L7- Wellbore Deflection & BHA Selection

7/28/2019 L7- Wellbore Deflection & BHA Selection

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Lecture

7:

DIRECTIONAL

DRILLINGDownhole Deflection of Wellbore &BHA Selection in Directional Wells

Arun S Chandel

Assistant [email protected]

09997200339

1


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Deflecting Tools & Techniques

There are several methods of deflecting a wellbore. Bydeflecting we mean changing the inclination and/or azimuth ofa wellbore. The most common methods that have been usedare:

1. Whipstocks

2. Jetting

3. Rotary Bottomhole Assemblies with AdjustableStabilizers

4. Steerable Motors with Adjustable Stabilizers

5. Rotar Steerable Assemblies


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WhipStock

The whipstock was the main deflection tool from 1930-1950. Astandard whipstock is seldom used nowadays, but it has notdisappeared completely.

Whipstocks are used in coiled tubing drilling for re-entry work. Thereare 3 types of whipstock used in conventional directional drilling:

1. Standard removable whipstock

Tool DesignThe Standard Removable Whipstock is mainly used to kick off wells,but can also be used for sidetracking. It consists of a long invertedsteel wedge which is concave on one side to hold and guide the

to prevent the tool from turning, and a heavy collar at the top towithdraw the tool from the hole. It will usually be used with a drillingassembly consisting of a bit, a spiral stabilizer, and an orientationsu , r g y a ac e o e w ps oc y means o a s ear p n.


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2. Circulating whipstockThe Circulating Whipstock is run, set and drilled like the standardwhipstock. However, in this case the drilling mud initially flowsthrough a passage to the bottom of the whipstock which permits

clean seat for the tool. It is most efficient for washing out bottomhole fills.

. ermanen cas ng w ps ocThe Permanent Casing Whipstock is designed to remain

permanently in the well. It is used where a window is to be cut incasin for a sidetrack. The casin whi stock can be set usin aPacker. A special stinger at the base of the whipstock slips into thepacker assembly, and a stainless steel key within the packer locksthe whipstock's anchor-seal and prohibits any circular movement

ur ng r ng.


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A d v a n t a g e

1. Lesser Operational time than other whipstocks

Gives a sharp dogleg so not recommended ifconsiderable distance is to be drilled below thesidetrack.


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ProcedureforSideTrackingaCasingusingbottomtrip

whipstockThe majority of whipstocks used today are used to sidetrack out ofcasing. The whipstock is hard enough to allow milling a window in the

.

1) Figure 7-2 is an illustration of a common whipstock. In this case, a castiron bridge plug (CIBP) was set with a wireline five feet above a casingco ar o avo m ng e cas ng co ar w e r ng o e w ps oc .

2) A mule shoe sub is placed above the whipstock, and the assembly isrun as shown to approximately 15 to 20 feet (4.5 to 6 m) above theCIBP.

3) The face of the whipstock is oriented in the desired direction with arosco ic surve tool. If the inclination is above 5o it can be oriented

with an MWD.

4) Lower the drill string until the whipstock tags bottom (do not set slips).

5) Check the orientation of the whipstock again. If the orientation is OK,

set the slips on the whipstock by applying weight.


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7) After setting the slips, set down enough weight to shear the shear bolt.Pick up and rotate the pipe to ensure that the whipstock is set and theshear bolt has sheared.

8) Once the whipstock is set, it is time to drill off the whipstock. Thestarter mill is used to start cutting the window. The starter mill onlydrills a short distance (approximately 2 feet or 0.6 m) as illustrated inFigure 7-3.

9) The starter mill is then pulled from the hole. A window mill along with awatermelon mill is run to actually cut the window in the casing asillustrated in Figure 7-4.

10)Once the well has been sidetracked and rathole drilled, the string isreamed throu h the window several times to clean it u .

11)When finished, it is a good idea to run the BHA through the window afew times without rotation to make sure that it is not going to hang up.


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Jetting

formations. The technique was developed in the mid 1950s andsuperseded the use of whipstocks as the primary deflection technique.A special jet bit may be used, but it is also common practice to use as an ar so orma on r -cone , w one very arge nozz e an

two smaller ones.


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Requirements for jettingThe formations must be soft enough to be eroded by the mudex ng e arge nozz e. s a roug ru e o um , orma onscannot be drilled at penetration rates of greater than 80 ft/hrusing normal drilling parameters, they are not suitable for jetting.Jettin is most effective in soft sand formations and itseffectiveness is reduced as depth increases, since the formationsbecome more compacted.Adequate rig hydraulic horsepower must be available. For jetting

available at the bit to erode the formation. A rule of thumb forjetting is that mud velocity through the large jet should be at least500 ft/sec.

Jetting AssembliesA typical jetting assembly used to drill a 121/4pilot hole is:

- ,2) extension sub,3) 12-1/4stabilizer,4) UBHO sub,5) 3 x 8" Drill Collars,6) Drill Collar, HWDP as required.


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Procedure for jetting1. The assembly will be run to bottom, a survey is taken and thearge e nozz e e oo ace s or en a e n e requ redirection.

2. Maximum circulation is established e. . 800 m in 12-1 4hole) and a controlled washout is effected. The drill string may bespudded up and down periodically, but not rotated, until severalfeet of hole have been made and the bit and near bit stabilizer

.lift the string 5 to 10 feet off bottom and then let it fall, catching itwith the brake so that the stretch of the string causes it to spudon bottom rather than the full weight of the string.

Another technique which may improve the effectiveness of jettinginvolves turning the rotary table a few degrees (15) right and left

.

3. Having jetted 3 to 8 feet of hole drilling is started. Thecirculation rate is now reduced to about 50%. Hole cleaningconsiderations are ignored while drilling the next 10 feet or so.


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4. High weight on bit (40 - 45 Klb) and low rotary speed (60 70RPM) should be used to bend the assembly and force it to follow

roug e ren es a s e w e e ng. rogress may edifficult at first because of interference between the stabilizer andthe irregularly shaped jetted hole.

5. After approximately 10 feet of hole has been drilled, the pumprate can be increased to perhaps 60% - 70% of the rate originallyused while jetting.

.down to the next survey point.

6. A survey is taken to evaluate progress. If the dogleg is toosevere the section should be reamed and another survey taken.


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Positive

Dis lacement

Motor

(PDM)

Enables a bit to be turned by usingthe h draulic ower of the mudrather than the top drive (or kelly)

This reduces the amount of work

to be performed by the drill pipe Enables a well to be directionally

drilled Enables faster rotation of the bit


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Downhole motor and bent sub

A common method of deflecting wellbores is to use a downhole motorand a bent sub. The bent sub is placed directly above the motor andthe bent sub which makes this a deflection assembly. Its lower threadon e p n s nc ne - rom e ax s o e su o y.

The bent sub acts as the pivot of a lever and the bit is pushedsidewa s as well as downwards. This sidewa s com onent of force atthe bit gives the motor a tendency to drill a curved path, providedthere is no rotation of the drill string. T h e d e g r e e o f c u r v a t u r e

( d o g l e g s e v e r i t y ) d e p e n d s o n t h e b e n t s u b a n g l e a n d t h e O D o f e m o o r , e n s u a n r c o a r s n r e a o n o e a m e e r

o f t h e h o l e . I t a l s o d e p e n d s o n t h e l e n g t h o f t h e m o t o r .

Usually there would be no stabilizers for at least 90 feet above the

bent sub. In fact, it is not uncommon for the entire BHA to be slickwhen a motor and bent sub is used for kicking off at shallow depths.


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Running Procedures

1. The motor is inspected and tested using standard procedures.2. Before drilling can begin with a motor and bent sub assembly, thebent sub (tool face) must be orientated in the desired direction.

. e p pe s wor e un s r ng orque s e m na e .

4. Make a reference mark on the kelly bushings, lock the rotary tableand take a survey to determine tool face orientation.

5. Turn the pipe to achieve the desired tool face orientation. Thisorientation should include an allowance for the anticipated reactive

torque. A rough rule of thumb is to allow 10 /1000' for lower torquemotors (Mach 2) and 20 /1000' for higher torque motors (Mach 1).

6. When orienting, turn the pipe to the right unless the turn is lessthan 90 left of the present setting. Work the string up and down so

that the turn reaches the bottomhole assembly.

7. Lock the rotary table before beginning to drill.


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Exam le

of

a

modern

da

Rotar

Steerable DrillingSystem

with automatic directionalcontrol

This ensures greater

trajectory accuracy Smoother boreholes Greater mud flow capacity


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Advancements

in

Directional

Drillin


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BHASELECTION

In

(OnlyDrill

Collars)


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Research and field experience proved thatbuckling will not occur if weight on bit isma n a ne e ow e uoye we g o ecollars. In practice weight on bit should not

collars.


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ProcedureforselectingDrillCollars

Step 1: Determine the buoyancy factor for the mud weight in use by:

1W

BF=

BF=Buoyancy Factor, dimensionlessMW=Mud weight in use, ppg

65.5

65.5=Weight of a gallon of steel, ppg

Step 2: Calculate the required collar length to achieve the desired weight on bit:

WOB = air weight of drillcollars x BF x 0.85 = DC length x Wdc x BF x 0.85

WOB

WOB=Desired weight on bit, lbf (x 1000)

l 0.85ength dcBF W

BF =Buoyancy Factor, dimensionlessWdc =Drill collar weight in air, lb/ft

0.85 =safety factor


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Calculationofweight/ftofdrillcollars

Considering the drill collars are made of steel (density = 489.5lbm/ft), the weight/ft of drill collars can be calculated by:

lbm/ft = cross section area x 1 ft x density of steel

(lbm/ft)drill collars= {/4 x (OD2 ID2) x 1 x 489.5}/144

Buoyancy factor


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PROBLEM 1

Find the number of drill collars required from the

Weight-on-bit (WOB) = 65,000 lbs

Hole deviation = 00

u ens y = ppg

5-1/2 x 2-1/2 Drill Collars

Each drill collar is 31 ft long.


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BHASELECTION

In

(DrillCollars

+HWDPs)


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RequiredHWDPlength

For directional wells:

( )( ) 1BHAWOB DF = ( )(cos ) HWDPBF W

=well inclination

BHA .


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Example

Drilling 17.5-inch hole with a roller cone bit, we want touse 45,000 lbs WOB in the tangent section at 30

a) What air weight of BHA is required to avoid running

ppg. Use a 10% safety margin.

' -.weighing 220 lbs/ft, a 9.5-inch MWD tool weighing3,400 lbs and 90 ft of 8-inch drill collars weighing

. -be required to meet the criteria in Example 1 (a)?

- = ,


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Solution

a)

b)

), .

56,860(0.847)(cos30) 1,480HWDPL =

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L7- Wellbore Deflection & BHA Selection

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