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 Dave Andrew Mark Aston Kevin Barrington Peter Bern Colin Bowes Brian Chambers Dave Cocking Rob Dallimer Joe Duxbury Martyn Fear Mike Guy Phil Hearn Perry Hill John Henderson Kamal Jardaneh

Arnis Judzis Daryl Kellingray Nigel Last Charlie Leslie Yuejin Luo John Martin Mike McLean Samir Modi Rune Olsen Steve Parfitt John Pucknell John Thorogood Allan Twynam Curtis Weddle Hugh Williamson

Statoil Harald Blikra

OGCI Mark Brooker

Gerald Coulter

Deutag John Gammage

Anadrill Andy Hatch

TH Hill Associates Tom Hill

Marc Summers

Halliburton Nic Jepson

Arco Mike Payne

Larry Wolfson

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

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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

•

Martin Fear

•

John Martin

•

Mark Aston

•

John Gammage

•

Mike McLean

•

David Andrew

•

Andy Hatch

•

Rune Olsen

•

Kevin Barrington

•

Phil Hearn

•

Steve Parfitt

•

Peter Bern

•

Perry Hill

•

Mike Payne

•

Harald Blikra

•

Tom Hill

•

John Pucknell

•

Colin Bowes

•

Kamal Jardaneh

•

Marcus Summers

•

Mark Brooker

•

Nic Jepson

•

John Thorogood

•

Brian Chambers

•

Arnis Judzis

•

Allan Twynam

•

David Cocking

•

Daryl Kellingray

•

Curtis Weddle

•

Pat Collins

•

Charlie Leslie

•

Hugh Williamson

•

Rob Dallimer

•

Yuejin Luo

•

Larry Wolfson

•

Joe Duxbury

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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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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.

Industry Extended Reach Wells Departure, m 0

1000

2000

3000

4000

5000

6000

7000

8000

0

1000 Wytch Farm M3

2000

Niakuk

3000

Standard Technology

N.Hydro C26

Amoco T12 A'jack

Statoil C2

Advanced Technology

Pompano Ula

4000

Wytch Farm Miller

Clyde

5000

Other BP Other Operators Dep / TVD = 3 Dep / TVD = 2

6000

Dep / TVD = 1 7000

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 highcapacity (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 “MinimumArea” 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.

2-5

6

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.

WYTCH FARM DRILLING PERFORMANCE

Depth, mBRT

TIME vs DEPTH PLOT 0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000 5500 6000 6500 7000 7500 8000 8500 9000

M5 Actual M3 Actual M2 Actual M1 Actual F21 Actual F20 Actual F19 Actual F18 Actual

0

10

20

30

40

50 60 70 Days from Spud

80

Figure 2-2. Time vs. Depth Plot

2-7

90

100

110

120

130

140

8

WYTCH FARM DRILLING PERFORMANCE AVERAGE METRES PER DAY

250

24" Section 17.1/2" Section

200

12.1/4" Section 8.1/2" Section

150 m/day 100 50 0

F18

F19

F20

F21

M1

M2

M3

M5

Figure 2-3. Average Metres per Day

STAGE III PERFORMANCE COST PER METRE 2500

To 9-5/8" Casing Reservoir Completed W ell

2000

1500 $/m 1000

500

0 F18

F19

F20

F21

M1

Figure 2-4. Cost Per Metre

2-8

M2

M3

M5

WYTCH FARM DRI LLI NG PERFORMANCE PERCENT NON-PRODUCTI VE TI ME 50% 45% 40%

24" Section 17.1/2" Section 12.1/4" Section

35% 30% 25% 20%

8.1/2" Section

15% 10% 5% 0% F18

F19

F20

F21

M1

M2

M3

M5

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.

DAYS vs DEPTH DEPTH (FT 000'S) 0

4000

8000

Tertiary

12000

16000

20000 ACTUAL Balder Sele

PLAN 24000

Forties SST Forties Shale

0

20

40

60

80

100

120

140

TIME (Days)

SAFTEY & ENVIRONMENT

;;;;;; ;;;;;; ;;;;;; ;;;;;; ;;;;;; ;;;;;; ;;;;;; ;;;;;;; ;;;;;; ;;;;;; ;;;; ;; ;;;;;;; ;;;; ;; ;;;;;;; ;;;; ;; ;;;;;;; ;;;; ;; ;;;;;;; ;;;; ;; ;;;;;;; ;;;; ;; ;;

LTA: 0 NEAR MISSES: 0 COMMENTS: NONE

TOTAL TIME

DRILLING 15%

TRIPS 14%

ENVIRONMENTAL IMPACT: UNSCHEDULED EVENTS 24%

CIRC & COND 4% DIRECTIONAL 1% WASH & REAM 1% DRLG CEMENT 1%

SYNTHETIC OIL-BASED-MUD WAS USED AS THE DRILLING FLUID.

RUN CASING 11%

RUNNING TUBING 2% NIPPLE BOPs 1%

CEMENTING & WOCS 3%

TEST BOP/CSG/LOT 1%

MISC 9%

LOGGING/PERF 8% OTHER 2%

UNSCHEDULED EVENTS BREAKDOWN

;;;; ;;;; ;;;; ;;;; ;;;; ;;;; ;;;; ;;;; ;;;; ;;;;

;;;;;;;;; ;;;;;;;;; ;;;;;;;;; ;;;;;;;;; ;;;;; ;;;;; ;;;;; ;;;;; ;;;;; ;;;;; ;;;;;

CEMENT PROBS 1%

WORKING INTREST AMOCO: 21.14 % BRITISH GAS 57.79 % AMERADA 18.67% PHILLIPS: 1.01 % FINA: 0.87 % AGIP: 0.52 %

STUCK PIPE 51%

CASING PROBS 2%

RIG REPAIR 9%

HOLE PROBS/REAMING 9%

WEATHER 3% MISC 2%

EVAL EQUIP FAILURE 14%

DIRECTIONAL PROBS 9%

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

VERTICAL DEPTH, FT

0 ACTUAL

1000

PLAN 2000 3000 4000 5000 0

2000

4000

6000

8000

10000

12000

HORIZONTAL DISPLACEMENT, FT

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 121/4 inch hold. High dilution as a result of losses degraded rheology and required sweeps

0

BLOCK WEIGHT ACTUAL WELL PATH

2000 MEASURED DEPTH, FT

•

NORMAL RUN

INSIDE CASING FF = .33 BUOYANCY ASSISTED

4000 13-3/8"CSG @ 5047'

ACTUAL WEIGHTS

6000 OPEN HOLE FF = .60 8000

0

20000

40000

60000

80000

INDICATOR WEIGHT, LBS

Best sweep rheology seemed to be with Fann 3 rpm reading of 50100.

Drilling Equipment •

Large top drive on the rig with 26,500 ft-lb of continuous torque output. DRILL PIPE BUMPER SUB HYDRAULIC RELEASING TOOL RUNNING HEAD TIE-BACK SLEEVE

SAFTEY JOINT

INFLATABLE PACKER

DRAG RING 7" LINER LANDING COLLAR FLOAT COLLAR FLOAT SHOE

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

100000

120000

British Petroleum Wytch Farm F18 General Project Background •

•

•

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

Wytch Farm 1F-18SP (Cost vs depth) Actual Depth (m) 0 500

Severe Gumbo problems required refining of mud properties

1000

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.

2000

1500

2500 3000 3500 4000 4500 0

800M

1.6MM 2.4MM 3.2MM 4.0MM 4.8MM 5.6MM 6.4MM 7.2MM 8.0MM Cost (US$)

•

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

•

Successfully ran 2 ECPs in liner.

Wytch Farm 1F-18SP (Time vs Depth) Actual Depth(m) 0 500 1000 1500 2000 2500 3000 3500 4000 4500 0

10

20

30

40

50

60

70

80

90

100

Time (Days)

BP - Wytch Farm, F18 - Page 1 of 1

British Petroleum Wytch Farm F19 General Project Background •

•

•

Mud & BHA programs redesigned and top-hole problems eliminated.

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

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.

Actual Depth (m) 0

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.

3000

•

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.

1000

2000

4000

5000

6000 $0

$1,600,000 $3,200,000$4,800,000 $6,400,000$9,600,000 $9,600,000$11,200,000 Cost (US$)

Wytch Farm 1F-19SP (Time vs Depth) 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.

0

1000

2000

3000

4000

5000

6000 0

20

40

60

80

100

120

140

160

Time (Days)

BP - Wytch Farm, F19 - Page 1 of 1

British Petroleum Wytch Farm F20 General Project Background •

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

Wytch Farm 1F-20SP (Cost vs depth) Actual Depth (m) 0

1000

2000

3000

4000

5000

6000 0

800000

1600000

2400000

3200000

4000000

4800000

5600000

Cost (US$)

Wytch Farm 1F-20SP (Time vs Depth) Actual Depth(m) 0

1000

2000

3000

4000

5000

6000 0

10

20

30

40

50

60

Time (Days)

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

70

80

90

British Petroleum Wytch Farm F21 General Project Background •

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 Wytch Farm 1F-21SP (Cost vs depth) Actual Depth (m) 0 1000 2000 3000 4000 5000 6000 7000 0

800M

1.6MM 2.4MM 3.2MM 4.0MM 4.8MM 5.6MM 6.4MM 7.2MM 8.0MM Cost (US$)

Wytch Farm 1F-21SP (Time vs Depth) Actual Depth(m) 0

1000

2000

3000

4000

5000

6000

7000 0

10

20

30

40

50

60

70

Time (Days)

BP - Wytch Farm, F21 -Page 1 of 1

80

90

100

British Petroleum Wytch Farm M2 General Project Background •

Geosteered 1750m in reservoir section

•

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

•

Wytch Farm 1M-02SP (Cost vs Depth) Actual Depth (m) 0 1000 2000

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.

3000 4000 5000

•

World record departure of 6760m

6000

•

Deepest RFT data point at 7400m

7000

•

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.

8000 0

1600000

3200000

4800000

6400000

Actual Depth(m) 0 1000 2000 3000 4000 5000 6000 7000 8000 20

9600000

Cost (US$)

•

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

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

0

8000000

40

60

80

100

Time (Days)

BP - Wytch Farm, M2 - Page 1 of 1

120

British Petroleum Wytch Farm M3 General Project Background •

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) Actual Depth (m) 0 1000 2000 3000 4000 5000 6000 7000 8000 0

800M

1.6MM 2.4MM 3.2MM 4.0MM 4.8MM 5.6MM 6.4MM 7.2MM 8.0MM Cost (US$)

Wytch Farm 1M-03SP (Time vs Depth) Actual Depth(m) 0 1000 2000 3000 4000 5000 6000 7000 8000 0

10

20

30

40

50

60

70

Time (Days)

BP - Wytch Farm, M3 - Page 1 of 1

80

90

100

British Petroleum Wytch Farm M5 General Project Background •

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) Actual Depth (m) 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 0

1600000

3200000

4800000

6400000

8000000

9600000

1120000

1280000

Cost (US$)

Wytch Farm 1M-05SP (Time vs Depth)

Actual Depth(m) 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 0

20

40

60

80

100

Time (Days)

BP - Wytch Farm, M5 - Page 1 of 1

120

140

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 FISHING 11%

OTHER HOLE PROBLEM 11%

FLUIDS 6% MISC 9%

CEMENTING 16%

BOP 18%

WEATHER 29%

A-13 Cost vs. Depth Depth (md) 0 3000 6000 9000

Squeeze 16" Shoe

Hurricane

12000 Wellhea d

15000

Float Equipment

18000 21000 0

1000

2000

3000

4000

5000

6000

7000

8000

Cost ($M)

A-13 Days vs. Depth Depth (md) 0 3000 6000 9000

Squeeze 16" Shoe

Hurricane

12000 Wellhead

15000

Float Equipment

18000 21000 0

5

10

15

20

25

30

35

40

45

50

Days

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

55

60

65

70

75

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 MISC 15%

FISHING 12%

BOP/WELLHEAD 12%

LOST CIRCULATION 27% WELLBORE INSTABILITY 35%

Mississippi Canyon 108 A-27 Days vs Depth

D e p t h

0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000

Days

FINAL DAYS 56.5

0

5

10

15

20

WATER DEPTH 1030'

25

30

35

40

AFE 45 DAYS

45

50

55

60

30.7 DAYS/10,000

Mississippi Canyon 108 A-27 Cost vs Depth 0

5000 D e p 10000 t h 15000

20000 Cost 0

500

1000

1500

AFE $4,539,000

2000

2500

3000

3500

4000

4500

FINAL COST $5,571,280

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

5000

5500

6000

COST/FT $307.8

Forest Oil Corp. Eugene Island 326 No. A-6 General Project Background

• • • •

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

0

•

1

1,000

2 13-3/8" 1,107' T.V.D.

1. Lost Hole - 20" "NO GO"

2,000

2. Lost Hole - Hole Opener Twist Off

3,000

4,000

5,000

6,000

Directional • • •

DAYS 26" D.P.

MEASURED DEPTH

•

Eugene Island 326 A-6 Eugene Isl., Blk. 326 Offshore, LA

9-5/8" 2,007' T.V.D. 7" 2,176' T.V.D.

7,000

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).

8,000

0

10

20

30

50

60

ACTUAL CASING PROGRAM DEPTH VS. DAYS

•

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.

•

40

DAYS

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. •

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

INDICATOR WEIGHT (LBSx1000) -12

-9

-6

-3

0

3

6

9

12

15

18

21

24

27

30

33

36

39

0

•

500 1000

TORQUE

MEASURED DEPTH (FT)

1500

Mud System

2000

FLOATED 7" CASING

•

2500

Seawater and polyacrylamide with lubricants with high vis pills prior to casing jobs Flow rates comparable to vertical wells in the area.

3000 3500 4000

FLOATED CASING ROTATING WEIGHT

SELECTIVE FLOTATION DEVICE PICKED UP

•

4500 ROTATION PROBABLY NECESSARY

5000

Drilling Equipment

5500 6000

•

6500 7000

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.

•

7500 0

5000

10,000

TORQUE (FT/LBS)

7000

6000

5000

4000

3000

2000

0

1000

1000 1000

150

0

1218 1410

1000

1610 1896

0

1786 2000

2174 59 301 M.D.

FINAL B.H.L. 6098.06' S-

59 301 M.D.

3000

59 301 M.D.

1000 59 301 M.D.

North 2000

3000

0

1000

2000

3000

4000

5000

6000

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

7000

Norsk Hydro C-26A in Oseberg Field, Norwegian North Sea General Project Background •

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.

0 1,000

Budget

22 3/4-in.

Actual

2,000

Measured depth, m

•

17 1/2-in.

3,000 4,000 5,000

6,000 12 1/4-in. 7,000 8,000 8 1/2-in.

9,000 10

20

50

70

90

110

Days

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.

East 1,200 2,400 3,600 0 600 1,200

300

1,800

0

2,400

27 in. conductor-286m

300

3,000 3,600 4,200

600 900 1,200

C-26

1,500

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

1,800

C-26A

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

2,100 2,400 2,700

9 5/8 in. casing-7,157m C-26A C-26

3,000 0

600

7-in. liner

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

Vertical section, m

TRSCSSV at 242 m

7-in. tubing 7-in., 30-ft. polished bore receptacle Flex-lock liner hanger at 5,073 m 7-in tie back seal mandrel

SABL-3 Packer at 6,918 m Sleeve installed at 6,980 m Top of 7-in. liner at 7,079m

9 5/8-in. casing shoe at 7,157

7-in. liner shoe at 9,325 m

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

5,400 5,800 6,000 6,600 6,900

South

True vertical depth, m

0

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

DAYS VS. DEPTH

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.

26" section 1000 17 1/2" section 2000

3000

DYP (mMDRKB)

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.

0

4000

12 1/4" section

5000

6000

7000

Total unscheduled events for the well were 9.3% of which 27. 2% were due to drilling.

8000

8 1/2" section Kompletering

9000 0

10

20

30

40

50

60

70

80

90 100 110 120 130 140 150

TID (Dager) Optimal tid

AFE-tid

Virkelig tid

Kompletering

Discussion & Conclusions 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.

UNSCHEDULED EVENTS BREAKDOWN CASING 23.1% COMPLETION 8.5% BOP 12.4%

WORKOVER/RECOMPLETE DRILLING 27.2%

WELL CONTROL 2.4% TESTING 4.5% RIG 1.7% FISHING 14.0%

TOTAL TIME COMPLETION 13.7% CASING 20.7%

BOP 2.9% WORKOVER/RECOMPLETE TESTING 2.4%

DRILLING 43.9%

UNSCHEDULED EVENTS 9.3%

WELL PATH East -400

Plotted values are measured depths Axis is Grid North

0

400

800 1200 1600 2000 7600 7200 6800 6400 6000 5600 5200 4800 4400 4000 3600

0

3200 2800

250

30" Casing 2400

True Vertical Depth

500 20" Casing 750

2000

1000

1600

1250

1200 800

1500 13 3/8" Casing

1750

400 0

2000

-400

2250 9 5/8" Casing

2500

7" Liner

2750 3000 -250

0

250

500

750 1000 1250 1500 1750 2000 2250 2500 2750 3000 3250 3500 3750 4000 4250 4500 4750 5000 5250 5500 5750 6000 6250 6500 6750 7000 7250 7500

Statoil - Statfjord C02 - Page 2 of 2

North

-250

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

TOTAL TIME

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.

COMPLETION 5.8% DRILLING 44.0%

BOP 3.5% SNUBBING 3.9% RIG 0% PLUGBACK 3.8% EVALUATION 2.4% MOVING 0.2% UNSCHEDULED EVENTS 26.7%

UNSCHEDULED EVENTS BREAKDOWN

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 81/2 inch section in well B-29BT2 had to be plugged due to fish in the hole. 0

BOP 0.9% DRILLING 74.2%

CASING 5.6% SNUBBING 0.2% PLUGBACK 6.6% COMPLETION 1.9% FISHING 3.4% EVALUATION 5.8% WELL CONTROL 1.4%

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.

24" Section B29

-1.000 17 1/2" Section B29

-2.000

CASING 9.7%

8 1/2" Section B29 12 1/4" Section B29A

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.

-3.000

Total unscheduled events for the well were 26.7% of which 74.2% were due to drilling. -4.000 12 1/4" Section B29B

-5.000 8 1/2" Section B29BT2

-6.000 8 1/2" Section B29A

Discussion & Conclusions 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.

-7.000

-8.000 15

30

45

60

75

90 105 120 135

PLANLAGT VIRKELIG REVIDERT

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 PATH B-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) 13 3/8 inch

9 5/8 inch

1500

T1

B-29B

T2

B-29BT3 TD 6,710m

1750

T3

7 inch

-2 50

B-29A

0

25

50 -32

00

50

-35

50

T4

B-29BT2 TD 6,863m

0

2250

T5

00

2000

-7

B-29

-5

True Vertical Depth (m)

1250

0 0 75

)

(m

00

-40

50

00

15

00

-45

50

12

-42

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

m)

th (

Nor

00 10

st

Ea

50 -37

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

DAYS VS. DEPTH

When drilling the 3098m 12-1/4” section, the well had a 110° change in azimuth at an inclination of about 80°.

Total unscheduled events for the well were 11.1% of which 55.1% were due to drilling.

1000 17 1/2" section 2000

DEPTH (mMD RKD)

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.

0

3000 12 1/4" section 4000

5000

Discussion & Conclusions 6000

8 1/2" section

Other experience from the well includes: •

Successful use of IDF DF 94/004 decreased friction factor from 0.30 to 0.20.

7000

•

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

8000

•

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 TIME (Days)

AFE Line

Target Line

Compl AFE

Actual time

70

80

90

100

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

TOTAL TIME COMPLETION 6.9% WORKOVER/RECOMPLET DRILLING

0.5%

42.1% CASING

13%

MOVING 0.8% BOP 3.1% WIRELINE 1.8% SNUBBING RIG

4.5%

PLUGBACK 2.6% EVALUATION 2.5%

0.5%

UNSCHEDULED EVENTS

11%

COILED TUBING

10.7%

UNSCHEDULED EVENTS BREAKDOWN SNUBBING

17.4% WORKOVER/RECOMPLET.

BOP 1.5% COMPLETION 3.7% FISHING

COILED TUBING

8.3%

EVALUATION RIG 4.4%

0.5%

3.4%

CASING

DRILLING

4.1%

1.7%%

55.1%

East

Scale 1: 160.00

160

480

800 480

-100

WELL DATA

160 18 5/8

100 300

svy/prop

slot

well

wellpath

p3627

slot #42

B42

B42 Feet P

s4002

slot #42

B42

B42 Feet P

30 -160

30

-480 13 3/8

18 5/8

500

-800

700

-1120

900

-1440

1100

-1760

1300

-2080 9 5/8

1500

B42 1 GP

-2400

North

True Vertical Depth

Scale 1: 100.00

-4000 -3680 -3360 -3040 -2720 -2400 -2080 -1760 -1440 -1120 -800 -480 -160 -300

B42 2 GP .1 Tgt 1700

-2720

B42 3 GP .2Tgt 13 3/8

1900

-3040 B42 4 GP .3Tgt B42 PLAN

gt

2300

/8

95

2500

T ,1

GP

21

B4

GP

22

B4

P,

2 B4

2

B42 FINAL SURVEY

3G

-4000

gt

T

,3

GP

2700

4 42

-4320

B

B42 PLAN

2900

1/2

5 B42 FINAL SURVEY

3100

-1400 -1200 -1000 -800

Scale 1: 100.00

-600

-400

-200

0

200

400

-3360 -3680

t Tg

600

800

1000 1200 1400 1600 1800 2000 2200 2400 2600 2800

Vertical Section on 128.26 azimuth with reference 33.53S, 10.76E from structure centre

Statoil - Statfjord B42- Page 2 of 2

Scale 1: 160.00

2100

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

Bu

ild

an

dH

old

Und

erse

Double

ction

Build

Multiple Build (with tange

nt)

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 =

1

μ

(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 costeffectively 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.

DOWNHOLE PRESSURE (PSI)

10000 LOWER 12 1/4" SECTION OPERATING ENVELOPE

7500

RE

U SS

E

H

PR

G

HI

5000

CE

D SE

BY

EA 0" ) AR0.02

A

RE

C DE

NG X TI PRO A R P

.

N RE

FE

R TE

PEE IS

E

(I

R

FE

100

150

200

OPERATING TEMPERATURE ( F )

Figure 3-2

3-10

H

M TE

G

HI

IN 50

P.

IN

C EN

R TE

0

BY

E

R

0

D

0.

E AS

CR

NONTE

2500

0"

01

A

O C ALREN M E R F

IN

0"

01

0.

250

300

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:

⎡ 9377(OD 4 − ID 4 ) ⎤ 2 ⎢ L ⎦⎥ Maximum weight (lb) = ⎣ 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

PP13-3/8”) 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

Gyro and Inertial Tools

QA, Tool Comparison and Learning

•

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.

•

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.

•

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 Slip-stick (torsional)

Symptoms Cyclic surface torque fluctuation/top drive stalling. Connection over-torque and back off.

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).

Control 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. 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.

Repeated slow build-up/abrupt drop in surface torque. BHA Whirl (lateral)

Localized tool joint wear.

Reduce RPM and/or increase WOB.

Increased MWD shocks.

Higher lubricity mud.

Erratic surface torque.

Use non rotating stabilizers and tool joint protectors. Use roller stabilizers.

Bit Bounce (axial)

Large surface vibration (obvious in shaking of equipment). Large WOB fluctuations.

reamers

rather

than

Use shock sub. Adjust drilling parameters (often to higher RPM and/or lower WOB).

Bit damage, usually tricones in hard formations. 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.

DRILLING TORQUE (ft-kips) 0

30 ROTARY SPEED (rpm)

0

250

ROTARY FEEDBACK ON

ROTARY FEEDBACK OFF

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 ExtendedReach 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 underbalanced 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. 2. 3. 4. 5. 6.

A permeable formation is exposed in the open hole Overbalanced condition at the permeable formation Thick filter cake accumulation at the formation face String is in contact with the filter cake Insufficient string movement 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 Summary Points:

Psi

Psi

• 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. 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”.

P P P

Formation Mud

P P P P P P

P

P

P

P P

16-5

Reactive CLAY BALLS MUD RINGS

Summary Points: • Wellbore stability - chemically inhibit shales, especially over long exposure times • Fluids Issues - select proper mud type - OBM or other inhibitive mud • Operations - monitor trends: torque/drag, cuttings type, shape, and load 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) • Operations - monitor trends: torque/drag, cuttings type, shape, and load 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 filtrateinduced 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 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 • Operations - monitor trends: torque/drag, cuttings type, shape, and load

Salt

Salt

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 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.

Geometry

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. A

A

DRILL COLLAR

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

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.

WELLBORE GEOMETRY LEDGING

SHALE

SANDSTONE

SHALE LIMESTONE

SALT

LEDGING AT FORMATION CHANGES

16-12

Collapsed Casing Summary Points:

Squeezing Salt Drill Pipe

Bottom Hole Assembly

Casing

Squeezing Salt

• 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 Summary Points: CEMENT

• 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 retorqued 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.

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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 (