Drilling tools and deflection methods

Table of Contents

Provisory - 06 Dec 96 Confidential Directional Drilling 5-i

5 Drilling Tools & Deflection Methods Page5.1 DRILLING TOOLS ................................................................................................................5-1

5.1.1 Drill Collar (DC) ......................................................................................................5-15.1.1.1 Short Drill Collar (SDC) .................................................................................5-25.1.1.2 Non-Magnetic Drill Collar (NMDC) ..............................................................5-25.1.1.3 Short Non-Magnetic Drill Collar (SNMDC) ..................................................5-2

5.1.2 Float Sub...................................................................................................................5-25.1.3 Bit Sub ......................................................................................................................5-35.1.4 Junk Sub....................................................................................................................5-35.1.5 Extension Sub ...........................................................................................................5-35.1.6 Heavyweight Drill Pipe (HWDP).............................................................................5-35.1.7 Stabilizer ...................................................................................................................5-4

5.1.7.1 Welded-blade Stabilizer ..................................................................................5-55.1.7.2 Integral-blade Stabilizer (I.B.) ........................................................................5-55.1.7.3 Sleeve-type Stabilizer......................................................................................5-75.1.7.4 Clamp-on Stabilizer.........................................................................................5-75.1.7.5 Other stabilizers ..............................................................................................5-85.1.7.6 Replaceable Wear Pad stabilizer(RWP) .........................................................5-85.1.7.7 ANDERGAUGE Stabilizer.............................................................................5-9

5.1.8 Roller Reamer...........................................................................................................5-105.1.9 Underreamer .............................................................................................................5-105.1.10 String Reamer .........................................................................................................5-115.1.11 Key-seat Wiper .......................................................................................................5-125.1.12 Turbine....................................................................................................................5-125.1.13 Bent Sub..................................................................................................................5-135.1.14 Orienting Sub..........................................................................................................5-135.1.15 Bent Orienting Sub (BOS)......................................................................................5-145.1.16 Hole Opener............................................................................................................5-145.1.17 Bullnose ..................................................................................................................5-155.1.18 Section Mill ............................................................................................................5-155.1.19 Whip-stock..............................................................................................................5-165.1.20 Drilling Jars ............................................................................................................5-165.1.21 Shock Absorber/Shock Sub ....................................................................................5-165.1.22 Rebel Tool ..............................................................................................................5-175.1.23 Steerable Motor ......................................................................................................5-17

5.2 DEFLECTION METHODS ......................................................................................................5-185.2.1 Whipstock .................................................................................................................5-185.2.2 Jetting........................................................................................................................5-19

5.2.2.1 Advantages of Jetting ......................................................................................5-205.2.2.2 Disadvantages of Jetting .................................................................................5-20

5.2.3 PDM (or Turbine) With Bent Sub ............................................................................5-205.2.4 Steerable Positive Displacement Motor ...................................................................5-21

Table of Contents

Provisory - 06 Dec 96 Confidential Directional Drilling 5-ii

List of Figures PageFigure 5-1 Flush and spiral drill collars ................................................................................... 5-2Figure 5-2 Junk sub .................................................................................................................. 5-3Figure 5-3 Dimensional data range of heavy weight drill pipe................................................ 5-4Figure 5-4 Various types of hardfacings. ................................................................................. 5-5Figure 5-5 Welded blade stabilizers......................................................................................... 5-6Figure 5-6 Integral blade stabilizers........................................................................................ 5-6Figure 5-7 Sleeve-type stabilizers ............................................................................................ 5-7Figure 5-8 Clamp-on stabilizers............................................................................................... 5-8Figure 5-9 Rubber sleeve stabilizer.......................................................................................... 5-8Figure 5-10 RWP stabilizer...................................................................................................... 5-9Figure 5-11 ANDERGAUGE stabilizer................................................................................... 5-9Figure 5-12 Roller reamers .................................................................................................... 5-10Figure 5-13 Under-reamer...................................................................................................... 5-11Figure 5-14 String reamer ...................................................................................................... 5-11Figure 5-15 Key seat wiper .................................................................................................... 5-12Figure 5-16 Bent sub .............................................................................................................. 5-13Figure 5-17 UBHO................................................................................................................. 5-14Figure 5-18 Hole opener ........................................................................................................ 5-14Figure 5-19 Bullnose.............................................................................................................. 5-15Figure 5-20 Section mill......................................................................................................... 5-15Figure 5-21 Shock sub............................................................................................................ 5-16Figure 5-22 Rebel tool............................................................................................................ 5-17Figure 5-23 Whipstock deflection method............................................................................. 5-18Figure 5-24 Jetting deflection method ................................................................................... 5-19Figure 5-25 Typical PDM BHA............................................................................................. 5-21Figure 5-26 Steerable motor................................................................................................... 5-22Figure 5-27 Steerable motor bit offset ................................................................................... 5-23

List of Tables PageNo list of tables.

Drilling Tools & Deflection Methods

Provisory - 06 Dec 96 Confidential Directional Drilling 5-1

5 Drilling Tools & Deflection MethodsAbout this chapter

Before the arrival of the positive-displacement mud motor (PDM), whip-stocks, knucklejoints and jetting (in soft formations) were used as deflection methods. DD tools andtechnology have evolved tremendously in the past 20 years. Today, there is a broad rangeof PDMs for different applications.

The various methods used to deflect a wellbore are described in this chapter. Orientationis covered separately in Chapter 11. The DD must be familiar with all the DD tools at therig-site and in the workshop. EQ Jars and PDMs are covered separately in this manual.The remaining DD tools are briefly described here. More detailed information isavailable from the manufacturers. Most of the DD tools are straightforward to operate.

While a directional drilling simulator is a useful aid in the teaching of DD concepts, theonly way to fully understand how a wellbore is deflected and how the various DD toolsare used is to get some on-the-job training. This chapter should provide a lot of thebackground knowledge required.

Objectives of this Chapter

On completing this chapter the directional driller should be able to do the followingexercises

1. Describe the use of an open-hole whip-stock.

2. Explain how deflection is achieved using the jetting kickoff technique.

3. Explain what determines the dogleg severity achieved with a non-steerable PDMkickoff BHA.

4. Describe the uses and applications of:

DC, SDC, NMDC, SNMDC, I.B. stabilizer, Sleeve-type stabilizer(s), clamp-onstabilizer, RWP, Bent Sub, UBHO, BOS, Underreamer, String Reamer, Bullnose,Hole Opener, Key-seat Wiper, Section Mill, Shock Sub, Rebel Tool.

5.1 Drilling ToolsThe major drilling tools likely to be used by the DD are discussed briefly here. For moredetailed information on a particular tool, it is necessary to refer to the "CompositeCatalog" or to the manufacturer’s data sheets.

5.1.1 Drill Collar (DC)

Drill collars are heavy, stiff steel tubulars. They are used at the bottom of a BHA toprovide weight on bit and rigidity. Flush or spiral drill collars are available. In directionaldrilling, spiral drill collars are preferable (Figure 5-1). The spiral grooves machined inthe collar reduce the wall contact area by 40% for a reduction in weight of only 4%. Thechances of differential sticking are greatly reduced. Spiral drill collars usually have slipand elevator recesses. Stress-relief groove pins and bore back boxes are optional. Thedrill collars (various sizes) are normally owned by the drilling contractor.



Figure 5-1 Flush and spiral drill collars

5.1.1.1 Short Drill Collar (SDC)

Often called a pony collar, this is simply a shortened version of a steel drill collar. Shortdrill collars may be manufactured or a steel drill collar may be cut to make two or moreshort collars. For the DD, the SDC and the short non-magnetic drill collar (SNMDC)have their widest application in the make-up of locked BHAs. SDCs of various lengths(e.g. 5’, 10’, 15’) are normally provided by the DD company.

5.1.1.2 Non-Magnetic Drill Collar (NMDC)

Non-magnetic drill collars are usually flush (non-spiral). They are manufactured fromhigh-quality, corrosion-resistant, austenitic stainless steel. Magnetic survey instrumentsrun in the hole need to be located in a non-magnetic drill collar of sufficient length toallow the measurement of the earth’s magnetic field without magnetic interference.Survey instruments are isolated from magnetic disturbance caused by steel componentsin the BHA and drillpipe. ANADRILL’s M1 MWD tool and its successors are fixedinside their own special MWD non-magnetic drill collars. SLIM-1, however, is runinside a standard NMDC. Stress-relief groove pins and bore back boxes are optional.

5.1.1.3 Short Non-Magnetic Drill Collar (SNMDC)

A short version of the NMDC, SNMDCs are often made by cutting a full-length NMDC.The SNMDC may be used between a mud motor and an MWD collar to counteractmagnetic interference from below. It is also used in locked BHAs, particularly where theborehole's inclination and direction give rise to high magnetic interference. Finally,BHAs for horizontal wells often use a SNMDC.

5.1.2 Float Sub

This is a PIN x BOX sub which is bored out to take a float valve. It is often run above amud motor. In conventional rotary BHAs, a float valve is inserted either in the bit sub (inthe case of a pendulum BHA) or in the bored-out near-bit stabilizer. Poppet and flapperdesigns of float valve are available. Note that some clients may not allow the use of afloat valve (because of kick-control problems). The DD should check the client'sregulations on arrival at the rig. The float sub is usually provided by the DD company.The float valve is usually provided by the drilling contractor.



5.1.3 Bit Sub

This is a BOX x BOX sub which is run directly above the bit (hence its name) when nonear-bit stabilizer is used. It is bored out to take a float valve. Various sizes of bit sub arenormally provided by the drilling contractor.

5.1.4 Junk Sub

A junk sub is fabricated from a solid steel body with a necked-down mid-portion. A"skirt" is fitted to the lower part of the body, around the necked-down portion, forming abasket for junk to settle in (Figure 5-2).

The junk sub is run directly above the bit. It catches pieces of junk which are too heavyto circulate out. Bleed holes in the skirt allow the mud to return to the system. The junksub is provided by the drilling contractor.

Figure 5-2 Junk sub

5.1.5 Extension Sub

This is a short sub which can be used to fine-tune a BHA. It is normally PIN x BOX. Afloat sub can be used as an extension sub. The extension sub is usually provided by theDD company.

5.1.6 Heavyweight Drill Pipe (HWDP)

This is an intermediate-weight drill string member with drill pipe dimensions for easierhandling. Its heavy wall tube is attached to special extra-length tool joints. These provideample space for recutting the connections and reduce the rate of wear on the OD. TheOD of the tube is also protected from abrasive wear by a centre wear pad (Figure 5-3).Tool joints and wear pad are hard-banded. Some HWDP have two wear pads.



Note: All dimensions are given in inches, unless otherwise stated.

E

5" 23" Min.

D 18˚A

3"3"

24"

BD

5" 25" Min.

E 18˚

DIMENSIONAL DATA RANGE II

3 1/2 2 1/16 .719 6.280 4

Nom.Size(A)

ID(B)

WallThick-ness

CenterUpset

(C)

Nom. TubeDimension

4 2 9/16 .719 7.410

4 1/2 2 3/4 .875 9.965

5 3 1.000 12.556

4 1/2

5

5 1/2

3 5/8

Eleva-tor

Upset(D)

4 1/8

4 5/8

5 1/8

TensileYield(lb)

407,550

548,075

691,185

345,400

Tor-sionalYield(ft-lb)

27,635

40,715

56,495

19,575

MechanicalProperties

Tube Section

TUBE

N.C. 38(3 1/2 I.F.)

ConnectorSize & Type

N.C. 40(4 I.F.)

N.C. 46(4 I.F.)

N.C. 50(4 1/2 I.F.)

OD(E) ID

4 3/4

5 1/4

6 1/4

6 1/2

2 3/16

2 11/16

2 7/8

3 1/8

TensileYield(lb)

407,550

548,075

691,185

345,400

Tor-sionalYield(ft-lb)

27,635

40,715

56,495

19,575

MechanicalProperties

Tube Section

Area

TOOL JOINT

Wt./ft

29.7

41.0

49.3

25.3

Wt./Jt.30 ft

890

1230

1480

760

ApproximateWeight IncludingTube & Joints (lb)

WEIGHT

Make-upTorque(ft-lb)

13,250

21,800

29,400

9,900

Figure 5-3 Dimensional data range of heavy weight drill pipe

HWDP is less rigid than DCs and has much less wall contact. Chances of differentialsticking are reduced. Its three-point wall contact feature solves two serious problems indirectional drilling. It permits high-RPM drilling with reduced torque. HWDP can be runthrough hole angle and direction changes with less connection and fatigue problems.Today, the trend in BHA design is to minimize the number of DCs in the BHA and useHWDP to comprise a major portion of available weight on bit

HWDP is normally provided by the drilling contractor. However, it is the DD’sresponsibility to ensure there are sufficient joints of HWDP on the rig. For normaldirectional jobs, 30 joints of HWDP should be sufficient.

5.1.7 Stabilizer

Stabilizers are an indispensable part of almost all rotary directional BHAs. Near-bitstabilizers have BOX x BOX connections. They are usually bored out to accept a floatvalve. String stabilizers have PIN x BOX connections. Most stabilizers have a right-handspiral. For directional control, 360 wall coverage (in plan view) is recommended.Stabilizer blades are "dressed" with various possible types of hard-facing (Figure 5-4).The leading edge of most stabilizer designs also has hard-facing applied. It is possible toorder variations of stabilizer design. Stabilizers are used to:

• Control hole deviation.

• Reduce the risk of differential sticking.

• Ream out doglegs and keyseats.



HardfacingsCrushed tungsten carbide held in a nickel bronze matrix. The 3 mm grain size ensuresgreater concentration of carbide which isideal for soft formatioin drilling.

Trapezoidal tungsten carbide inserts held in asintered carbide nickel bronze matrix. Thiswill give a greater depth of carbide coverage -ideal for high deviation drilling in abrasiveformations.

Tungsten carbide insert set iin a powder spraydeposit is ideal for abrasive formations. 97%bonding guaranteed. Certified by ultrasonicreport. Recommended for non-magnetic stab-ilizers.

Tungsten carbide inserts (button type). The in-serts have been developed to allow cold inser-tion and maintain close fit. A greater concen-tration of inserts on the bottom third of theblade and leading edge will increase surfacecontact to reduce wear in highly abrasiveformations.

The oxy-acetylene process applies tough mol-ten carbide particles of varying sizes held in anickel chrome matrix which provides excellentbonding properties and greater surface wearcharactristics are achieved.Surface hardness levels over 40HRC. Ideal forGEO-THERMAL applications over 350˚C.

Sections through hardfacings

Figure 5-4 Various types of hardfacings.

There are many designs of stabilizer. The most common types are:

5.1.7.1 Welded-blade Stabilizer

The blades are welded on to the body in a high-quality process that involves pre-heatingand post-heating all components and the assembled unit to ensure stabilizer integrity andminimize the possibility of blade failure. Blades can be straight, straight-offset or spiraldesign (Figure 5-5). Welded-blade stabilizers are not recommended in hard formationsbecause of the danger of blade fatigue. They are best suited to large hole sizes where theformation is softer because they allow maximum flow rates to be used. They arerelatively cheap. The blades can be built up when worn.

5.1.7.2 Integral-blade Stabilizer (I.B.)

I.B. stabilizers (Figure 5-6) are made from one piece of material rolled and machined toprovide the blades. They are more expensive than welded-blade stabilizers. The leadingedge may be rounded off to reduce wall damage and provide a greater wall contact areain soft formations. They can have either three or four blades. I.B. stabilizers normallyhave tungsten carbide inserts (TCIs). Pressed-in TCIs are recommended in abrasiveformations.



SpiralBlade

StraightBlade

(offset)

StraightBlade

Figure 5-5 Welded blade stabilizers

Figure 5-6 Integral blade stabilizers



5.1.7.3 Sleeve-type Stabilizer

There are two main designs of sleeve-type stabilizer (Figure 5-7):

• Two-piece stabilizer (mandrel and sleeve). The sleeve is screwed onto thecoarse threads on the outside of the mandrel and torqued up to the recommendedvalue. Sleeve makeup torque is low. There is no pressure seal at the sleeve. It isconvenient to change sleeves on the drill floor. This design of stabilizer ismanufactured by several companies. It is in wide use today.

• Three-piece stabilizer (mandrel, sleeve and saver sub). The sleeve is screwedonto the mandrel first, by hand. The saver sub is then screwed into the mandreland this connection is torqued up to the recommended value. In this case, there isa mud pressure seal at the mandrel/saver sub connection. Makeup torque of thisconnection is the full value for that size of API connection. Great care must betaken (clean and dope the shoulders properly, use correct makeup torque),otherwise downhole washouts etc. will result. It can be quite difficult anytime-consuming to change/service the sleeve. For these reasons, this design ofsleeve-type stabilizer is not as widely used today as it was some years ago.

Figure 5-7 Sleeve-type stabilizers

5.1.7.4 Clamp-on Stabilizer

Several designs are available e.g. REED, Servco-loc, EMTEC. An example is shown inFigure 5-8. Clamp-on stabilizers allow more flexibility in BHA design. They can bepositioned on NMDCs, MWD, PDMs etc. at the required spacing to maintain directionalcontrol. Nonmagnetic clamp-on stabilizers are available on request Some clients areapprehensive about running clamp-on because of the danger of them moving positiondownhole. Sometimes they’re difficult to take off after POOH.



Figure 5-8 Clamp-on stabilizers

5.1.7.5 Other stabilizers

Non-rotating Rubber Sleeve stabilizer (Figure 5-9): This type of stabilizer is usedsomewhere above the top conventional stabilizer in the BHA, especially in abrasiveformations. The rubber sleeve does not rotate while drilling. Blade wear and walldamage are thus minimized. A special elastomer sleeve may be used in temperatures upto 350 °F.

Figure 5-9 Rubber sleeve stabilizer

Rockyback and Hydro-string stabilizers: Christensen designs. The sleeve is shrunk onhydraulically to the mandrel. They are not used much today.

5.1.7.6 Replaceable Wear Pad stabilizer(RWP)

Has four long blades 90° apart composed of replaceable pads containing pressed-in TCIcompacts (Figure 5-10). RWP stabilizers are good for directional control and/or inabrasive formations but may give excessive torque.



Figure 5-10 RWP stabilizer

5.1.7.7 ANDERGAUGE Stabilizer

The ANDERGAUGE stabilizer (Figure 5-11) is a downhole-adjustable stabilizer. It hastwo positions - open (full gauge) or closed (under gauge). It is expanded to full gaugedownhole by slacking off a small amount of weight-on-bit and is then locked in place bya hydraulic latch. To deactivate, the pumps are cut back before pulling off bottom. In thiscase, the hydraulic latch locks the stabilizer in the closed position when normal pumprate is resumed. Further information is available in the ANDERGAUGE manual.

Figure 5-11 ANDERGAUGE stabilizer



5.1.8 Roller Reamer

Roller reamers are designed to maintain hole gauge, reduce torque and stabilize thedrillstring. They can be 3-point or 6-point design (Figure 5-12). Both nearbit and stringroller reamers are available. They are particularly useful in abrasive formations.

Near-bit roller reamers help prolong bit life. They are normally bored out to accept afloat valve. A near-bit roller reamer is sometimes used in place of a near-bit stabilizerwhere rotary torque is excessive. Sometimes one or more string roller reamers are alsoused in a BHA. Roller reamers help to ream key seats, dog legs and ledges.

Figure 5-12 Roller reamers

Cutters are available for soft, medium and hard formations. Cutters, blocks and pins canbe changed at the rig-site.

5.1.9 Underreamer

Common applications for the underreamer are wiping out bridges and key-seats, openingdirectional pilot holes, opening hole for a casing string below a BOP restriction. The toolis opened hydraulically. It is held in the open position while hydraulic pressure ismaintained. When the pumps are shut off, the arms collapse back into the body of theunderreamer (Figure 5-13). Various formation-type cutters are available. Cutter arms andnozzles can be changed on the rig. A "full-coverage" configuration of cutter arms mustbe used. One size body accepts a range of sizes. It is recommended to run abull-nose below the underreamer when opening a directional pilot hole in soft formation.This eliminates the possibility of an accidental sidetrack. Underreamers are normallymanufactured PIN UP.



Figure 5-13 Under-reamer

5.1.10 String Reamer

A string reamer is designed to increase the diameter of any key-seat through which itpasses. The body of a string reamer is sometimes made from a short length of HWDP.The connections are usually the same as on the drillpipe. Blades are welded on the body(Figure 5-14). The blades are hard- faced. The blades may be either straight or tapered.The O.D. of the blades varies, but is never greater than the bit diameter.

A more expensive design of string reamer is machined from one piece of steel andhard-facing then applied.

A string reamer is normally run in the drillpipe. It is positioned in the drillstring so that,on reaching bottom, it is close to the top of the key-seat area. As drilling progresses, thestring reamer helps to ream out the key-seat.

String reamers with larger-O.D. bodies are designed to be run in the drill collars. Theyhave the same connections as the DCB.

Figure 5-14 String reamer



5.1.11 Key-seat Wiper

In a well where key-seating is a problem, a key-seat wiper (Figure 5-15) can be runbetween the top drill collar and the bottom joint of HWDP. When POOH, the hard-facedsleeve (which has an O.D. typically 1/4" greater than that of the DCs) tends to wedge inthe keyseat first. By releasing the drillstring, the sleeve is jarred out of the key-seat. Theclutch at the bottom of the sleeve is automatically disengaged. The string is then rotatedand the hole back-reamed. The sleeve re-engages the tool body. It acts as a reamer toenlarge the key-seat and allow free passage of the drill collars. The tool can be eithersingle-clutch or double clutch design. The sleeve has spiral blades with TCI hard-facingto provide fast cutting action and good resistance to wear.

Figure 5-15 Key seat wiper

5.1.12 Turbine

This tool uses centrifugal fluid mechanics. It is a totally different principle to thepositive-displacement motor (PDM). Energy is diverted from the velocity or volume ofmud flow directed onto a stationary angular stator, creating a rotating force on theopposed angular rotor. Each rotor/stator combination is called a stage. A turbine for DDwork has many stages. Turbines (often called turbodrills) are not used much today. Theyare normally run by specialists.



5.1.13 Bent Sub

A bent sub (Figure 5-16) normally is manufactured PIN x BOX. The pin connection ofthe bent sub must be compatible with the box of the PDM of the same O.D. The pin ismachined at a certain offset angle to the axis of the body of the sub (high side). Thisangle usually from 1° to 3° in increments of 1/2°. A scribe-line on the body of the sub,directly in line with the centre of the pin offset, is used as the master reference fortool-face position. A bent sub is used directly above a PDM or turbine. It forces the bit tofollow a certain arc of curvature as it drills.

Offset Pin

Body

Figure 5-16 Bent sub

5.1.14 Orienting Sub

An orienting sub is commonly called a UBHO (Universal Bottom Hole Orientation) sub.It is a straight sub having PIN x BOX connections which are compatible with the bentsub and/or the NMDCs. It is bored out to accept a mule-shoe sleeve. After allintermediate connections have been torqued up fully, the key of the mule-shoe sleeve isaligned directly above the scribe-line of the bent sub. This key is the landing-point forthe mule-shoe survey running gear. It gives the DD the tool-face position on his surveydisc. The sleeve is locked in place using two hexagonal screws (3/8" allen key required)which are screwed in from the body of the sub. Figure 5-17 shows the situation when themule-shoe stinger is landed on the UBHO, with the mule-shoe slot sitting on the key ofthe UBHO sleeve. This is the situation when surveying during a singleshotkickoff/correction run sidetrack.



Mule ShoeOrienting Assembly

"O" Ring

Sleeve

Mule Shoe

Key

"O" Ring

Screw

UHBOSub Body

Mule ShoeStinger

Figure 5-17 UBHO

5.1.15 Bent Orienting Sub (BOS)

A BOS is simply a sub which combines the features of a bent sub and a UBHO. Theoffset pin is compatible with the PDM, it is bored out to take a mule-shoe sleeve etc.

5.1.16 Hole Opener

A hole opener is usually designed as a fixed-diameter tool (Figure 5-18). Hole openersare used to open pilot holes. Various formation-type cutters are available. The cuttersand nozzles can be changed on the rig-site. The use of a bullnose (rather than a bit)below the hole opener when opening directional pilot holes is strongly recommended.Hole openers are usually manufactured PIN UP.

Figure 5-18 Hole opener



5.1.17 Bullnose

A bullnose is used to guide a hole opener or underreamer, particularly in deviated pilotholes. The bullnose can be either hollow or solid. Some under reamers have no nozzles.Thus, it is advisable to run a jet bullnose (Figure 5-19) directly below the underreamer insuch a situation. The fluid is directed upwards by the jets to clean the cutters and help theunderreaming operation. Bullnoses are usually manufactured PIN UP.

Figure 5-19 Bullnose

5.1.18 Section Mill

Figure 5-20 Section mill



This tool is used to mill a section of casing (usually prior to a cased-hole sidetrack). TheServco K-mill (Figure 5-20) is the most common in ANADRILL. It operates on a similarprinciple to the underreamer. It includes six triangular cutters which are dressed withtungsten carbide. On reaching the depth of the top of the section, pump pressure isapplied. Three of the cutter arms expand and begin the cut-out. When the casing cut-outis complete, the second set of three arms expands into the milling position. The Flo-Telfeature gives a positive surface indication of casing cut-out. All six cutter arms are thenseated squarely on top of the casing and milling of the section proceeds.

5.1.19 Whip-stock

The fore-runner of the PDM as a deflection tool, whip-stock can be open-hole or cased-hole. The open-hole whip-stock is retrievable. It is mainly used to do a deep sidetrack inhot holes or on small rigs. The cased-hole whip-stock is used to perform a sidetrack frominside casing. It is oriented, anchored inside the casing to allow deflection from thecasing and is left in place. Several trips are necessary to complete the cased-holesidetracking operation.

5.1.20 Drilling Jars

These are designed to deliver an impact either upwards or downwards. Jars are run indeviated wells so that the string can be jarred free in case of tight hole or stuck pipe. Jarscan be either mechanical, hydraulic or hydro-mechanical design. The earthquaker (EQ)jar is manufactured by Schlumberger. It will be covered in Chapter 6.

5.1.21 Shock Absorber/Shock Sub

Drilling shock absorbers were designed to solve the problems of drill string vibration.The shock absorber absorbs or reduces the bit-induced vibration. The ANADRILL shockabsorber is called a SHOCK GUARD (Figure 5-21). It includes specially-designedsprings having high end load capacity and low spring rate that dampen vibration intension and compression.

Drilling Mud

Floating Pistion

OilSpring

Bearing

Splines

Bearing

Mandrel

Body

Mandrel

Body

Torque-transmitting splines

Figure 5-21 Shock sub



5.1.22 Rebel Tool

The rebel tool corrects lateral drift by counteracting the bit walk. It can either slow downthe bit walk or eliminate it completely. Left-hand or right-hand paddles are available.The paddles can be changed at the rig-site. It is most suitable in medium formations. Therebel tool can be used at inclinations above 12° in hole sizes from 8 1/2" to 12 1/4". Aleft-hand rebel tool (long paddle) is shown in Figure 5-22. With the advent of steerablemotors, the rebel tool is seldom used today.

Figure 5-22 Rebel tool

5.1.23 Steerable Motor

This is the “state-of-the-art" in terms of DD tools. It is a PDM which can be oriented orrotated as required. A bent housing allows deflection to occur in oriented mode. Smallcorrections to the well path can be made as required. BHA design allows inclination toshow minimal change in the rotary mode. Steerable motors are covered in Chapter 7.



5.2 Deflection MethodsThe main deflection tools used in directional drilling are:

• Whipstocks

• Jetting

• Motors

5.2.1 Whipstock

The retrievable, open-hole whip-stock is only used in special applications e.g. rigs withsmall pumps, sidetrack in deep, very hot hole.

The whip-stock is pinned to a limber BHA which includes a small bit (Figure 5-23). Atypical BHA is:

• Whip-stock + Pilot Bit + Stabilizer + Shearpin sub +1 Joint of Drill Pipe +UBHO + Non-magnetic DC.

Figure 5-23 Whipstock deflection method

The hole must be clean before running the whip-stock. On reaching bottom, circulation isstarted. The concave face of the whip-stock is oriented in the desired direction. The toolis set on bottom. The toe of the wedge is anchored firmly in place by applying sufficientweight to shear the pin. The bit is lowered down the whip-stock face. Rotation of thedrillstring is started About 15’ -20’ of rathole are drilled at a controlled rate.



The whip-stock is retrieved and the rathole opened with a pilot bit and hole opener.Another trip using a full-gauge bit, near-bit stabilizer and limber BHA is then made.About 30’ are drilled. More hole deflection is obtained. A full-gauge directional BHA isthen run and standard drilling is resumed.

It is obvious that the whip-stock deflection method of deflecting a wellbore istime-consuming and involves several runs.

5.2.2 Jetting

This technique is used to deviate the wellbore in soft and friable formations. The wellcan be kicked off and built up to maximum inclination using one BHA. Special jettingbits can be used or it’s possible to use a standard long-tooth bit, normally using one verylarge nozzle and two other blank (or very small) nozzles.

A typical jetting BHA is:

• Bit + Near-bit Stab. + UBHO + MWD + NMDC + Stab. + DC + Stab., etc.

A formation suitable for jetting must be selected. There must be sufficient room left onthe kelly to allow for jetting and drilling the first few feet after the jetted interval. Thecentre of the large nozzle represents the tool face and is oriented in the desired direction.Maximum circulation rate is used while jetting. Jet velocity for jetting should be 500ft/sec. The drillstring is set on bottom. If the formation is sufficiently soft, the WOB"drills off”. A pocket is washed in the formation opposite the large nozzle (Figure 5-24).The bit and near-bit stabilizer work their way into the pocket (path of least resistance).Enough hole should be jetted to “bury" the near-bit stabilizer. If required, the bit can bepulled off bottom and the pocket "spudded". The technique is to lift the string about 5'off bottom and then let it fall, catching it with the brake so that the stretch of the string(rather than the full weight of the string) causes it to spud on bottom. Spudding can besevere on drillstring, drilling line and derrick and should be kept to a minimum. Anothertechnique which may help is to "rock" the rotary table a little (15) right and left of ourorientation mark while jetting.

Step 1Orientatedand Jetting

Step 2Drilling

Step 3Re-Orientated

and Jetting

Figure 5-24 Jetting deflection method



After a few feet (typically 5’) have been jetted, the pumps are cut back to about 50% ofthat used for jetting. The drillstring is rotated. It may be necessary to pull off bottommomentarily due to high torque (nearbit stabilizer wedged in the pocket). High WOB andlow RPM are used to try to bend the collars above the near-bit stabilizer and force theBHA to follow through the trend established while jetting. The remaining footage on thekelly is drilled down. Deflection is produced in the direction of the pocket i.e. thedirection in which the large jet nozzle was originally oriented. To clean the hole prior toconnection/survey, the jet should be oriented in the direction of deviation. Aftersurveying, this orientation setting (tool face setting) is adjusted as required, dependingon the results achieved with the previous setting. Dogleg severity has to be watchedcarefully and reaming performed as required.

The operation is repeated as often as is necessary until sufficient inclination has beenachieved and the well is heading in the desired direction. The hole inclination can thenbe built up to maximum angle using 100% rotary drilling. Small direction changes can bemade if needed. The jetting method is compatible with the single-shot method or MWD.Figure 5-24 illustrates the sequence.

Jetting BHAs are discussed in Chapter 10. In very soft formation where hole erosionmakes it impossible to keep enough WOB when drilling, a more limber ("Gilligan")jetting BHA may be required.

5.2.2.1 Advantages of Jetting

• There is no offset in the assembly. Thus, survey errors are minimal compared toPDM/bent sub alternative.

• Surveys can be taken much closer to the bit than when using a PDM.

• There is no reactive torque when jetting. The "tool face" can be oriented moreaccurately than when using a PDM. This is particularly important when close toother wells.

5.2.2.2 Disadvantages of Jetting

• The main problem with jetting is that that erratic, sometimes severe doglegs canoccur over short sections of hole. The problem is compounded by the fact thatthese doglegs may be underestimated by normal survey practices. The calculateddogleg is actually an average value over the total interval between surveys. Muchof this dogleg may have been created in the short section of hole which wasjetted. The actual dogleg severity in this part of the hole may be much higherthan that calculated from the surveys.

• Below 2,000’ TVD, the formation normally becomes too firm for efficientjetting/spudding. A mud motor/bent sub kickoff would be preferable.

5.2.3 PDM (or Turbine) With Bent Sub

In this method (Figure 5-25), a bent sub is run directly above a PDM. A typical BHA isas follows:

• Bit + PDM + Bent sub + Float sub + Orienting sub (UBHO) + Non-magneticDCs + Steel DCs + HWDP + DP.



Bit

Bent SubAngle

Mud Motor

Bent Sub

Float Sub

Orienting Sub

NonmagneticDrill Collar

Figure 5-25 Typical PDM BHA

The pin of the bent sub is offset at an angle of 1°-3°. A scribe line is cut on the outside ofthe body of the bent sub, above the centre of the pin offset. The bent sub allowsdeflection to occur by pushing the mud motor to one side of the hole. As drillingprogresses with the drillstring locked, the bit is forced to follow a curved path. Thedegree of curvature (dogleg severity) depends on the bent sub offset angle and the OD ofmotor, bent sub and drill collars in relation to the hole diameter. It also depends on thelength of the motor and on the type of formation. The appropriate bit-bent sub/PDMcombination is chosen to give the desired dog-leg severity. An orienting sub (UBHO)allows single- shot surveys to be taken as required.

Because of the high bit offset caused by the bent sub, it is advisable not to rotate thistype of BHA unless in special circumstances e.g. difficulty getting to bottom,re-establishing orientation.

5.2.4 Steerable Positive Displacement Motor

The most common type of steerable motor (Figure 5-26). is the single bent-housingdesign.

The motor housing is not straight. One of the motor housing connections (usually theconnecting rod housing) is machined at a certain precise offset angle. This is known asthe bent housing angle. The bent housing angle is usually 1.5°. At offsets greater thanthis, it becomes difficult to rotate and motor life is shortened.



Bearing HousingStabilizer

Bent Housing(less than 2°)

PDM Power Section

Optional Dump Valve

String Stabilizer

Figure 5-26 Steerable motor

Because the bend in the housing is quite close to the bit, the nominal bit offset is muchless than when using a straight PDM with bent sub as the deflection method. This isshown in Figure 5-27. However, the rate of deflection (dog leg severity) achieved for arelatively small bent housing offset angle is high.

A steerable motor can be used to perform kickoffs, correction runs and sidetracks.However, the usual application of a steerable motor is as the major component of a BHAwhich can be used in oriented ("sliding") or rotary mode. In sliding mode, the steerablemotor changes the course of the well. The BHA is designed as a "locked" assembly inrotary mode.



The ideal use of a steerable motor is to drill a complete hole section from casing point tocasing point. In theory, provided the bit and BHA selection is good, a steerable motorcan stay in the hole until the next casing point. The extra cost to the client of running themotor must be compensated for by significant savings in rig time - due to less round tripsand/or faster ROP.

A surface-adjustable bent housing is now available. The next technological advance willbe a downhole-adjustable bent housing.

SideForce

SideForce

1" NominalBit Offset

18" NominalBit Offset

ConventionalBent Sub/MudMotor Assembly

SteerableSystem

Figure 5-27 Steerable motor bit offset

Drilling tools and deflection methods

Engineering

Drilling tools and deflection methods