.

Magnetic Surveys

Being solid state and therefore robust, measurement while drilling (MWD) and electronic multishot (EMS) tools are physically suited for extended reach applications. Another strong point is the ability to check one instrument against another. MWD tools and collars should be changed out on every trip, and electronic multishots should be run in stacks of at least two (preferably three) probes. On the down side, all magnetic tools have two fundamental weaknesses:

• They rely on an accurate knowledge of the Earth's magnetic field • They are susceptible to interference from other magnetic fields

Magnetic Bias

Despite the use of non-magnetic collars, magnetic survey sensors are always influenced to some extent by magnetization of the drill string. Theory suggests that in northern latitudes the resulting error will generally be to the north, and a study of surveys in Alaska confirms this. The latest estimate is that magnetic surveys will lie north of gyroscopic surveys 77% of the time. The effect is certainly present in Alaska and the North Sea, but has not been studied properly in mid, low, and southern latitudes. This "bias" of magnetic surveys to the north has two effects:

• Where the gyro survey lies say 1°-3° to the North of the MWD, both should be regarded with more suspicion than if the gyro lies say 1°-3° to the South.

• To reduce the chances of missing the geological target, aim slightly north of center. The DDSS target sizing routine takes account of this.

Used "stand-alone", magnetic surveys seldom meet the accuracy requirements of ERD wells. The techniques mentioned below are means of enhancing this accuracy.

13-4

Magnetic Interference Corrections

There are several fairly simple mathematical algorithms which attempt to correct MWD or EMS for drill string magnetic interference. They require a good estimate of the Earth's magnetic field, and can give wrong answers if the value is in error. Unless the local magnetic field has been specially measured, their only real application is as a QC device for detecting gross interference. The main examples in use are:

• SUCOP/D-RAW/PC-RAW (Shell/BHI/Anadrill) • Short Collar Correction (Sperry Sun) • MAC1 (Halliburton) and ("Blended Algorithm") Scientific Drilling Controls.

Halliburton's MAC2 is unlike these corrections, in that it is less dependent on knowledge of the Earth's magnetic field and can potentially make a more thorough (hence more accurate) correction. It still, however, relies on knowledge of the local magnetic declination. Two trials of the method were completed for BP in Norway in 1993/94 with promising results.

In-Hole Referencing

In-hole referencing is a technique which helps compensate for uncertain knowledge of the Earth's magnetic field, hence reduces systematic errors over long tangent sections. The method involves running a gyro several hundred meters into open hole to establish a baseline for subsequent correction of MWD and EMS. [1] has more details. In-hole referencing has long been established in BP's UK operations, but has only recently been adopted in Alaska. The method potentially offers significant accuracy gains at little extra cost, but is critically dependent on the quality of the gyro reference survey. The first instrument used was the Schlumberger GCT, which at the tangent angles then common in the North Sea (45°-60°), could be run slick below the 13-3/8 inch casing and usually produced smooth, reliable surveys. More recently, tangent angles have increased and the GCT has been withdrawn. The reference survey is now usually a Gyrodata or SDC Finder tool run inside drill-pipe. The quality of these surveys is variable, but following the general rules in [1] and in the JORPs will help ensure success.

In-hole referencing can only be applied over tangent sections. Normally, the in-hole reference interval will be at the start of the tangent. In Wytch Farm, the wells continue to build through the interval, hence invalidating the inclination correction - a BHA sag correction was applied instead.

In-Field Referencing

In-field referencing is a technique developed and patented by Sperry Sun for correcting MWD and EMS data using real-time values of the local magnetic field. It was tried (June/July 1995) at Wytch Farm with encouraging results [3]. On land, the method is cheap and easy to run. Development of a system for use offshore is feasible, but is awaiting confirmation of reasonable market. At the high latitudes of Alaska, the complexity of magnetic field variations probably precludes use of this method.

13-5

Gyro and Inertial Surveys

In the right application, gyros give accurate, reliable results, but do not overestimate their capabilities at high angle. The accuracy of nearly all gyro instruments reduces at high inclination. In practice, the effect tends to be masked by the sharp decline in data quality when switching from running centralized to running in drill pipe or pumping down casing. That said, inclination limitations can be derived from considerations of tool design coupled with experience:

Gyrodata Physical limit is 90° - poor quality data is increasingly frequent above 75°

SDC Finder Physical limit is 108° - no inclination related problems yet seen

Sperry Sun G2 Too big to be run in drill-pipe, but accuracy would degrade rapidly above about 70° anyway

Inteq RIGS Too big to be run in drill-pipe - accuracy degrades slightly at high inclination

Running Methods

The only way to get a quality survey with a high degree of confidence is to run the tools free-fall in casing (centralized or low-side). The maximum inclination achieved can vary from under 50° to over 80°. Undisturbed cuttings beds, viscous mud, and severe doglegs are sure ways of making the tool hang up early.

Pumping a wireline tool down the drill pipe is a well-established means of surveying at high angle and into open hole, but typically gives erratic azimuth results which make selection of reliable in-hole reference intervals difficult. Surveys in Wytch Farm and Pompano have also indicated the presence of unexplained systematic inclination errors resulting in large TVD discrepancies.

Gyrodata has a battery-powered version of their tool which can be run in on slickline and seated in an orienting shoe. The line is then released and withdrawn and the survey taken while tripping out. A version of the tool capable of withstanding a free-fall into drill pipe is due for testing in 1996.

Pumping down a wireline tool inside casing is a promising technique first tried by Statoil with the Schlumberger GCT. The tool is run with a cement plug connected to the bottom with a weak link. Statoil has had some success with this method, but a trial on Gyda using the Inteq RIGS tool highlighted a potential problem - the wireline must be kept in tension while the tool is pumped to maintain accurate depth control. Wireline operators experienced with this technique would be an advantage.

Continuous vs. Stationary Tools

Gyro tools which require to be stationary to take surveys are rapidly becoming obsolete. Continuous tools save time and allow a greater station density. The improvement in positional accuracy is modest, but detection of doglegs and measurement of tortuosity is greatly enhanced. The Sperry Sun G2 now runs continuously; the continuous version of Gyrodata's tool is still undergoing field trials. The SDC Finder must be stationary below 15° inclination, but makes up time by running at up to 250ft/min at higher angles. The Inteq RIGS tool is potentially faster still, but its weight limits the speed of outrun in extended reach applications. Speed is not always an advantage and it is easy to run in hole too quickly. A drop in tension means the wireline is spooling out faster than the tool is descending, causing a depth error.

13-6

Gyro While Drilling

A gyroscopic tool capable of withstanding the rigors of rotary drilling over long periods has yet to be developed. Delco Systems (part of GM Hughes Electronics) is planning trials of a solid state gyro which will fit into a standard sub. The theoretical performance is exciting, but the system remains unproved.

Survey QA Tool Comparison and Learning

Apparently good surveys can contain significant errors, although use of the JORPs reduces their frequency. To spot bad data quickly, check all multishots against MWD as soon as they are run. It is often clear straight away that the two datasets are in disagreement. If there is any doubt, DEAP/DDSS can provide a quantitative measure. The following diagram gives some ideas on how to proceed once the disagreement is confirmed.

Arethere significant

doubts about eithersurvey ?

Whichsurvey would you choose to “play

it safe” ?

Has thecause of the

discrepancy beenidentified

?

Decide whichsurvey to tie-in to

Request a change to JORPs and inform DTG

Request the multishot Wellsite QASummary Sheet and all the MWDbenchmark and check shot data

Get the MWD company to apply a magneticcorrection to the data

Make up a large scale T-plot with

all the survey data

Ask the survey companyto suggest a change in

procedures that willprevent it’s recurrence

Don’t let it rest once the pressure

is off - an errorwithout an explanation

will occur again

Canthe change be

included in a procedurereferenced in

JORPs?

Run another survey

Decide which surveyto accept as definitive

Can you reasonably run another

survey ?

Isthere another

hole section for whichyou need to choose

a tie-in?

Request a changeto the procedure

Resolving a Discrepancy Between Surveys

Things to Do, Questions to Ask

No

No

No

No

Yes

Yes

Yes

Yes

SURVEYING - PRINCIPLES AND PRACTICE

Larger uncertainty, accumulating over a longer distance leaves, little room for error when surveying ERD wells. Remember the principles: objective setting, design, QA, and investigation.

13-7

SETTING OBJECTIVES

• Target Definition: The target should reflect the geological. • Target Sizing: Establish contingencies for missing target. • Anti-Collision: Evaluate separation rule versus costing by doing a risk analysis. • Relief Well Contingency: Establish relief well contingencies for locating the wellbore.

PROGRAM DESIGN AND TOOL LIMITATIONS

Typical Wytch Farm Program

Instrument Run Type Hole Interval Gyro Orientation Single Shots • 24 inch and 17-1/2” hole sections until clear of magnetic

interference from existing wells

• Cluster shots until azimuth spread negligible

• BHA correction applied

MWD • Every 30m until through remaining 17-1/2 inch section


MWD • Every 30m until +/- 300m below 13-3/8 inch casing shoe

• Run gyro inside casing into open hole. (If hole angle greater than +/- 65 degrees, then drillpipe pump-down may be required in open hole).


MWD • Every 30m, increasing to every 60m once tangent section established

• Apply gyro IHR correction to asimuth


Pump down 3 stack EMS • Section TD (optional)

MWD • Every 30m in 8-1/2 inch section Definitive concatenation:

• Gyro multishot

• MWD (or EMS) with IHR

• MWD

13-8

Gulf of Mexico Survey Program Report

Instrument Run Type Hole Interval Gyrodata Large ID (>13-3/8”) Csg Mshot Conductor

Gyro Orientation - North Seeking Gyro Surface

MWD - Standard (declination corrected) Surface

Gyrodata Large ID (>13-3/8”) Csg Mshot Surface

MWD - Standard (declination corrected) Intermediate

Gyrodata DP or small ID Casing Multishot Intermediate

MWD - Standard (declination corrected) Drilling Liner

EMS + BHA Correction Drilling LIner

MWD - Standard (declination corrected) Production

EMS + BHA Correction Production

Be sure to select every tool based on its capabilities.

Magnetic Tools

• Must always be checked against another tool. Be sure your survey program caters for this.

• Consider what enhancement techniques are going to be used (in-hole referencing, magnetic corrections, in-field referencing) and if they are appropriate to your well.

Gyro and Inertial Tools

• Be sure the tool will get to bottom if run in casing. If it won’t, consider whether the extra reliability and accuracy will outweigh the reduced range. Consider pumping down in casing as an alternative to running in drill-pipe.

• Be sure the hole inclination is within the range of the tool.

• If the tool doesn’t run continuously, consider how long the survey will take. You want to get a good measure of tortuosity.

QA, Tool Comparison and Learning

• Tool comparisons must be made immediately so that a timely decision on running another multishot can be made. When tool disagreements occur:

• The gyro is usually South of the MWD.

• It is unusual for the gyro to be North of the MWD.

• Check all the QA data prescribed in the JORPs and make up a T-plot

• Consider applying magnetic interference or depth corrections.

• After the decision is made, keep up the pressure on the survey companies to find an explanation.

• A change in procedures may keep the same thing from happening again.

13-9

REFERENCES

1. "BPX Directional Survey Handbook, v1.0", XTP-DTG, July 1993.

2. "DDSS User Guide, v2.3", Hugh Williamson, XTP-DTG, July 1995.

3. "In-Field Referencing Trials at Wytch Farm", Hugh Williamson, XTP-DTG, September 1995.

Copies of JORPs can be obtained direct from the Survey Company (MWD: Inteq, Sperry Sun, Halliburton, Anadrill; Survey: Inteq, Sperry Sun, SDC, Gyrodata).

Contacts

Specialty Name Location Telephone Fax XTP Survey Specialist

Hugh Williamson XTP Dyce 44 (0)1224 833694 44 (0)1224 833586

BPX Drilling Global Consultant

John Thorogood PSR Dyce 44 (0)1224 833585 44 (0)1224 832827

Trevor Hogg BPX Colombia 57 1 623 4077 57 1 618 3215

13-10

Section 14 Drill String Dynamics

In this Section... • Severe Vibration - How To Know Severe Vibration is Occurring - Symptomology and Control of Vibration - Controlling Severe Vibration - Vibration Monitoring Tools - Consideration of Geology

• References

SEVERE VIBRATION

Severe vibration is defined as vibration events which can cause rapid damage to the bit, drill string, and the bottom hole assembly (BHA) components. Drilling vibration which is normally present and which causes string failure by slow fatigue crack growth (usually within 200-400 drilling hours) is not classified here as severe vibration.

How To Know Severe Vibration is Occurring

• Cyclic surface torque • Top drive stalling • Premature bit failure (by impact damage rather than abrasive wear) • Vibration damage to internal measurement while drilling (MWD) components • Excessive or unusual wear on tool joints and stabilizers • Frequent washouts and twist offs

14-1

Severe vibration should be minimized/eliminated via proper rig site vibration monitoring and control. Non-severe drilling vibration should be quantified through proper drill string fatigue inspection.

Symptomology and Control of Vibration

The following table summarized the types of vibration, commonly observed symptoms for each type, and steps to control them.

Vibration Type Symptoms Control

Slip-stick (torsional) Cyclic surface torque fluctuation/top drive stalling. Connection over-torque and back off.

Increase RPM and/or reduce WOB. Installation of soft-torque feedback system on the topdrive. In ERD wells, high drill string torque reducing techniques such as non-rotating drill pipe protectors, higher lubricity mud and smoother well profile are helpful.

Bit whirl (lateral) Cutter impact damage (usually on the bit nose). Impact damage to bit gauge pads. Increased MWD shocks. High frequency lateral/torsional vibration (detectable downhole). Repeated slow build-up/abrupt drop in surface torque.

Reduce RPM and/or increase WOB. Use anti-whirl bits, or other bits with built-in lateral bit stability. Pick up off bottom for a few seconds, and stop/restart rotation.

BHA Whirl (lateral) Localized tool joint wear. Increased MWD shocks. Erratic surface torque.

Reduce RPM and/or increase WOB. Higher lubricity mud. Use non rotating stabilizers and tool joint protectors. Use roller reamers rather than stabilizers.

Bit Bounce (axial) Large surface vibration (obvious in shaking of equipment). Large WOB fluctuations. Bit damage, usually tricones in hard formations.

Use shock sub. Adjust drilling parameters (often to higher RPM and/or lower WOB).

Parametric resonance (axial/torsional/lateral)

Increased MWD shocks. Large WOB/bit torque fluctuations

Each vibration type can trigger other types of vibration. Therefore, more than one vibration type is usually occurring. Note that many of the vibration suppression techniques in the table are cures for one type of vibration only (e.g. running an anti-whirl bit will not normally cure slip-stick.)

Slip-stick and bit whirl commonly occur with drag (PDC) bits while bit bounce is usually only found with tri-cone bits. In ERD wells and wells with high tortuosity, slip-stick torsional vibration can become very common due to additional string-wellbore interaction.

14-2

Some symptoms (e.g. MWD shocks) can occur with more than one vibration type, hence to correctly identify the prevailing vibration type we often need to detect more than one symptom.

Controlling Severe Vibration

Each type of vibration types have their own characteristics and require a specific cure. Often corrective measures for one mechanism can exacerbate another. Therefore, effective vibration suppression requires that you first detect what vibration type is occurring downhole, before you prescribe remedial actions.

Vibration Monitoring Tools

Vibration detection can be greatly assisted by appropriate surface and downhole monitoring tools. Downhole lateral vibration in particular is heavily attenuated along the drill string and does not propagate to the surface. In such cases, downhole detection is required.

The most commonly used monitoring techniques are:

• Tool inspection (e.g. nature of damage on downhole drilling components, impact damage on PDC cutters).

• Mud-logging data, either in the form of measured variation in surface torque (either via sigma torque, or the departure between minimum and maximum torque per foot drilled), or via a special slip-stick monitoring package, which many mud-logging companies now provide.

• MWD data (e.g. shock counts with or without gamma ray) for detecting downhole lateral vibration and its correlation to the changes in the lithology. Anadrill and Baker Hughes INTEQ provide MWD with shock measurements, Anadrill also provides MWD with 3-axis and 4-axis accelerometers to detect lateral, torsional and axial vibration. Sperry-Sun provides a downhole recording tool for measuring lateral, torsional and axial vibration.

14-3

Rotary Feedback Systems

Rotary feedback systems are used to reduce the amplitude of variations in rotary torque as shown in Figure 14-1. Although there are several rotary feedback systems available, only three have seen significant application. The Deutag Mark I Soft-Torq system can be effective at suppressing torsional vibrations, and is still in service in several areas, particularly Colombia. An improved Mark II system has been available for some time, and has provided good service at Wytch Farm. The third system is marketed by Sedco, but has generally failed during several trials in Colombia. It is not yet sufficiently robust to survive in the drilling environment.

ROTARYFEEDBACK

ON

ROTARYFEEDBACK

OFF

DRILLING TORQUE (ft-kips)

ROTARY SPEED (rpm)

30

2500

0

Figure 14-1. Rotary Feedback

Consideration of Geology

Many types of vibration are closely related to formation type and properties. Slip-stick for instance is often more severe in hard limestones or sandstones than in more drillable lithologies like shale. The presence of such formations in planned ERD wells should be taken as a warning indicator of potentially severe vibration problems, and vibration suppression techniques planned into the drilling program.

14-4

REFERENCES

1. Abbassian F., "Drill String Vibration Primer", BP Exploration, January 1994.

2. Brett, J.F., Warren, T.M., and Behr, S., "Bit Whirl: A New Theory of PDC Bit Failure", SPE Drilling Engineering, 275-281, December 1990.

3. Kyllinstad, A., and Hasley, G.W., "A Study of Slip-Stick Motion of the Bit", SPE 16659, presented at the 62nd Annual SPE Technical Conference and Exhibition, Dallas, Texas, September 1987.

4. Fear M., and Abbassian, F., "Experience in the Detection and Suppression of Torsional Vibration from Mud Logging Data", SPE 28908, presented at Europec Conference, London, October 1994.

5. Payne, M.L., Abbassian, F., and Hatch, A.J., "Drilling Dynamic Problems and Solution in Extended-Reach Operations", presented at the ASME Energy-Sources Technology Conference and Exhibition, Houston, Texas, January 1995.

6. Zannoni, S.A., Cheatham, C.A., Chen, D.C.K., and Golla, C.A., "Development of Field Testing of a New Downhole MWD Drill String Dynamics Sensor", SPE 26341, presented at the SPE Annual Technical Conference and Exhibition, Houston, October 1993.

7. Dufeyte, M.P., and Henneuse, H., "Detection and Monitoring of Slip-Stick Motion: Field Experiments", SPE/IADC 21945, presented at the SPE/IADC Drilling Conference, Amsterdam, March 1991.

8. Macpherson, J.D., Mason, J.S., and Kingman, J.E.E., "Surface Measurement and Analysis of Drill String Vibrations While Drilling", SPE 25777, presented at the IADC/SPE Drilling Conference, Amsterdam, February 1993.

9. Altred, W.D., and Sheppard, M.C., "Drill String Vibrations: A New Generation Mechanism and Control Strategies", SPE 24582, presented at the Annual Technical Conference and Exhibition, Washington DC, October 1992.

10. Rewcastle, S.C., and Burgess, T.M., "Real-Time Downhole Shock Measurements Increase Drilling Efficiency and Improve MWD Reliability", SPE 23890, presented at the IADC/SPE Drilling Conference, New Orleans, February 1992.

11. Warren, T.M., Brett, J.F., and Senor, L.A., "Development of a Whirl-Resistance Bit", SPE Drilling Engineering, December, 1990.

12. Brett, J.F., "The Genesis of Torsional Drill String Vibration", SPE Drilling Engineering, September 1992.

13. Dunayevsky, V.A., Abbassian, F., and Judzis, A., "Dynamic Stability of Drill Strings under Fluctuating Weight on Bit", SPE Drilling Engineering, June 1993.

14. Vandiver, J.K., Nicholson, J.W., and Shyu, R.J., "Case Studies of Bending Vibration and Whirling Motion of Drill Collars", SPE 18652, presented at the SP/IADC Conference, New Orleans, 1989.

15. Jansen, J.D., "Whirl and Chaotic Motion of Stabilized Drill Collars, SPE 20930, presented at Europec Conference, The Hague, October 1990.

14-5

Section 15 Well Control Guidelines for Drilling High Angle or Horizontal Wells

In this Section...

• Kick Tolerance

• Kick Prevention and Detection

• Well Shut-In and Surface Pressures

• During Well Shut-In Period

• Well Kill Techniques

• Trapped Gas in Inverted or Horizontal Hole Section

• References

INTRODUCTION

The following summarizes the key differences in well control procedures/techniques for drilling high angle and horizontal wells. Please consult the relevant sections in the BP Well Control Manuals (Vol. 1 and 2) for more details.

15-1

KICK TOLERANCE

The BP Excel Well Control Toolkit (Excel Toolkit) should be used to calculate the kick tolerance for a high angle or horizontal wells.

In a high angle or horizontal well, the kick tolerance volume should be checked against the maximum allowable surface pressure, based on the rated pressure of the well control equipment and the casing. This can be done using the Excel toolkit.

The surface pressure safety factor should include:

• Choke operator error (100-150 psi) • Annular pressure loss from casing/liner shoe or openhole weak point to surface • The pressure loss through choke line (if not compensated for during kill)

The pressure losses can be estimated using the Excel Toolkit.

KICK PREVENTION AND DETECTION

All techniques used in vertical wells for avoiding and detecting kicks can be applied to high angle or horizontal wells.

Kick intensity is potentially high when drilling a horizontal well due to the longer hole section exposed to the producing formation.

The swab/surge pressure is relatively high in a high angle or horizontal well. To prevent swabbed kicks, it is important to ensure that:

• The mud rheology is conditioned prior to tripping out • The tripping speed is controlled below the maximum allowable speed • The correct tripping procedures are followed

The equivalent circulating density (ECD) is relatively higher when drilling a high angle well. This may mask an over-pressurized formation. Therefore, it is important to flow-check the well when circulation stops to ensure that the well is stable without the ECD effect.

15-2

WELL SHUT-IN AND SURFACE PRESSURES

Use the hard (fast) shut-in method upon detecting a kick to minimize the kick volume. Studies showed that the potential water-hammer effect associated with the hard shut-in is negligible.

When a kick occurs in a high angle or horizontal hole section, the shut-in drill pipe pressure (SIDPP) may be close or equal to the shut-in casing pressure (SICP). This is because the kick only causes a small or no hydrostatic pressure reduction in the annulus.

Zero shut-in pressures (SIDPP & SICP) does not mean there is not kick. Together with a positive pit gain, this may indicate that the kick is still in the horizontal hole section, which may be caused by swabbing or improper hole fillup on trips.

One or more of the following may indicate that a kick has occurred in a high angle or horizontal well:

• Increased mud return flowrate • Positive pit gain • Drilling break • When the well is shut in, the SICP may be greater than SIDPP (influx above horizontal

section), or both are equal and greater than zero (influx in horizontal section with under-balanced kick), or both are zeros (influx in horizontal section with swabbed kick)

DURING WELL SHUT-IN PERIOD

The conventional method, which determines the influx density/type (gas/water/oil) based on pit gain, SIDPP and SICP, can not be applied in a high angle or horizontal well. This is because the influx will stay along the top-side of the annulus. There is no simple alternative method yet for field applications.

A gas influx may be recognized by the continuous increase in SICP, which may be caused by gas expansion above the horizontal hole section due to gas migration or mud circulation.

During the well shut-in period, the free gas may migrate up the annulus if the angle is below 90o. The gas migration rate depends upon mud rheology, hole size and hole angle. Increasing mud yield stress or gel will reduce the migration rate.

Do not calculate the migration rate based on the increase in SICP, as it often seriously under-predicts the migration rate.

Gas does not migrate if:

• Hole angle is 90o or higher, or • Gas is dissolved in the OBM, or • Gas is trapped as small bubbles in mud by its high gel strength

15-3

WELL KILL TECHNIQUES

The advantages of the Wait & Weight method over the Driller’s method are less important in a high angle or horizontal well. This is because the weighted mud will not reduce the surface and casing shoe pressures until it has passed the high angle or horizontal hole section. By then the gas influx may have entered into the casing, or been circulated out of the well.

Do not wait for the mud to be weighted up. Start to circulate using the Driller’s method once a kick is detected and the stabilized shut-in pressures are established. In the mean time, prepare the kill weight mud in the reserve mud pits. The earlier start of the circulation will reduce the risks of stuck pipe and other hole problems associated with stagnant mud.

When circulation is switched to the kill weight mud, use the kick sheet designed for high angle wells (Excel Toolkit) to calculate the standpipe pressure schedule. Do not use the conventional kick sheet designed for vertical wells, as it will result in excessively high well pressures and the possible consequence of breaking down the formation at the weak point.

While circulating out a gas influx, the free gas will slip through and travel faster than the mud, even in a horizontal hole section. Therefore, the influx may arrive at surface earlier than the mud. The influx slip velocity mainly depends upon the mud rheology, hole size and hole angle.

TRAPPED GAS IN INVERTED OR HORIZONTAL HOLE SECTION

If a gas kick occurs when drilling an inverted (>90o) hole section, the free gas will be trapped there when circulation stops. Similar scenarios may also occur in washouts or undulations of a horizontal hole section.

Upon detecting a kick in horizontal or inverted hole, the first attempt to kill the well is to use one of the standard techniques (Driller’s or Wait & Weight).

If the standard technique fails to circulate the kick to surface, it indicates that the kick is free gas and has been trapped in the inverted or the horizontal hole section.

To remove the entrapped gas, the mud needs to be circulated at an annular velocity above 100 ft/min, which is higher than that at a commonly used silicon controlled rectifier (SCR). Therefore, special well kill techniques may have to be considered.

The trapped gas may be flushed out by using the following procedures:

1. Start circulation using Driller’s method at a high SCR (corresponding to 100-150 ft/min) until the entire horizontal hole section has been displaced.

2. Reduce to a normal SCR and continue to circulate until one complete circulation. 3. Shut the well in to check the pit gain and surface pressures. 4. If there is still a positive pit gain, it indicates that some gas is still trapped. Repeat the

previous procedures.

The above requires determining the pump pressures at the high SCR prior to drilling the inverted/horizontal section.

15-4

If the above procedures fail to remove the trapped gas, consider bullheading the gas back into the formation. Since the trapped gas should be near the kicking formation, bullheading is more likely to succeed in an inverted hold section. However, this should be assessed against the following factors:

• The rated pressure of the well control equipment and casing • Risk of formation breaking down at the openhole weak point • Damage to reservoir formation

REFERENCES

1. BPX Well Control Manual

2. The Super Volume Estimator Spreadsheet

3. The Equipment Performance Evaluation Spreadsheet

15-5

Section 16 Stuck Pipe Prevention

In this Section...

• Well Planning - Anticipating Probable Mechanisms

• Differential Sticking

• Formation Related - Geopressured - Reactive - Unconsolidated - Mobile - Fractured/Faulted (tectonic) - Inadequate Hole Cleaning - Wellbore Geometry / Keyseating - Collapsed Casing - Cement Blocks

• Connections Guidelines

• Reaming and Back-Reaming Guidelines

• Freeing Stuck Pipe

• Stuck Pipe Issues

• Contacts

• References

16-1

WELL PLANNING - ANTICIPATING PROBABLE MECHANISMS

As a result of high angle and long openhole sections in ER wells, several situations arise which increase the risk of several stuck pipe mechanisms. These situations include:

• Increased side forces on tubulars in the wellbore • Reduced solids transport efficiency • Altered behavior of formations which are exposed to the wellbore • Unplanned wellbore curvatures (tortuosity) • Long open hole sections with long exposure times • Narrowed wellbore stability/fracture window for mud weight

Each hole interval of the well plan should be evaluated for its stuck pipe risks and tools and procedures should be put in place to avoid stuck pipe occurrences.

ERD can increase the risk of these sticking mechanisms over low-inclination wells:

• Differential sticking • Formation related:

Geopressured, Reactive, Unconsolidated, Mobile, Fractured/Faulted • Inadequate hole cleaning • Wellbore geometry/ keyseating • Collapsed casing • Cement blocks

ERD does not have a significant effect on the incidence of the remaining sticking mechanisms:

• Junk • Undergauge hole • Green cement

Stuck pipe risks in each hole section should be identified during the planning phase. Consider having the team assemble for Stuck Pipe Prevention training to discuss potential changes in practices to minimize these risks. Action plans to avoid stuck pipe should be prepared for each hole interval.

16-2

DIFFERENTIAL STICKING

Summary Points:

• Equipment - stabilize the bottom hole assembly (BHA), minimize drill collars • Wellbore stability - higher mud weight (MW) may result in high overbalance in

permeable zones • Fluids Issues - maintain fluid loss control and optimum overbalance where possible • Operations- keep pipe moving, monitor trends: torque/drag

Differential sticking is caused by concurrent existence of six situations in the wellbore:

1. A permeable formation is exposed in the open hole 2. Overbalanced condition at the permeable formation 3. Thick filter cake accumulation at the formation face 4. String is in contact with the filter cake 5. Insufficient string movement 6. Lack of circulation between the string and the cake

The effect of drilling high angle wells can make some of these situations worse:

• High inclination through the reservoir results in long hole sections with high permeability formations exposed

• Higher mud weights required for mechanical wellbore stability may result in higher than normal overbalance.

• In many instances, OBM or SOBM is used where thick filter cake is not a major issue. • High inclination results in more contact between the string and the wall of the hole. • Sliding mode drilling reduces string movement. • High low-end rheology may reduce circulation between the string and the wall of the hole.

In an ERD well, permeable formations, particularly the target reservoir, are typically penetrated at high inclination. This high inclination often requires increased mud density to counteract in-situ forces and provide adequate mechanical wellbore stability. (This issue is discussed in more detail in Section 5, “Mechanical and Chemical Wellbore Stability”.) Care should be taken to maintain a mud density which will provide appropriate overbalance as these formations are drilled so that high differential pressures can be avoided. If a high mud density is required, the risk of differential sticking is increased and the focus should be on the following issues.

• The filtration properties of the mud should be closely controlled to minimize fluid flow into the formation. The polymers and solids in the mud should be efficient cake builders to provide a thin, impermeable cake. Mud type selection and properties optimization is discussed in detail in Section 6, “Drilling Fluids Optimization”. If using WBM, consider having a premixed tank of spotting fluid available on site which can weighted up quickly. This will help minimize the time before freeing operations can begin if the pipe should become stuck.

16-3

• The configuration of the string should be designed to minimize wall contact, particularly in segments where annular clearance is already reduced like the BHA. The length of the drill collar section should be minimized and replaced with drill pipe or heavy weight drill pipe (HWDP) where applicable. The tool joints on these components help to minimize the wall contact area by providing standoff for the tubes from the wall. Drill collars should also be appropriately stabilized to provide standoff from the wall of the hole while achieving directional objectives. Special operations such as coring should be planned carefully since they typically occur in a high permeability reservoir and the annular clearance is reduced. Core barrels should be stabilized to minimize wall contact.

• The trajectory of an ERW should also be optimized to minimize dogleg severity. Reduction of curvature, other things being equal, will reduce the wall contact forces by the string. Trajectory optimization is discussed in Section 7, “Tubular Design and Running Guidelines”.

• From an operational practices viewpoint, the most important rule is to keep the pipe moving. This is critical in low angle wells and is even more important in ERW applications to avoid differential sticking. Minimize the time spent with the pipe stationary during connections. Consider rotating the pipe slowly in the slips during connections, but only if absolutely necessary. When pulling slips, always initiate pipe movement in a downward direction. Also monitor torque and drag trends on connections and trips to evaluate whether hole conditions are improving or worsening.

16-4

FORMATION RELATED

Geopressured

Psi

Psi

Summary Points:

• Wellbore stability - maintain MW within operating window

• Fluids Issues - maintain proper overbalance

• Operations - monitor trends: torque/drag, cuttings type, shape, and load

Geopressured formations are typically shales or mudstones with low permeability and pore pressure higher than adjacent formations. If the pore pressure exceeds the pressure exerted by the mud column, the formation can “cave” into the wellbore, causing higher cuttings loading in the annulus and hole enlargement.

P

P

P

PP

P

P

P

PP

P

PP

P

Formation

Mud

The higher MW they may require to counteract the higher pore pressure and maintain mechanical stability should be evaluated against the fracture gradient to ensure that it is maintained within the MW “operating window” as described in Section 5, “Mechanical and Chemical Wellbore Stability”.

16-5

Reactive

MUD RINGS

CLAY BALLSSummary Points:

• Wellbore stability - chemically inhibit shales, especially over long exposure times

• Fluids Issues - select proper mud type - OBM or other inhibitive mud


Reactive formations, typically shales with a large amount of bentonitic clay, undergo a chemical reaction, usually water in the mud filtrate causing the formation to swell. Exposure time of these formations with the mud filtrate also determines the severity of the problems. In an ERW, the open hole interval may quite long and as a result may see more severe problems.

Reactive formation problems are combated by selecting a mud type and mud properties which are inhibitive so that the formation does not chemically react with the mud filtrate. OBM is the preferred inhibitive drilling fluid where it is applicable. Fresh water mud systems are to be avoided if reactive formation problems are expected.

Primary operational concerns include torque and drag trend monitoring and changes in mud properties. Be prepared to make regular wiper trips to keep the hole open.

16-6

Unconsolidated

Summary Points:

• Wellbore stability - monitor cuttings load • Fluids Issues - maintain proper

overbalance, fluid loss control, rheology (surge/swab)


Unconsolidated formations are often loosely compacted or poorly cemented sandstones and conglomerates which can become mechanically unstable. Mechanical disturbance can occur as a result of pipe movement past the formation or surge and swab pressures during trips.

A wellbore traversing one of these formations at high inclination could induce mechanical instability on the high side where the formation “overhangs” the hole.

Rheology, mud density, and filtration control should all be maintained carefully in intervals where unconsolidated formations are expected. In an ERW, it is typical to have very high low end rheology to aid in hole cleaning. High viscosity may increase surge and swab pressures and induce instability in these formations. Mud weight should be controlled closely within normal constraints (influx versus lost circulation) to ensure that the formation is never underbalanced and that it is not unduly overbalanced, possibly leading to fracture or unnecessary losses. Filtration should be kept low to minimize filtrate-induced instability. Refer to Section 6, “Drilling Fluids Optimization”.

Monitor torque and drag trends and cuttings type, shape and load. Problems in an unconsolidated formation can very quickly become a hole cleaning problem. Reduce rate of penetration (ROP) or stop and circulate until the hole cleans up. Use pipe movement to improve hole cleaning. Refer to Section 11, “Hole Cleaning and Hydraulics”.

16-7

Mobile

Salt Salt

Summary Points:

• Equipment - Consider enlarging the mobile formation with underreamers/bicenter tools

• Wellbore stability - counteract encroachment with overbalance/mud type

• Fluids Issues - maintain proper overbalance


Mobile formations such as plastic salts and shales squeeze into the wellbore under in-situ stresses. Encroachment might slowed or stopped with increased MW if other ERW mechanical wellbore stability issues allow.

When a mobile formation is encountered, wiper trips should be made regularly to determine the rate of encroachment into the wellbore. Monitor torque and drag as well as the type, shape, and load of cuttings.

16-8

Fractured/Faulted (tectonic)

Summary Points:

• Wellbore stability - maintain MW within operating window

• Fluids Issues - maintain proper overbalance, fluid loss control

• Operations - monitor trends: torque/drag, cuttings type, shape, and load, mud losses

Formations which have been fractured and faulted are exposed to in-situ stresses. How the rock behaves in the area around the wellbore depends upon the orientation of the local downhole stresses and the inclination and azimuth of the wellbore. Estimating the wellbore stresses and defining the operating practices to maintain wellbore stability are discussed in detail in Section 5, “Mechanical and Chemical Wellbore Stability”.

When a high inclination hole section is being drilled, torque and drag trends and mud volumes should be monitored closely looking for indications of hole collapse or losses to the formation. The difficulty arises in long sections at high inclination where many formations may be penetrated. The shales may be prone collapse and require higher MW while the permeable sands or carbonates may not tolerate the higher MW and therefore be prone to fracture and mud losses. It is often helpful to maintain low filtration properties in the mud system to make the wellbore more tolerant of the overbalance.

16-9

Inadequate Hole Cleaning

Summary Points:

• Equipment - top drive, pumps, BHA selected for high percentage rotary drilling, large DP • Wellbore stability - monitor hole enlargement • Fluids Issues - maintain high low-end rheology, note inclination effects • Operations - maximize annular velocity (AV), backreaming, controlled ROP, cuttings

beds agitation benefits, monitor trends: torque/drag, cuttings type, shape, and load Planning for adequate hole cleaning involves the interaction of several drilling disciplines including the mud system, the directional trajectory, the BHA and drill string design, hole sizes and casing program, and rig equipment selection. Detailed hole cleaning recommendations are included in Section 11, “Hole Cleaning and Hydraulics”.

To prevent a stuck pipe occurrence as a result of inadequate hole cleaning, monitor torque and drag trends on a regular basis each day and compare to predicted values. If torque and drag indicate the hole is not being properly cleaned, several steps can be taken. The ones chosen will depend upon the current situation on the well and what can be done most cost-effectively. Consider:

• Increasing mud pump rate • Increasing drill string rotation/reciprocation (possible BHA change) • Increasing low-end rheology of mud • Pumping high-vis sweeps • Limiting ROP to reduce cuttings load • Running larger drill pipe for higher annular velocity (AV) and flow rate

The mud properties should be carefully maintained with low-end rheology within the prescribed range. If possible, increase the flow rate to raise AV and limit ROP until the problem is corrected. This will be especially helpful if there is evidence of hole enlargement, which reduces AV in the localized area.

Important tool selections for ERD operations include a rig with a top drive to allow efficient backreaming and large pumps and larger drill pipe to maximize AV. Use pipe rotation and reciprocation to agitate any cuttings beds which may have accumulated on the low side of the hole. This will include regular wiper trips with backreaming through these intervals. Hole cleaning may also be improved by optimizing BHA design to allow maximum drilling in rotary mode. Pumping various pills as indicated in Section 7 may also improve the situation. Monitor cuttings load at the surface as these pills are circulated around to evaluate the hole condition and any beneficial effect from the pills.

16-10

Wellbore Geometry / Keyseating

Geometry

Summary Points:

• Equipment - use tapered stabilizers • Wellbore stability - monitor hole ledging • Operations - control DLS, monitor trends:

torque/drag

Wellbore geometry problems occur when curvature in the wellbore interferes with the passage of the drill string or casing string. ERW trajectories typically utilize the lowest curvature which achieves the directional objectives. This helps to minimize side forces on the drill string and casing which will reduce torque and drag loads and allow longer reaches. However, unplanned curvatures, especially those located in areas where the string has a high tensile load, will increase the torque and drag above the planned values. Trajectory planning and directional BHA optimization are discussed in detail in Sections 7, “Tubular Design and Running Guidelines” and Section 8, “Cementing”, respectively.

Typically ERW curvatures are low enough that wellbore geometry problems seldom occur. However, if trajectory control requires multiple directional correction runs, the wellbore may have excess curvature, or tortuosity, which increases torque and drag. This is also discussed in Section 7, “Tubular Design and Running Guidelines”. Use backreaming trips to reduce torque and drag and smooth excess curvature in the wellbore.

Keyseating occurs when a drill string is rotated through a curved section of wellbore under high side loads. If the side loads are high enough and the formation is soft enough, the drill string will wear a groove into the wall of the hole. Monitor torque and drag in the open hole segments of the build section to evaluate whether keyseats may be forming.

SECTION A-A

DR

ILL

CO

LL

AR

A A

Keyseat

16-11

Ledges can also form, especially where hard and soft formations are interbedded. In curved wellbore sections and at high inclinations, side forces on the drill string and other mechanical and chemical interactions can cause irregular enlargements in the wellbore along bed boundaries. Again, monitor torque and drag in these sections and make wiper trips as required. Consider simplifying the BHA by omitting some stabilizers and using stabilizers with tapered edges on the top and bottom of the blades.

SANDSTONE

LIMESTONE

SALT

SHALE

SHALE

WELLBORE GEOMETRYLEDGING

LEDGING ATFORMATION CHANGES

16-12

Collapsed Casing

Casing

Bottom HoleAssembly

Drill Pipe

SqueezingSalt

SqueezingSalt

Summary Points:

• Equipment - DP protectors, DBS/WWT tools, hardbanding materials

• Operations - metal in cuttings, position/severity of doglegs, monitor trends: torque/drag

When casing is run through a curved wellbore section, the casing bends to conform to the wellbore. Rotating drill strings inside curved casing, especially with high tensile loads and high side loads, can accelerate casing wear. As the wall of the casing is worn away, the collapse capacity of the casing string is reduced. If the external forces on the casing are high enough, the casing will collapse. Casing wear and the chances of casing collapse can be reduced by reducing the side loads on the drill string and by minimizing the damage caused by the drill string under these loads. Refer to Section 7, “Tubular Design and Running Guidelines” for a discussion of casing wear mitigation and drill string hardbanding issues.

Casing wear can be reduced by lowering drill string side loads, particularly through the curved section of the hole. This is discussed in Section 9, “Drill String Design” and Section 7, “Tubular Design and Running Guidelines”. Another alternative is to support the side loads so that the drill string does not rotate against the casing. This can be accomplished with non-rotating components like the WWT and DBS tools. These tools are placed throughout the string to provide standoff for the string from the casing or open hole while allowing the string to rotate with lower torque.

The damage caused by the drill string under a given load can be reduced by selecting a hardbanding material for the tool joints which is not as damaging to the casing. This is discussed in Section 9, “Drill String Design” and Section 10 of the Casing Design manual.

Casing collapse is of particular concern when mobile formations are present. Monitor metal content in the cuttings and wear on the drill string as a gauge of casing wear. Consider running a casing caliper to monitor casing wall thickness if necessary.

16-13

Cement Blocks

CEMENT

Summary Points:

• Operations - minimize rathole below casing shoe, monitor trends: drag in the casing shoe

Blocks of hardened cement can fall into the open hole from the rathole below the casing shoe when they are mechanically disturbed. If the casing shoe is at high inclination, the tendency for this problem to occur is increased.

The primary way to reduce the risk of this problem is to minimize the length of rathole below the casing shoe. Monitor drag through the shoe on trips and consider a wiper run through the area if problems arise.

16-14

CONNECTIONS GUIDELINES

There is a history of sticking problems when making connections. These have occurred in 17-1/2 inch, 12-1/4-inch, and 8-1/2 inch hole sizes and have resulted in expensive side tracking operations.

These guidelines are being issued to remind everyone of good drilling practices which minimize potential problems during connections. These guidelines assume top drive drilling.

• All Drillers should be familiar with these connection procedures. • Wipe, at least, the last joint prior to making a connection. If erratic or high torque is

experienced prior to the connection, clean the hole. • At “Kelly Down” always allow the weight on bit (WOB) to drill off prior to picking up off

bottom, especially when drilling with high WOB. • Have a single in the “V”door in case downward motion is required to free the pipe after a

connection. • Avoid starting and stopping the mud pumps suddenly. This may disturb the wellbore

downhole (shock loading effect). Take a whole minute to bring the pumps up to speed. • Minimize the period without circulation during a connection. • After drilling or reaming, cuttings should be circulated above the BHA prior to picking up

to make a connection. • If differential sticking is suspected to be a risk; maximize pipe motion, consider rotation of

string with slips set while picking up the next stand. • Connections should only be made if hole condition is good. Never make a connection

with any overpull onto the slips. • Set slips high enough to allow downward movement. If hole conditions are sticky, extra

stick up may be required, taking care not to bend pipe. • Always confirm circulation after a connection prior to moving pipe. • Always begin pipe motion downwards once slips are pulled. • When using 6-5/8 inch drill pipe with the Varco TDS 3 top drive the pipe needs to be re-

torqued after the connection has been lowered from the back-up system to tong level. This operation should be treated as a connection and the above guidelines followed.

16-15

REAMING AND BACK-REAMING GUIDELINES

It is now accepted that reaming contributes to increased hole deterioration. In addition, reaming and back reaming account for over 60% of BPXC stuck pipe incidents. Reaming in the hole has the greatest risk of sticking associated with it due to the fact that the BHA continues run in hole (RIH) past "stirred up" cuttings beds and can therefore pack-off.

The preferred practice is to work the string past a tight spot as a first option. However, overpull limits must be known and used. Work up to the overpull limit in stages, ensuring free movement in the other direction at each stage.

Understanding the geology and hole condition is important. Different actions may be required in different formations (e.g. undergauge sand, ledges or sticking balling formations).

• Always plan the trip. Have an up-to-date mudlog on the rig floor, know where high doglegs exist and note troublesome areas from past trips.

• The new Mudlog tripping plot should be available on the rig floor. A good understanding of this plot will assist in safer and quicker trips.

• Ensure that the Driller knows what actions to take in the event of problems. Are overpull limits, freeing procedures and reaming practices understood? Are written instructions for the driller prepared and updated regularly?

• If reaming is required, control the speed of reaming operations. Large volumes of settled cuttings or new cave-ins can be introduced to the hole while reaming. It is critical that this material is circulated out (4 stands an hour can be used as a rule of the maximum speed).

• Reaming operations should be conducted as smoothly as possible. Rotation speed should be dictated by torque and kept as low as possible.

• Prior to heavy reaming, slow rotation (<80 rpm) should be attempted to "walk" the pipe through ledges.

• Reaming weight and speed should be kept low (< 10 - 15 Klb) either up or down. This reduces the chance of sidetracking the well and is less damaging to the drill string.

• Soft Torque must not be used while reaming as it may disguise torque trends. • When the top drive stalls out during reaming operations, there is a great deal of stored

energy in the torqued up drill string. Always release this torque slowly. • If consistent parameters can be used for reaming operations, this assists in identification

of changes in torque and pressure trends. • Increase in drag, torque, or pressure may indicate that the annulus is loaded up and a

pack-off may be forming. Take time to clear up the hole. Know and follow the freeing procedure for pack-off should packing-off occur.

• The shakers must be monitored continuously, and the volume of solids being removed from the wellbore should be recorded. Reaming speed and circulation time should be adjusted if volume rate dictates.

• Drill floor personnel should get into the habit of calling the Mud loggers before making connections to check that everything is OK.

16-16

• When back-reaming do not overpull the pipe up in the slips to connect the top drive. • Reaming operations should be conducted with the same flowrate as drilling. • When washing in with a motor in the BHA, rotate the whole drill string at low rpm. • When reaming or back-reaming always make sure the hole is clean and the pipe free

prior to setting slips. • Avoid complacency when running through long open hole sections or intervals prone to

generate high cavings volumes. Do not assume that resistance is always at the bit. Stabilizers and drillcollar contact may be indicative of a build up of loose material in the hole and a potential pack-off situation.

• Coal has been the cause of several stuck pipe incidents. Know were coal seems to exist and be prepared to ream them on first few passes.

• There was some discussion as to whether reaming and back-reaming should be classed as NPT, as the operation may be necessary and improves well condition. However, the DEAP database automatically classifies all reaming operations as NPT.

• Freeing procedures are the results of analysis of hundreds of stuck pipe incidents. They should be the first steps taken in a stuck pipe incident by the Driller to avoid actions that may worsen the situation. If no progress is made, and the situation and stuck pipe mechanism are understood, other steps may be taken (under the guidance of the BP Supervisor) that are not specified in the freeing procedures.

• Recommended rotary speed and WOB while reaming. Comments were received to say that slow rotary should be used to "walk" the bit off of ledges. However, in tight sands higher rotary (160 rpm) was preferred as this "stiffened" the BHA and prevented the bit / NBS jamming geometrically in gauge sands. WOB was also not thought to be as important as keeping the bit moving to avoid "sidetracking" the well.

• If the annulus continues to flow when the pumps are shut down and pump pressure takes a long time to fall off, this is a good indication of a loaded annulus and possible imminent pack-off. Take time to clean the well bore. This has been more of a problem when 6-5/8 inch drill pipe and 9-1/2 inch drill collars have been used in 12-1/4 inch hole.

16-17

FREEING STUCK PIPE

General Recommendations:

• Attempt first movement in opposite direction from when pipe became stuck • Begin jarring immediately • Work pipe to safe limits • For differential sticking and inadequate hole cleaning (packoff) initial movement should

be down with torque • For differential sticking, work pipe to maximum immediately • For packoff, work gradually up to maximum • Achieve and maintain circulation

For ERW applications, differential sticking and hole packoff or bridging as a result of inadequate hole cleaning are the most prevalent stuck pipe mechanisms. For differential sticking, be prepared to pump spotting fluid as early in the episode as possible. For hole packoff, make top priority achieving and maintaining circulation.

When to give up attempts to free pipe - If early freeing attempts fail, the decision has to be made whether to back off or not. There are likely to be four options:

• Continue attempts to free the pipe. • Back off above the free point and run in with a fishing assembly. • Back off above the free point, plug and side-track. • Back off above the free point prior to abandoning the well.

Retrievable sources should be used in LWD tools due to the difficulty in fishing BHA’s in extended reach and horizontal hole sections. This will allow the well to be quickly plugged and side-tracked around the fish should that option be chosen.

Fishing - Due to torque and drag in an ERW, accurate string control for freepoint, backoff, and fishing tool engagement may prove difficult. In fact, at very high inclinations, the wireline tools will not slide to bottom and may need to be pumped down. If a backoff is achieved, the overshot guide may require modification to engage the pipe laying on the low side of the hole.

16-18

STUCK PIPE ISSUES

OFF

WORK STRINGUP & DOWN

TO ESTABLISHCIRCULATION

UNCONSOLIDATEDFORMATIONS

HOLE PACKED

FORMATION RELATEDSTUCK PIPE CAUSE

FACTURED/FAULTED

FORMATIONS

- IF LIMESTONEPUMP ACID

-WORK STRINGUP & DOWN

REACTIVEFORMATIONSFORMATIONS

GEOPRESSURED


-INCREASEHYDROSTATIC

HEAD

FORMATIONSMOBILE

SALT PLASTIC CLAYS

STRINGJAMMED

WATER

-WORK STRING


HEAD

-PUMP FRESH

UP & DOWN

- WORK STRINGUP & DOWN

TO ESTABLISHCIRCULATION


HEAD

OFFHOLE PACKED STRING

JAMMED OFFHOLE PACKED

OFFHOLE PACKED



HEAD

CLEANING

STUCK PIPE CAUSE

MECHANICALDIFFERENTIAL

STICKING

WELLBORE JUNKPOOR HOLEKEYSEATING

U/GAUGEHOLE GEOMETRY

CEMENTRELATED

GREENCEMENT

CEMENTBLOCKS

COLLASPEDCASING

STRINGJAMMED

HOLEPACKED OFF

-WORK STRING

DOWN &ROTATE

WORKSTRING

WORKSTRING

UP

UP IF RIH

-WORK STRINGDOWN IF

-WORK STRINGDOWN TO

IMPROVECIRCULATION

WORKSTRINGDOWN &

UP

- WORKSTRING UP

- PUMPACID IF

AVAILABLE

- WORKSTRING UP& DOWN- PUMPACID IF

AVAILABLE

WORKSTRINGDOWN

-SLUMPSTRING &ROTATE

REDUCEHYDROSTATIC

HEAD

- SPOTRELEASING

AGENTS

STRINGJAMMED

STRINGJAMMED

STRINGJAMMED

STRINGJAMMED

STRINGJAMMED

STRINGJAMMED

POOH

ESTABLISH/

STRINGJAMMED

16-19

CONTACTS

Stuck Pipe Network Name Location Telephone Fax

Colin Bowes XTP Sunbury 44 (0)1932 763831 44 (0)1932 764183

Ian Pitkethly XTP Sunbury 44 (0)1932 762049 44 (0)1932 764183

REFERENCES

1. British Petroleum, “Stuck Pipe Prevention Course Workbook” and training course

2. British Petroleum, “Stuck Pipe Handbook”

3. British Petroleum “Stuck Pipe Refresher Training - Rig Site modules”

4. British Petroleum “Hole Cleaning - A Team Approach” video

5. British Petroleum Differential Sticking Guidelines

6. British Petroleum Hardbanding Specifications

7. Amoco TRUE Training

8. T H Hill Associates, Inc., Drill String Failure Prevention course book

16-20

Section 17 Emerging Technologies

In this Section...

• Drill Strings - High-Strength 165 ksi Drill pipe - Purpose-Built ERD Drill Pipe - Composite Drill Pipe - Titanium Drill Pipe - Thread Inspection - Lubricant Embedded Hardfacing

• Directional Drilling Systems - Rotary Steerable Drilling Systems - Inclination Control - Rotary Fully Steerable Systems - Inclination and Azimuth Control - Summary

• Other Special Equipment - Sonic LWD Tools - Magnetic Interference Correction Software - MWD Gyro System - Inteq / Mitsubishi Drilling Mechanics Sub - Security/DBS Flexible Bit - Liner Thruster Tool - Wireline and Coil-Tubing Tractors - Enhanced Performance (Lo-Torque) Drill Pipe

• References

17-1

DRILL STRINGS

High-Strength 165 ksi Drill Pipe

High-strength drill pipe (DP), grades above 135 ksi and up to 165 ksi, allows increased load capacities and improved dimensional efficiencies for ERD wells. Compared with conventional grade tool joints with 120 ksi yield, a 165 ksi tool joint offers a 38% increase in tool joint torque and tension capacities. These increases have been previously sought and 165 ksi DP has developed a mixed reputation to date. Because of strict metallurgical requirements of these grades and the need for careful field usage, failures with 165 ksi DP have occurred and practical application of these grades has been limited. However, recent metallurgical advances have been made which will make high-strength grades more reliable. Twelve joints of 165 ksi DP with 150 ksi tool joints were successfully field trialed by Wytch Farm in three of the most recent ERD wells. These test joints have not shown any cracking or structural problems to date, although a few of the joints suffered unusually heavy tool joint wear, which is still under investigation.

Purpose-Built ERD Drill Pipe

Rather than applying high-strength metallurgies to standard sizes, custom ERD drill strings should be considered. Since application of 165 ksi material to standard DP and tool joint sizes can result in higher capacities than surface rotary equipment, the drill string design should actually be optimized with new weights and dimensions. The 165 ksi DP tube should be designed to provide specific torsional and tensile strengths with a maximized ID for a given OD, i.e. 5 inch, 5-1/2 inch, or 6-5/8 inch. Simultaneously, the tool joint should be optimized with a suitable material strength. For example, 150 ksi tool joints may provide the strength necessary for a specific application while providing higher ductility and toughness than 165 ksi. The optimal tool joint should be pursued with double or multiple torque-shoulders. Stress balancing, and/or high friction thread compounds can also be applied. Using such approaches, 165 ksi DP can be manufactured with weights at least 15-30% less than conventional DP with 10-25% less hydraulic pressure loss. These more efficient hydraulics impact ERD hole cleaning, while the weight savings impact torque and drag. Both considerations significantly extend current capabilities.

Composite Drill Pipe

Composite DP has been manufactured and used in the drilling of short radius horizontals. The composite DP was manufactured by a division of Brunswick which is now a separate business known as Lincoln Composites. The wells were drilled by Amoco in West Texas. The composite DP used went through several design iterations to improve the bond between the composite pipe and the steel tool joint. Despite that work, that bond remains a weak link in the product and further research and testing is suggested. Composite DP costs have also been estimated as very high and long-term wear characteristics of the composite body have yet to be established. Despite these potential limitations, composite DP has and is being successfully used to drill short radius laterals. It may become useful for ERD as well if these strength issues can be addressed.

17-2

Titanium Drill Pipe

Titanium has a density approximately 40% less than steel, and yield strengths as high as 170 ksi, 26% higher than S-135. As a result, titanium DP has the potential to double reach capabilities achievable with steel drill pipe. Titanium DP has been manufactured by RMI as part of a DEA research project. That project demonstrated the capability for the product to be manufactured (i.e. friction-welding of a titanium tool joint onto a titanium tube) and provided some make/break testing of the product. Further testing of the product is required for tension, torque, fatigue, wear, etc. Several areas of concern remain with titanium DP. One area is buckling and twist. Because titanium's elastic modulus is lower than that of steel, it is more prone to buckling under axial compression and results in a higher twist (rounds) for a given amount of torque. The implications are dependent on the specific drilling conditions, but there are significant differences in the elastic stability and rigidity of titanium vs. steel. Wear is also a concern for titanium. A joint-industry project to assess the wear of titanium in downhole environments tested titanium pup joints against 9-5/8 inch 53.5 P-110 casing. The most wear-resistant type of titanium showed wear rates 7 times greater than those for steel. Thus, work is required on developing surface treatments to enhance titanium wear resistance, or to protect it through the use of DP protectors or wear pads. Finally, titanium cost remains a concern. Cost indicators show titanium may cost 8-10 times a comparable steel product. Thus, economic justification of titanium DP for ERD will require significant cost savings over other development options.

Thread Inspection

Technical Software Consultants (TSC) has developed an entirely new concept for thread inspection aimed at overcoming the practical difficulties of applying conventional non-destructive testing (NDT) to threads. The main objective being to improve the reliability of thread inspection and to reduce the likelihood of downhole failures from thread cracking. The system is called A.T.I. (ACFM Thread Inspection).

The system can be configured to suit virtually any thread form and hence is suitable for use on other downhole threaded components such as mud motors.

The new ACFM thread inspection technology is advertised as providing rapid, reliable and auditable thread inspection and provide significant cost benefits over existing inspection techniques.

17-3

Lubricant Embedded Hardfacing

DEA Project 86 is being conducted by Sprayforming Developments Ltd. (SDL) of Swansea, UK for the development of self-lubricating hardfacings. The technology involves the application of current hardfacings (i.e. Arnco-200XT or Armacor-M) using electric arc-spray guns, with graphite simultaneously injected using a proprietary powder injection technique. Results from small scale tests on wear and friction of the resulting hardfacing were encouraging. Friction was as much as 75% lower and casing wear rates 50% lower than with current chromium-based hardfacings, specifically Arnco 200XT. These results are shown in the following plot:

0.5

0.4

0.3

0.2

0.1

00 5 10 15 20

fric

tion

coef

ficie

nt

time (hours)

200XT weldmaterial

arc sprayedsteel/graphite

Figure 17-1. Plot from DEA Phase 1 Test

Further work is needed to assess commercial viability. A Phase II for the project is being pursued, focused on applying the graphite-containing hardfacings to full size tool joints which will be tested by Maurer Engineering. Maurer owns the Drilco casing wear test machine which has been used to establish baseline wear performance of various materials through the DEA-44 project. These tests should give a better comparison of the new materials to existing hardfacings. Further work will be required to assess costs for full-scale implementation. The applications discussed above have been conducted in enclosed chambers with nitrogen or argon as the atomizing gas. New equipment and techniques will be required to implement these application methods by current hardfacing suppliers.

17-4

DIRECTIONAL DRILLING SYSTEMS

Rotary Steerable Drilling Systems - Inclination Control

Oriented drilling becomes more difficult as departures increase and well trajectories become more severe. Procedures that assist sliding in such difficult conditions include:

• Pipe reciprocation and rotation in conjunction with high flow rates to clean the hole prior to a sliding attempt

• Tripping out of the hole to pickup stands of drillcollars for the near-vertical section of the well

• The application of weight on bit (WOB) through hydraulic tools such as "thrusters" • The application of traveling equipment weight to the drill string

Such measures are expensive however, particularly when the much reduced rate of penetration (ROP) associated with oriented drilling is accounted for. As a result, systems that allow reduction in oriented drilling requirements are of pivotal importance to ERD operations. Recent advances in systems to reduce or eliminate oriented drilling are described in the following sections.

Halliburton Highly-Variable Gage Stabilizer (HVGS)

Variable gauge stabilizers (VGS) have provided partial success in increasing rotary mode drilling by allowing some control over build/drop rates. Unfortunately, VGS systems have had significant limitations. These include limited diameter ranges of 1/2 inch to 3/4 inch and usually only 2 settings, i.e. blades fully expanded or collapsed. Some recent VGS designs allow 3 size settings. This limited size variation limits the VGS' ability to account for changing formation behaviors during long bit/BHA runs. This is true for rotary bottom hole assemblies (BHAs) and even more so for BHAs using positive displacement mud motors (PDMs) since the VGS is run above the PDM and is farther from the bit. In addition, these VGS were set by WOB application that is difficult in severe ERD wells and can lead to bit balling or stuck pipe. If the VGS was being used with a PDM and flow was continued while setting the VGS, the PDM could stall which will lead to a shortened PDM run life. Once set, the VGS imposes a pressure drop as its signal to confirm position. This pressure drop is undesirable in ERD hydraulics.

These limitations were recognized and addressed by the development of a new generation highly variable gauge stabilizer (HVGS). This new HVGS provides a larger diameter range and does not restrict drilling parameters for setting or confirmation requirements. The 8-1/2 inch HVGS provides size variations between 7-1/4 inch and 8-1/2 inch. A variable number of size settings can be run within this range, but 1/4 inch size variations are usually provided, meaning six (6) size settings can be used to adjust the build, hold or drop BHA tendencies. The HVGS is set using flow rate signals from the surface. The HVGS has an internal flow switch that times the flow rates to determine which setting is desired. Once the size command is given, the HVGS uses internal hydraulic valves and mechanical stops to establish the size to which the adjustable blades will expand. The blade expansion is achieved by the pressure drop through the bit and (if used) the PDM. The HVGS is full strength and full bore, and imposes no pressure drop on the drilling hydraulics. The HVGS uses its own mud pulse signal to communicate the size setting to surface. HVGS systems are available that operate in an integrated fashion with a measurement while drilling (MWD) tool and as stand-alone systems that are independent of other MWD/LWD systems.

17-5

Pulser

Microprocessor

Battery

Control System

Positioning Piston

Flow Tube

Return Spring

Follower

Blade

Push Rod

Piston

Figure 17-2. HVGS Construction

HVGS systems have been successfully applied at Wytch Farm to maximize departure while providing effective and efficient means of controlling inclination. The capability to "tune" a BHA's directional tendency to the formation being drilled is important, particularly when drilling at near horizontal inclinations in layered, dipping reservoirs. Because of the inefficiencies of oriented drilling in ERD wells, drilling systems should be pursued that allow the minimization or elimination of oriented drilling requirements. Inefficiencies aside, HVGS systems that allow rotary drilling and adjustable inclination control will allow farther absolute departures to be achieved, since they eliminate the limitations imposed by steering. Other benefits include minimizing wellbore tortuosity and maximizing hole cleaning through sustained drill string rotation. A diagram of the HVGS system is shown:

17-6

Rotary Fully Steerable Systems - Inclination and Azimuth Control

The HVGS system is a substantial advancement of directional drilling technology for ERD and is being used in a number of operations. However, the HVGS is still a reactive BHA system. In other words, directional BHA tendencies are identified and if they are not what is desired, the HVGS size is changed and drilling is resumed to determine what the tendency will be with the new configuration. More advanced than such a "reactive" system are "active" directional control systems. These systems use directional monitoring to automatically adjust the directional behavior of the BHA to achieve the desired objectives. Efforts to develop this new technology include: Cambridge Radiation Technologies

Cambridge Radiation Technologies’ rotary steerable system was developed under joint-industry funding. Known as the Automated Guidance System (AGS), the first tool was built for 12-1/4 inch hole and involves a rotating drive shaft enclosed in a non-rotating housing. The non-rotating housing remains in contact with the wellbore via centralizer-type blades. Hydraulic bladders between the outer housing and inner mandrel are inflated to deflect the mandrel up/down or left/right at the bit face, thus allowing both inclination and azimuthal steering. The basic concepts of the AGS are illustrated in the following figure:

DRILL BIT

TAPER

CONNECTOR

DRILL PIPE

CONNECTOR

MBS

ADAPTER

VALVE BLOCK

RING

HYDRO

SEAL

ANGULATION

JOINT

ACTUATOR BLOCK

ANTI-ROTATION DEVICE AND

MAIN PRESSURE COMPUCATOR

ANGULATION

JOINT

HYDRO

SEAL

TAPER

CONNECTOR

DRILL PIPE

CONNECTOR

SECOND

STABILIZER

DRILL COLLAR

ADAPTER

RING

UNDEFLECTED

DEFLECTED

DRILLINGDIRECTION

LATERALFORCE LATERAL

REACTION

LATERALREACTION

Figure 17-3. AGS Diagram In September of 1995, Cambridge Drilling Automation Ltd. carried out an endurance/performance test with the 12-1/4 inch version of the AGS. The AGS kicked off vertically and automatically built inclination at a rate of 1.6o/98 ft. (30m) until its pre-programmed course of 18o Inclination/45o Magnetic was achieved. The system then drilled a tangent section of 328 ft. (100m) in length adhering to this pre-programmed length.

17-7

Following re-programming to 18o Inclination/65o Magnetic, the AGS automatically changed direction until the re-programmed course was achieved. The system then drilled a 269 ft. (82m) tangent section at this course, to total depth (TD). The courses achieved were very accurate, with the readings from the single shot surveys taken in the tangent sections showing the courses realized to be almost identical to those programmed.

The section drilled with the AGS was 2087 ft. (636m) in length. The number of circulating hours was 143 and the number of hours rotating on bottom was 125. There was no detectable loss of oil from the AGS during the test, there was no minimal wear of the System’s Anti-Rotation Device Blades, and no detectable degradation of any mechanical feature.

A roller cone insert bit and a PDC bit were used alternatively during the test. Although not quantified, vibrational levels with the insert bit were, at times, high. The formation drilled was pebble beds, limestone, and upper/middle/lower coal measures. Weight on bit was generally 20,000 lbs and rpm generally 100.

The first full test of the tool was conducted in February 1992 at the Drilling and Production Training Center in Montrose, Scotland. Various problems were encountered in early tests, but were remedied so that the tool operated for a total of 37 drilling hours, drilling a total of 689 ft. (210m). A second test of the tool in November 1992 was abandoned due to hole problems and stuck pipe. The AGS sustained jarring loads during this operation which resulted in failed battery modules. The first field test of the tool were conducted with Shell/SIPM. These tests were apparently not successful but details are not available. A second field test was attempted by Amoco offshore UK. However, the tool did not “activate” downhole. A critical vibration level is needed to activate the system, (i.e. indicate that drilling has initiated), and this was not reached. As a result, the tool was immediately pulled from the hole. Threads were unfortunately galled upon breakout at surface, which prevented further tests on the subject well.

A field test was conducted by BP on Miller Well 16/8b-A14 in April 1994. The AGS was RIH to 13,370 ft. (4,075m) including reaming through a problem interval from 10,836 ft. -11,668 ft. (3303m - 3556m). A total of 745 ft. (227m) was drilled to 14,115 ft. (4,302m). The tool was run with instructions to steer the well to 13.8° inclination and 285.7° azimuth using maximum doglegs of 1.5°-2° . During the run, the well was turned from c. 271° azimuth to c. 284° azimuth. However, the assembly displayed an undesired dropping trend as high as 1.8°/100’ and the well lost inclination from 14.1° to 5.7° . Various theories, such as dynamics, were initially offered as an explanation for the tool’s inability to control inclination. Data from the well did indicate that shocks as high as 60g’s were incurred during reaming while RIH. However, the explanation for the failure was ultimately placed on temperature limitations. Three of the four battery packs failed, reportedly due to temperature (BHCT was 135°C or 275° F), and hence a field test was sought with a lower temperature regime.

A field trial was conducted by Statoil. In that application, it is reported that the tool failed to steer the well as desired. That failure was due to rotation of the non-rotating portion of the housing, which was in turn put down to the “excessive lubricity” of the Baroid Petrofree mud system. Although various lessons have been learned in each of these field trials, failures have occurred in each case. Due to the complexity of the involved technology and the need for substantial technical resources for successful development, CRT may need to consider an alliance or technology sale to a major service company to ultimately secure a commercial system.

17-8

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Figure 17-4.

Hycalog / Camco Rotary Steerable Drilling System

A different approach to rotary steerable systems has been taken which uses "modulated bias" to steer the BHA. Modulated bias refers to the modification of stabilizer blade dimensions and contact pressures in a synchronous fashion as the particular blades pass up/down or left/right of the bit. By applying hydraulic pressure every time the rotating blades pass a specific orientation in the wellbore, this modulated near-bit stabilization forces drilling away from that location. In this way, the BHA can achieve both inclination and azimuthal steering. The system uses a non-rotating control mounted inside the main tool housing that includes pressure-activated stabilizer blades or "paddles". The system was tested in the lab and surface tested on a rig in 1993. In 1994, the full-scale system was used to drill about 640m of hole in about 20 different run modes, i.e. build, build/turn, neutral, etc. The field tests demonstrated the ability of modulated bias to impact BHA steering. Overall, the well trajectory was built from near-vertical to 55° inclination and turned from 65° azimuth to 310°. On the basis of these successful concept and prototype tests, continued development of the tool is being pursued. The development testing of the tool is continuing with further test runs to be conducted in Montrose, Scotland, and if successful, runs in commercial wells could begin as soon as Q1-96.

17-9

Non MagneticFlex Sub

DirectionalSensor

Formation EvaluationSensors and Resistivity

Gamma-Ray

DownholeElectronics

Flex Joint

Mud Pulse Valve

Alternator andOil Pump

Near Bit Sensor

ExpandableStabilizer7 7/8" x 9 7/16"

Bit

10900

2650

600

Figure 17-5. RCLS Diagram

Inteq’s Rotary Closed-Loop System (RCLS)

Another approach has been taken by Inteq which uses non-rotating near-bit stabilization to achieve rotary steering. The system is known as the Rotary Closed-Loop System (RCLS). Inteq and Agip, who partially funded the tool's development, have been working with Wytch Farm to test the system. On Well M5, two attempts were made to pickup and function the tools and on both occasions the tools failed to successfully communicate with the surface control system. Thus as yet, the Inteq RCLS tools have yet to even be run to bottom and used.

The basis for the RCLS is a non-rotating near bit stabilizer sleeve with three (3) independently actuated blades. Based on the desired directional behavior (build/drop and/or turn) the blades are powered to give a specific force vector to achieve the outcome. The tool includes a near-bit inclination sensor and accelerometers which provide dynamic monitoring up to 50g’s. A full MWD/LWD package with inclination, azimuth, gamma ray, and resistivity is included. The tool is approximately 36 feet (11 meters) and can be run with or without a PDM. Inteq’s initial preference for field trials is for it to be run in simple

rotary mode without a PDM. The system can operate in either a surface-control mode or an automated drill-ahead mode. In the surface-control mode, an operator defines the desired force vector for the blades. Based on the blades' then current orientation, they are independently hydraulically actuated to achieve the force. In the automated drill-ahead mode, the tool maintains itself within a 0.1°tolerance of a set inclination and will adjust the blade pressures automatically to achieve this. Azimuthal changes are not considered in this drill-ahead mode. Inteq has previously engineered other sophisticated drilling systems such as the Thruster for SIPM and the Vertical Drilling System for the German KTB project. Although the brief tests of the RCLS tools at Wytch Farm have been disappointing to date, it is likely that Inteq will persevere to ensure the tools are commercially successful as rapidly as possible. A diagram of the RCLS is shown in Figure 17-5.

17-10

Remote Controlled Downhole System (RCDOS)

Developed by the Japanese National Oil Corporation (JNOC), RCDOS is a directional drilling system which can freely control the bit axis of the downhole tool (both bend angle and tool face) from the surface by a two way telecommunication system. EM and Sonic thru DP are currently used for the remote control. The system can dynamically and steadily steer the bit towards the course while drilling is in progress with WOB.

The current motor steerable RCDOS allows the change of both bend angle and tool face by remote control from the surface, thus reducing the number of trips out of hole for changing BHA and saving the rig time. The build up rate and bend angles are:

• Build up Rate: 15deg/100 ft @ bend angle of 2.0 deg.

• Bend Angles: 0.0, 0.5, 1.0, 1.6, 2.0 (5 steps)

Currently EM is the communication used from surface to downhole, and Sonic from downhole to surface. Application of Sonic in two way and Mud Pulse is under research.

The system allows steering without the usage of rotary table nor stoppage of drilling operations, thus saving the rig time and smoothing the control of tool face orientation, especially in deep wells and severe downhole conditions. It also allows dynamic steering while drilling is in progress with WOB and creates best control of tool face orientation, thus providing the fine tuning of the course and a smooth gauged hole, minimizing hole tortuosity and permitting an increase in the distance and ROP.

Future Rotary Steerable RCDOS (Steering While Rotation) will improve the operational dynamics and reduce the torque and drag, thus creating a smooth hole and permitting an increase in the distance and ROP. You will be able to achieve hole cleaning more efficiently, thus reducing the likelihood of pipe sticking and mitigating formation damage. You will also be able to minimize stick slip problems causing motor stall and loss of tool face orientation, thus saving the rig time.

Future Downsized RCDOS will expand the areas where RCDOS can provide services, i.e. reentry wells, slimholes and coiled tubing operations. It will provide the steerable coiled tubing drilling system. RCDOS does not require a wireline tool nor a hydraulic line inside the tubing. RCDOS works in underbalanced operations. Smooth holes help coiled tubing work better.

17-11

Table 17-1 Milestones of RCDOS Development

Year Topics

1989*

• Survey and basic research on directional drilling system.

1990 • Research on basic design on bending mechanism.

• Basic study on tele-communication commenced.

1991 • Part of bent housing was manufactured for trial.

• Basic study on tele-communication was continued.

1992 • Models of bent housing were manufactured for trial.

• Basic design of two way communication system was made.

1993 • Bent housing and communication system were manufactured (not total system yet).

• Signal transmission in two way were field-tested.

1994 • Bent housing and communication system were manufactured (not total system yet).

• Bent housing and communication system were field-tested respectively.

*Fiscal Year; April 1989 thru March 1990

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RCDOSSYSTEM COMPONENTS

Similar to the current directional drilling system

SURFACE CONTROL UNIT:--Portable Cabin (2ton W)-EM Transmitter & Sonic Receiver

MWD TRANSMITTER (10m L):--Sensor Subs (Directional, WOB, Torque)-EM Receiver & Sonic Transmitter

MOTOR & BENT HOUSING(10m L)

17-12

Figure 17-6.

Summary

While none of the fully rotary steerable systems are commercial technology at this time, focused development of distinct systems should lead to one or more viable commercial systems in the near future. At this time, use of the Halliburton HVGS in conjunction with either a conventional or instrumented geosteering PDM provides the most advanced directional drilling system, for ERD and horizontals.

17-13

OTHER SPECIAL EQUIPMENT

Sonic LWD Tools

Sonic logging while drilling (LWD) tools are now available from Halliburton and Schlumberger. Sonic LWD can be used for seismic corrections to avoid poor seismic resolution or wrongly assumed formation acoustic properties causing the planned wellpath not to be in the optimum position. Using Sonic LWD allows identification of formation boundaries and acoustic properties in the overburden, for correction of formation thickness, and for correlation to the seismic profiles. This will allow the direction of the well to the target to be fine-tuned while drilling, thus saving correction runs or possibly even sidetracks if not hitting the reservoir in the planned location. Sonic LWD can also be used for detection of sub-normal formation pressures in the overburden, thus reducing the risk of getting stuck due to pack-off, and to optimize ROP by being able to fine-tune mud weight. Using Sonic LWD provides real-time data while drilling which can be of great importance due to being able to correct the well trajectory if the formation properties are not as expected. Using wireline logging tools on DP can be difficult and time-consuming. Halliburton's Sonic LWD are available for 12-1/4 inch, 8-1/2 inch and under development for 6 inch holes. Anadrill's Sonic LWD are available for 12-1/4 inch holes.

Magnetic Interference Correction Software

Conventional MWD directional surveys are increasingly affected by magnetic anomalies and interference as the inclination increases and the direction approaches East-West directions. Halliburton's MAC2 program is the only Magnetic Azimuth Correction program that is able to perform cross-axial corrections of the Azimuth reading to compensate for these phenomena. Using Halliburton's MAC2 can significantly reduce, or even eliminate, the need to stop drilling for intermediate gyros. Using MAC2 can therefore reduce rig-time as well as avoid the risk of getting stuck or lose hole during intermediate gyros. MAC2 is run with conventional MWD and does not consume any rig-time or add any additional risks. The quality of the MAC2 results may even eliminate the need to run any additional survey instruments in the well, thus saving significant cost while maintaining complete directional control.

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MWD Gyro System

Delco, a division of Hughes Electronics, has delivered electronics and navigation sensors to the aviation and space industries for many years. Delco is now developing a Hemispherical Resonator Gyro (HRG) for oilfield applications. Delco is now seeking funding and a development partner among the MWD companies. The time-frame for having a prototype for field use is Q2-96 with a commercial service as early as Q2-97. The Delco HRG uses a capacitive electrostatic charge between metallized surfaces of quartz components to sustain the standing wave and to sense its position. The HRG is a high reliability, high performance solid state gyro. The design for oilfield applications will be of small diameter, i.e. 30mm sensors in a 1.5 inch package. The design temperature is currently 347oF (175oC). Use of the HRG with an MWD may give the following advantages:

• Gyro surveying by conventional MWD procedures • Gyro surveying while drilling (rotating) • Inertial surveying while tripping

The accuracy potential of the system as reflected in the current design specifications is 1' per 1,000' in gyro mode and 1' per 10,000' in inertial mode.

Inteq / Mitsubishi Drilling Mechanics Sub

As part of a joint research and development agreement with Elf Aquitaine, Inteq has developed a sophisticated drilling dynamics sub with Mitsubishi (electrical) and Sumitomo (structural). The sub includes multiple accelerometers and strain gages to measure loads (WOB, TOB, bending) and dynamics in real-time. Unlike current MWD tools which provide relatively crude measurements of dynamic accelerations, the Inteq sub has advanced DSPs (digital signal processors) which allow high-frequency dynamics data to be acquired and analyzed using FFT's (Fast Fourier Transforms) in real-time downhole. FFT's convert time-domain data into frequency-domain data so that resonant peaks and frequencies can be identified. The sub will also be programmed with diagnostic logic so that the raw data and processed FFTs can be analyzed downhole and the dynamic problem diagnosed (i.e. bit whirl, stick/slip, BHA whirl, bit bounce, etc.). The sub will communicate only summary information such as dominant peak and type of dynamic problem to surface (via code). The approach is designed to provide very advanced data collection and analysis where it is needed, i.e. at the bit, while still accounting for the limited data rates afforded by mud-pulse technology. The sub has been field tested by Agip and results were encouraging. Inteq is currently looking for operators who are interested in partnering this technology.

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Security/DBS Flexible Bit

Security/DBS, in conjunction with BP, has developed a flexible bit connection which effectively decouples bit tilt from the BHA. By decoupling the bit and the BHA, the adverse effects of bit bounce, bit whirl and BHA whirl can be reduced. The entire face of the bit stays more directly engaged with the rock face increasing penetration rates and reducing impact damage to the bit. Roller cone bits can be expected to achieve longer bearing and cutting structure life, as well as improved gage retention. Fixed cutter bits will also benefit from a reduced likelihood for whirl and from reduced impact damage. The sub is deployed directly above the bit and acts as a mechanism to decouple the axial tilt of BHA from the bit. The connection consists of various components designed to allow the bit to maintain complete engagement with the formation face even if the BHA above the bit is tilted. The connection is created by mating an upper and lower housing. The upper housing includes an API pin connection in the uphole direction and a contoured, splined drive shaft at the lower end. When assembled, the mated splines of the drive shaft and lower housing socket allow for direct application of torque. The splines are designed to provide direct transfer of torque while allowing for tilt or flex between the axes of the upper and lower housings. Elastomers, acting in conjunction with the lower ball end of the drive shaft and the landing seat of the lower housing, cushion the flexing action. The design is currently being reviewed following a connection failure while undergoing a field trial in Poland.

Liner Thruster Tool

The basis of the liner thruster tool is a telescopic joint or thruster unit located between the drill string and the liner running tool. By leveraging against the drill string weight and the drag between the drill string and the wellbore, DP pressure is applied to the cross-sectional area of the telescopic joint allowing one joint of liner to be pushed down. The pressure is then bled off and the drill string weight is slacked off and lowered one stroke length into the telescopic joint before it is repressured. The drill string and the liner are moved separately step by step to TD. To allow circulation, a valve is located in the telescopic joint. The circulation valve opens and allows for circulation when the telescopic joint is completely extended. The valve is closed when the telescopic joint is retracted. This solution allows for standard cementing procedures. A drill pipe pressure of 345 bar (5,070 psi) produces a force on the order of 100 tons (200 kips) at the top of a 9-5/8 inch liner. This force can be critical in overcoming friction in the well. The tool could have crucial impact while running liners and/or sand screens in horizontal and ERD wells. The potential for cost saving while running liners and/or sand screens is significant. The time-consuming use of drillcollars, which often requires picking them up from the pipe deck and running with safety clamps, pickup subs, etc., can be reduced or eliminated. Use of DCs can also introduce problems with cement wiper plugs due to their ID restrictions.

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Wireline and Coil-Tubing Tractors

Statoil has ongoing development work aimed at ensuring well intervention capabilities sustain pace with the rapid development of ERD drilling capabilities. These efforts include the qualification of lubricants, the development of pump-assisted coil-tubing (PACT), and the development of composite CT, a CT tractor, and a wireline tractor. Both the CT and wireline tractors have been developed by a Danish company, Welltec Aps, Kobenhaven. Prototypes exist for both tractors and initial focus has been on qualification of the wireline tractor. The wireline tractor has been tested in a 7 inch test loop at Rogaland Research in Stavanger during summer 1995. Pulling performance was about 600 lbs and temperature, pressure and endurance testing went well. Further testing was performed offshore on Statfjord where a minor leak developed in a sealing system. Offshore retesting is planned for early October 1995. The wireline tractor is utilizing electric energy from the cable. Using a standard 7/32 inch cable, the ERD reach may be 6,000-9,000m.

The CT tractor is powered by a turbine. The turbine uses the hydraulic energy when pumping through the CT. Pulling performance of the CT tractor may be as high as 6,000 lbs. This tractor had conduits through it enabling hydraulic and electrical through-put (e.g. for fluid circulation and/or for completion tools, perforating guns, etc.). Testing of the CT tractor is scheduled for November 1995.

Enhanced Performance (Lo Torque) Drill Pipe

A new product, known as "Enhanced-Performance Drill Pipe" (EPDP) has been developed for ERD. EPDP involves the inclusion of three (3) sets of integral stabilizer blades along the body of the DP. The spiral blades have an OD slightly larger than the tool joint and are coated with a hard, low-friction material, Stellite. This product is manufactured by machining the entire EPDP product from solid stock, thereby providing high structural integrity between the blades and the DP body. The primary advantage of the EPDP is its ability to mechanically disturb and agitate cuttings beds. The mechanical action of the spiral blades rotating against the low-side of the hole guarantees that any cuttings beds will be broken up and the cuttings will disperse into the fluid flow profile. This cuttings beds removal action is important when flow rates are restricted below critical flow rates due to pressure or horsepower constraints. Even with critical flow rates maintained, EPDP provides added assurances that cuttings beds are minimal in size, and are only permanent if they are in washouts or recessed ledges, etc. that will not affect tripping the drill string or running casing. The EPDP should be spaced out at reasonable intervals in the drill string. This will ensure that all areas of the open-hole are wiped with the EPDP with reasonable frequency. EPDP is shown in Figure 17-7.

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Three versions of EPDP are currently available:

• 5 inch EP DP • 5 inch Heavy Wall EPDP • 6-5/8 inch EPDP

14 in

6 5/8 in

18

8 ft15 ft

22 ft

30 ft8 in 10 in

6 in7 in

35

2 13/16 in2 in

Figure 17-7. Enhanced Performance Drill Pipe

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REFERENCES

1. Payne, M. L., Duxbury, J. K., and Martin, J. W., "Drill string Design Options for Extended-Reach Drilling Operations", 1995 ASME ETCE, 30 January - 1 February, Houston, Texas,

2. Underwood, L. D. and Odell, A. C., II, IADC/SPE 27484, "A Systems Approach to Downhole Adjustable Stabilizer Design", presented at the 1994 IADC/SPE Drilling Conference, 15-18 February, 1994, Dallas, Texas.

3. Odell, A. C., Payne, M. L. and Cocking, D. A., "Application of a Highly Variable Gauge Stabilizer at Wytch Farm to Extend the ERD Envelope", SPE 30462, presented at the 70th Annual SPE Fall Conference, 22-25 October, 1995, Dallas, Texas.

4. Cambridge Radiation Technology, Ltd., Crakeside Business Park, Greenodd, Cumbria LA12 7RT, United Kingdom.

5. Cambridge Radiation Technology's Automated Guidance Systems as described by Bell, S., "Innovative Methods Lower Drilling Costs", Petroleum Engineer International, pp.25-26, February 1993.

6. Barr, J. D., Clegg, J. M., and Russel, M. K., "Steerable Rotary Drilling with an Experimental System", SPE/IADC 29382, presented at the 1995 SPE/IADC Drilling Conference, 28 February - 2 March, 1995, Amsterdam.

7. Chur, C. and Oppelt, J., "Vertical Drilling Technology: A Milestone in Directional Drilling", SPE/IADC 25759, presented at the 1993 SPE/IADC Drilling Conference, Amsterdam, 23-25 February, 1993.

8. Donati, F., Oppelt, J., Ragnitz, D., Ligrone, A., and Calderoni, A., "New Concept Steerable Drilling Tools for Horizontal and ERD Applications", to be presented at the 3rd Annual International Conference on Emerging Technologies, 31 May - 2 June, 1995, Aberdeen, Scotland.

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Appendix A

Acronym Glossary

ADP Allowable Departure from Plan

AGS Automated Guidance System

API American Petroleum Institute

AV Annular Velocity

BHA Bottom Hole Assembly

BHCT Bottom Hole Circulating Temperature

BHST Bottom Hole Static Temperature

BOP Blow-out Preventer

BUR Build Up Rate

CBL Cement Bond Log

CT Coiled Tubing

DAC Downhole Activated Centralizers

DBS Diamont-Boart-Stratabit

DC Drill Collar

DEAP Drilling Engineering Applications Platform

DLS Dogleg Severity

DP Drill Pipe

DPP Drill Pipe Protectors

DSS Drill String Simulator

ECD Equivalent Circulating Density

ECP External Casing Packer

EMS Electronic Multishot

EPDP Enhanced Performance Drill Pipe

ER Extended Reach

ERD Extended Reach Drilling

ERW Extended Reach Well

FFT Fast Fourier Transforms

FO Full Opening

HRG Hemispherical Resonator Gyro

HVGS Halliburton Variable Gauge Stabilizers

HWDP Heavy Weight Drill Pipe

JNOC Japanese National Oil Corporation

JORP Joint Operating Reporting Procedures

KOP Kick Off Point

LAS Liquid Additive System

A-1

LCM Lost Circulation Materials

LGS Low Gravity Solids

LOT Leak Off Test

LWD Logging While Drilling

MAC Magnetic Azimuth Correction

MD Measured Depth

MW Mud Weight

MWD Measurement While Drilling

NDT Non-Destructive Testing

NPT Non-Productive Time

NWDP Normal Weight Drill Pipe

OBM Oil-base Mud

OH Open Hole

OOH Out Of Hole

PACT Pump Assisted Coil-Tubing

PBR Polish Bore Receptacle

PDC Polycrystalline Diamond Compact

PDM Positive Displacement Mud Motor

PV Plastic Viscosity

RCDOS Remote Controlled Downhole System

RCLS Rotary Closed Loop System

RIH Run In Hole

ROP Rate of Penetration

RPM Revolutions Per Minute

SCR Silicon Controlled Rectifier

SDSS Super Drill String Simulator

SICP Shut In Casing Pressure

SIDPP Shut In Drill Pipe Pressure

SOBM Synthetic Oil Base Mud

SPP Stand Pipe Pressure

TD Total Depth

TFA Total Flow Area

TSP Top Set Packer

TT Thickening Time

TVD True Vertical Depth

VGS Variable Gauge Stabilizers

WBM Water Base Mud

WOB Weight on Bit

WT Wear Tolerance

WWT Western Well Tools

XRD X-Ray Diffraction

YP Yield Point

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Extended Reach Drilling Guidelines - BP

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