BHA Design, Vibration Management

WOODSIDE ENERGY LTD

WELL ENGINEERS DESK GUIDE

MODU WELL ENGINEERING

3.17 BHA DESIGN & VIBRATION MANAGEMENT REV. 0

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DOCUMENT CONTROL AND SIGN-OFF

Document No.

N/A

Title

Well Engineers Desk Guide

Custodian

Supervising Drilling Engineer

Revisions (*Commence revisions at bottom and work up – start with Revision 0)

0

11/12/2001

New Document

Dave Crane

*Rev

Date

Description (Reason for Revision)

Author(s)

Initials

This Revision : 0 Reviewed by : Name

Approved By : Initial/Date

Name

Gary Jones

Kevin Gallagher;

Supervising Drilling

MODU Team Leader

Initial/Date

Engineer

Definitions and Approvals

Author(s) =

Have written the document in accordance with WEL systems.

Reviewer(s) =

Have independently reviewed and verified the document in accordance with WEL systems.

Concurrence = Concur with the objectives and content of the document. Approval =

Satisfied that the Author and Reviewers are competent and approves its release as a Well Engineering Document.

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TABLE OF CONTENTS

3.17

BHA DESIGN AND VIBRATION MANAGEMENT............................................................. 4 3.17.1 3.17.2 3.17.3 3.17.4 3.17.5

Purpose & Deliverables ....................................................................................... 4 Scope .................................................................................................................. 4 Responsibilities.................................................................................................... 4 Formation Evaluation Requirements.................................................................... 5 ROP Optimisation................................................................................................ 5 3.17.5.1 Weight On Bit ...................................................................................... 5 3.17.5.2 Roller Reamers vs. Stabilisers ............................................................. 6 3.17.6 Performance Downhole Motors ........................................................................... 6 3.17.7 Hydraulics .......................................................................................................... 7 3.17.8 Bottom Hole Assembly Reliability ........................................................................ 7 3.17.9 Wellbore Trajectory Control & Surveying ............................................................. 8 3.17.10 Fishing & Contingency Planning .......................................................................... 9 3.17.11 Vibration Management......................................................................................... 9 3.17.12 BHA Handling .................................................................................................... 10

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3.17

BHA DESIGN AND VIBRATION MANAGEMENT

3.17.1 Purpose & Deliverables This document describes the processes and methods used by MODU Well Engineering teams to design a drilling Bottom Hole Assembly (BHA) for MODU vertical and/or exploration well. The purpose of this section is to ensure that BHA’s are designed to achieve the following objectives: • Formation Evaluation requirements are achieved including FEWD data, picking core points etc. • ROP’s are optimised. • BHA reliability is maximised. • Well trajectory requirements are achieved. • Sufficient contingency is included in the BHA design to allow for potential hole problems i.e losses, ledging, fishing. • BHA handling time is minimised.

3.17.2 Scope This document applies to drilling BHA’s on any vertical MODU well or any MODU well where a vertical hole section is planned. This document does not cover the design of BHA’s for special operations, i.e. coring, fishing, well testing etc. This document is not intended for use in the planning of directionally drilled wells.

3.17.3 Responsibilities Drilling Engineer The Drilling Engineer is responsible for: • Reviewing offset well data to evaluate the performance of previous BHA designs with respect to formation evaluation objectives, directional (inclination) control, ROP performance (weight transference to bit, surface torque, vibration, losses etc. • Ensuring that the planned BHA design includes takes sufficient account of any problems likely to be encountered during drilling. • Reviewing geological target data with asset geo-science personnel and ensuring that geological targets are as large as possible to allow maximum flexibility in BHA design. • Ensuring that the proposed BHA design is capable of meeting all formation evaluation objectives, i.e. FEWD logs, identifying core points etc. • Ensuring adequate hydraulics are achievable with the proposed BHA design. • Ensuring BHA designs are kept as simple and reliable as possible with respect to handling, thread types, crossover requirements etc. • Ensuring that all BHA components are available when required including back-up equipment, handling equipment etc. • Ensuring that all components can be fished and the correct fishing tools are available at the wellsite. • Ensuring that the proposed BHA complies with WEL policies with respect to well control, well bore surveying and downhole equipment inspection requirements etc.

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Supervising Drilling Engineer The Supervising Drilling Engineer is responsible for: • Reviewing BHA design recommendations and confirming compliance with WEL policies.

3.17.4 Formation Evaluation Requirements Prior to commencing detailed well planning, ensure that formation evaluation requirements for each hole section are clearly understood and documented. Formation evaluation issues which to be resolved with asset geo-scientists during well planning stage include as a minimum the following: i. ii. iii. iv.

Formation evaluation and hydrocarbon logging requirements Expected pore pressure profiles and pore pressure prediction requirements Identification of casing points Identification of core points

In general, FEWD tools should be positioned as close to the bit as possible, this is particularly important where FEWD logs are required to identify casing points based pore pressure transition zones or when identifying a core point etc. However, the advantages of positioning FEWD tools close to the bit need to be weighed against any possible impact on BHA performance. For example, FEWD tools positioned closer to the bit may result in a more limber BHA which may have a tendency to build angle with a high WOB. The number and complexity of FEWD tools included in any BHA should be kept to an absolute minimum. Only ”essential” tools should be included, “nice to have” tools should be avoided. Non-essential FEWD tools will increase the amount of BHA handling required exposing drill crews to additional risks. They are also likely to increase any fishing operations in the event that the BHA is lost in the hole. Nuclear FEWD tools (containing radio-active sources) should only be included in BHA’s where they are considered absolutely essential.

3.17.5 ROP Optimisation

3.17.5.1 Weight On Bit Maximum expected weight on bit (WOB) should be determined from offset well data and technical specifications the proposed bit selection. The BHA should be designed with a sufficient number of drill collars for a maximum WOB equivalent to 80% of BHA weight (including buoyancy) below the jars. Note: Bit manufacturer’s specifications are often conservative when specifying maximum WOB. It is worth confirming maximum recommended WOB with the manufacturer based on actual run data.

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3.17.5.2 Roller Reamers vs. Stabilisers WEL routinely use both roller reamers and conventional integral blade stabilisers for BHA stabilisation. There are inherent advantages and disadvantages with both of these tools and the correct choice will depend on the particular well. The following guidelines, based primarily on MODU Well Engineering experience in the North West Shelf & Timor Sea regions, should be used when deciding which tool should be used. Surface Hole: (17 ½” & 14 ¾”)

Use Roller Reamers only. Historically, interbedded hard stringers have tended to cause ledging and high torque when large diameter stabilisers have been used in surface hole. Roller reamers have tended to reduce torque and minimise ledging.

Intermediate Hole: Use Roller Reamers and/or Stabilisers. Dependent on specific conditions. (12 ¼”) Stabilisers have been known to cause problems with weight stacking and subsequent use of Roller Reamers has been shown to improve weight transfer. Where offset wells have suffered ledging and torque problems or where there is some doubt regarding the performance of stabilisers, Roller Reamers should be used. Production Hole: (8 ½”)

Use Near Bit Roller Reamer + Stabilisers. A NBRR plus IB string stabilisers should be sufficient for most applications. In deeper wells where hard, abrasive or thick sandstone intervals are expected, consideration should be given to all Roller Reamers.

Contingency Hole: Use Stabilisers. Integral blade stabilisers should be used unless hard, (6”) abrasive or thick sandstone intervals are expected where consideration should be given to Roller Reamers. As a general rule, the number of stabilisers and/or reamers included in the BHA should be kept to the minimum number required to ensure stability. Excessive numbers of stabilisers will only serve to increase surface torque and ledging/weight stacking problems. Only sealed bearing type roller reamers fitted with TCI cutters such as Gearhart Redback roller reamers should be used.

3.17.6 Performance Downhole Motors •

Consideration should be given to running a positive displacement or mud motor to improve ROP. The use of a performance motor also has the advantage of de-coupling the bit from the drill string to minimise BHA vibration.

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•

Where a performance motor is used, ensure that the motor OD size is compatible with the hole size being drilled. A motor is a relatively limber item and when small OD motors are used in a relatively large hole size large bending stresses can be generated which can ultimately result in a connection failure. In larger hole sizes the following minimum motor sizes should be used: 17 ½” Hole: 11 ¼” OD motor 14 ¾” Hole: 9 5/8” OD Motor

•

When selecting a performance motor, careful attention should be given to the stator/lobe configuration. High torque’s can be expected in larger size holes particularly where hard stringers are likely to be encountered. The Drilling Engineer should confirm that maximum torque/motor differential pressure is sufficient to allow the hard stringers to be drilled with high WOB without stalling the motor.

3.17.7 Hydraulics •

When optimising hydraulics, ensure that all BHA related pressure losses are accounted for including pressures losses associated with MWD/FEWD tools and mud motors.

•

If a mud motor is included in the BHA the pressure loss associated with the motor should be based on the highest expected on-off bottom differential pressure. If no motor differential pressure historical data is available then the motor’s maximum rated differential pressure should be used for calculations. A “stall pressure” allowance of approx. 200 psi should be included when determining maximum standpipe pressures to avoid lifting mud pump relief valves if the motor stalls.

•

When sizing bit nozzles avoid nozzles smaller than 12/32nd inch to minimise the chances if plugging nozzles with debris. Ensure that the calculated bit pressure loss is compatible with any MWD/FEWD tools included in the BHA.

•

If the BHA will be used to drill out a casing shoe-track, particularly where a subsea plug launching system has been used, then consideration should be given to reducing the number of roller reamers and/or stabilisers in the BHA to an absolute minimum. Problems have been experienced on previous wells with rubber and plastic debris packing off around roller reamers due to their reduced flow area.

3.17.8 Bottom Hole Assembly Reliability BHA’s should be designed to maximise reliability wherever possible by ensuring that: i.

The BHA design is as simple as possible with the minimum number of tools, i.e. minimal FEWD tools. ii. The number of crossovers is minimised. Where possible, drill collars, subs, FEWD/MWD tools, jars etc should be provided with a consistent thread type. iii. Near Bit Stabilisers or Near Bit Roller Reamers are bored to accept a drillstring float valve, avoiding the need to use short float subs near the bit. iv. Large changes in diameter are avoided wherever possible. As an absolute minimum, HWDP should be positioned between the drillpipe and drill collars at the bottom of the string. Careful attention should also be made with respect to the placement of stabilisers/reamers and crossovers etc. WEL Doc. No. Uncontrolled/Revision 0

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v.

Use as large a diameter drill collar and connection type as practical, particularly when drilling large hole sizes to minimise bending stresses. At least one stand of 9 ½” drill collar with 7 5/8” Reg connections should be used when drilling 17 ½” hole. This stand should also include most of the stabilisation subs. vi. When ordering rental stabilisers ensure that the stabilisers comply with the following specifications: Body OD Bending Strength Ratio (BSR) as per DS-1 2nd Edition < 6” 1.8 – 2.5 6 – 8” 2.25 – 2.75 > 8” 2.5 – 3.2 Stress Relief features as per API Spec 7, Section 6 Thread forms as per “NC” convention rather than obsolete “IF” Stabilisers to be inspected to DS-1 2nd Edition, Category 4, Section 3.24 Contractors must be informed of WEL’s inspection and certification requirements for downhole tools and BHA components as per WEPS13 – Quality Assurance in Supply and Service. Where possible, avoid running drilling jars in compression. The BHA should be designed to maintain the jars in tension at all time as per Section 5.1. Drill string float equipment should be inspected prior to installation in the BHA and any suspect elastomeric seals replaced if required. A seal failure during drilling is likely to result in plugged nozzle(s) and subsequent poor hydraulics and bit performance.

3.17.9 Wellbore Trajectory Control & Surveying •

One of the primary objectives of the BHA when drilling vertical wells is to keep the hole vertical or at least minimise any tendency to build inclination. Packed hole BHA’s should always be used for this purpose.

•

It has been routine practice to run a Non Magnetic Drill Collar (NMDC) above any MWD tools to minimise the effects of drillstring related magnetic fields on the MWD directional measurements. However in most vertical wells, where target sizes are relatively large and surveying errors are not critical, it is usually possible to dispense with the NMDC and use a mathematical correction (SUCOP Short Collar Correction) to correct the raw survey data for the effects of magnetic axial interference.

•

The applicability of the SUCOP Short Collar Correction must be checked on a well by well basis. If anti-collision or target size are likely to be an issue or if there is any doubt as to whether the Short Collar Correction is applicable, the NMDC should be run above the MWD tools.

•

If an Electronic Multi Shot (EMS) survey is to be dropped prior to tripping out of hole, a NMDC and Totco Ring must be run in the BHA. However, the inclusion of a Totco Ring in the BHA will prevent the running of any ball or dart actuated drilling tools below the Totco Ring. The DE should confirm whether any drilling tools such as PBL Circulating Subs, Core Barrels etc are required in the BHA. If they are, it may not be possible to drop the EMS and an alternative survey method may be required, i.e. gyro on wireline etc.

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Note: The option of dropping and landing an EMS tool onto a PBL Sub positioned immediately below the NMDC has been investigated previously. It has been determined that this cannot be done due to the risk of either damaging the EMS tool, damaging the PBL sub or plugging the string by jamming the EMS tool into the PBL Sub which may compromise well control in the event of a swabbed kick while tripping out of the hole. •

Use as large a diameter drill collar as possible for the hole size. The larger the drill collar diameter, the stiffer the BHA and the straighter the hole. Just a slight change in diameter (i.e. 8” to 9 ½” OD) will have a very large impact as “stiffness” is proportional to OD4 – ID4.

3.17.10 Fishing & Contingency Planning •

If significant mud losses are anticipated then consideration should be given to including a PBL Circulating Sub in the BHA. If a PBL Sub is run, ensure that there are no ID restrictions above the sub which may obstruct the passage of the setting ball, i.e. Totco rings, FEWD/MWD turbines, crossovers etc.

•

Dimensions of all BHA components should be checked and confirm that the rig’s standard fishing tool package can catch each component.

•

Sufficient drill collar weight should always be run above the drilling jars to provide an adequate impact force when jarring downwards. As a guide, 2 to 3 drill collars will usually be sufficient.

3.17.11 Vibration Management •

Historically, drilling operations in the Timor Sea and North West Shelf have often suffered from problems with excessive vibration resulting in BHA/drillstring failures, poor ROP and MWD/FEWD tool failures.

•

Where high levels of vibration are expected, vibration monitoring sensors should be run with the MWD/FEWD tools to monitor vibration. It is essential that the vibration data is available real time, i.e. pulsed to surface, to allow drilling parameters to be adjusted immediately to reduce vibtration levels. Vibration sensors should be capable of detecting vibration on three separate axes to distinguish between torsional (bit whirl and stick-slip), lateral, and axial vibration modes.The DE should include procedures in the Well Specific Guidelines for wellsite monitoring and management of BHA vibration. The immediate action will normally be to adjust drilling parameters (RPM and WOB) to reduce the level of vibration.

•

Consideration should be given to including a mud motor in the BHA to de-couple the BHA from the rotation of the drill string and maintaining a low (< 60) surface RPM to minimise lateral vibration. One disadvantage of running a mud motor is that it may limit the amount of power that can be transmitted to the bit. If a motor is required, a low speed – high torque lobe configuration should be used with an extended power section.

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3.17.12 BHA Handling •

BHA handling requirements should be kept to a minimum to reduce rig time and reduce exposure of drill crews to a potentially hazardous operation (handling heavy drill collars). This is particularly the case when handling larger 9 ½” and 8 ¼” drill collars.

•

Double handing of BHA components should be minimised. BHA’s for several hole sections should be designed to use the same configuration of drill collars and crossovers where possible, i.e. 36” hole, 26” hole and 17 ½” hole sections should only involve changing stabilisers/roller reamers and the bit.

•

Use of thread crossovers should be minimised. All BHA components should use consistent threads and consideration should be given to re-cutting threads if the cost can be justified on the basis of rig time savings.

•

The BHA should be designed as far as possible so that it consists of full stands to reduce handling time.

REFERENCES • • • • • • •

Example BHA’s – 2001 MODU Drilling Campaign DOG Section 18, Stuck Pipe & Fishing WEP04, Well Control (A6000SD003), WEL Well Engineering Policies & Standards. WEP05, Drilling Practices (A6000SD003), WEL Well Engineering Policies & Standards. WEP12, Offset Well Review (A6000SD003), WEL Well Engineering Policies & Standards. WEP13, Quality Assurance in Supply and Service (A6000SD003), WEL Well Engineering Policies & Standards. Schlumberger Vibration Management Guidelines

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