Welldrill Directional Drilling

SIEP: Well Engineers Notebook, Edition 2, January 2001xii

L – DIRECTIONAL DRILLING

Clickable list(Use the hierarchical list under "Bookmarks" to access individual tables and/or sub-topics)

Depth references L-1

Azimuth true, magnetic & grid L-4

Directional well plan equations L-5

Bottom hole assemblies L-6

The use of mud motors L-15

Surveys L-27

Equations L-29

L–1SIEP: Well Engineers Notebook, Edition 2, January 2001

Top rotary table, RT(used as reference while drilling)

Local datum(always referred to.The only permanent datum)

Top 20" casing head housing, CHH(= top of bottom flange).Often used as reference by the production department as it remains unchanged for the life of the well.

DEPTH REFERENCES

ONSHORE WELLS

30" stove pipe

20" casing

SIEP: Well Engineers Notebook, Edition 2, January 2001L–2

DEPTH REFERENCES

OFFSHORE WELLS DRILLED WITH SURFACE BOPS


DEPTH REFERENCES

OFFSHORE WELLS DRILLED WITH SUB-SEA BOPS


AZIMUTH - TRUE, MAGNETIC AND GRID

In the equations and diagrams below, which refer to a horizontal plane at the point in question :

ATN = Azimuth with reference to True NorthAMN = Azimuth with reference to Magnetic NorthAGN = Azimuth with reference to Grid NorthG = Grid Convergence, which is by definition positive when Grid North is East

of True NorthD = Magnetic Declination, which is by definition positive when Magnetic North

is East of True North

Thus:ATN = AGN + GATN = AMN + D

AGN

ATN

G

Grid North

Here the value of G is positive

True North

Borehole direction ATN

AMN

D

Magnetic North True North

Here the value of D is negative

Borehole direction

Be wary of the term “grid correction” which is used in a similar way to grid convergence but which is, by definition, the negative of grid convergence. Grid correction was the standard used in Well Engineering defined in a previous Borehole Surveying Manual (EP 59300). To comply with standards used in the survey industry and Topographic Departments, Grid convergence has now been adopted as the standard for Well Engineering.

Note also that not all OUs use the standard convention. Within an OU only the local convention should be used. These will be provided by the OU focal point.


D R

d

x

Displacement = Rα = x

= sin-1 ( R )D

= sin-1 ( d )D

DIRECTIONAL WELL PLAN EQUATIONS

With target co-ordinates of ∆N and ∆E relative to the surface position :

the horizontal displacement, d = ∆N2 + ∆E2

and the azimuth, At = tan-1 ∆E (+ 180°)∆ND = TVDtarget - TVDk.o.p.

From the build-up rate, BUR, R = 360 x characteristic length = 5,730 2π BUR BUR

For the build-up section, with inclination α: ∆AHD = 2πα x R 360∆TVD = R sin α

∆d = R(1 - cos α)

For the tangent section : ∆AHD = ∆TVDcos α

∆d = ∆TVD tan α

D R

d

x

y

DR

d

x

y

Displacement < Rα = x - yx = sin-1 ( R cos y )

Dy = tan-1( R - d )D

KOP

KOP

KOP

Target

Target

Targetα

α

α

Displacement > Rα = x + y

x = sin-1 ( R cos y )D

y = tan-1 ( d - R )D


BOTTOM HOLE ASSEMBLIES

FUNDAMENTAL PRINCIPLES

Fundamentals of BHA Design

In all cases, the minimum practical amount of BHA should be run. By running the minimum amount of BHA the torque and drag will be reduced, this in turn will reduce the fatigue generated in the drill string and thereby increase the life of the drill string.

All BHAs place a side force at the drill bit. This side force affects the path followed by the drill bit and the rate of angle change, (dog leg severity), in the well bore.

By planning to minimise the rate of angle change and by selecting the minimum number of tools having the correct material properties and assembling them in the correct order, good BHA design can delay fatigue damage and reduce the severity of drill string failure.

To achieve correct BHA design, it is necessary to understand the basic principles and the effect of selected physical properties of the BHA components.

Factors Affecting BHA Behaviour

The directional behaviour of a rotary BHA is affected in three different ways: by the mechanical characteristics of the BHA, by the drilling parameters applied to the BHA, and by the formation being drilled – over which we have no control.

Characteristics affecting BHA behaviour can be summarised as follows:

• The gauge and placement of stabilisers and other BHA components• The diameter, length and material of the BHA components• Bit type

Drilling parameters affecting BHA behaviour are:

• Weight on bit• Rotary speed• Circulation or flow rate

Directional Control Principles

There are three basic principles used to control well bore direction.

• The fulcrum principle – used to increase the well bore inclination. Inclination is the angle, expressed in degrees, between the path of the well bore and vertical.

• The stabilisation principle – used to hold both inclination and azimuth. Azimuth is the direction, expressed in degrees, between the path of the well bore and true North, or grid North if specified.

• The pendulum principle – used to drop inclination.

Note :

This and the following eight pages about BHAs have been taken from Shell Expro's “Drillstring Failure Prevention - BottomHole Assembly Design Guidelines” (WEIN 553), also available as SIEP Report EP 94-1103.



THE FULCRUM PRINCIPLE

A BHA with a full gauge near bit stabiliser, and between 90 ft and 120 ft of drill collars before the first string stabiliser (or no string stabiliser at all) will build inclination when weight on bit is applied .

The drill collars above the near bit stabiliser bend due to their own weight and also due to the weight on bit. The near bit stabiliser acts as the fulcrum point of a lever transmitting this bending moment down to the bit and pushing the bit upwards, thus building angle.

The following factors act on the build-up rate of this type of drilling assembly:

• Distance between the near bit stabiliser and the first string stabiliser.As this distance increases, the build-up rate also increases. However, once the distance between the first two stabilisers reaches 120 feet any further increase in length has little or no effect and might allow the drill collar to touch the side of the hole.

• The outside diameter of the drill collars.As the outside diameter increases, the collars become more rigid or "stiff' and the build-up rate decreases.

• Material of the drill collars.In the field, a choice of material is seldom available, so options are not normally possible. In a critical well this option should be considered at the planning phase.

• Bit type e.g. Tri-cone, PDC etc.The bit type has little effect on the build or drop rate, the exception being long gauge bits. The increase in gauge length decreases the build tendency. However the bit type does affect the "walk" or azimuth change, tricone bits tend to walk right whereas PDC bits exhibit little or no walk, but each bit does have its own characteristics.

• Weight on bit.An increase of the weight on bit tends to increase the bending force on the collars above the near bit stabiliser and hence the build-up rate.

• Rotary speedWith an increase in rotating speed the BHA becomes effectively more rigid and the build-up rate decreases.

• Flow rate.In soft formations, higher flow rates tend to decrease the building tendency due to the effect of the circulating fluid washing away the formation. This increases the hole size and decreases the support for the BHA.

Figure L-1 shows several BHAs which will exhibit a build tendency. They are graduated from highest to lowest tendency to build angle, and are typical for a 121/4" hole.



THE FULCRUM PRINCIPLE (2)

* At lower inclinations this BHA is the most responsive**The level of build tendency changes with inclination where

BHA Nos. 6 & 7 generate more side force at higher angles

Figure L-1 : BHAs for building inclination



THE STABILISATION PRINCIPLE

By using three or more stabilisers with a short, large diameter drill collar between the near bit stabiliser and the first string stabiliser it is possible to reduce the transmission of bending moment to the bit, forcing it to follow a reasonably straight path. The BHAs that use this principle are called Packed Hole Assemblies and are used in vertical and deviated wells to maintain inclination and azimuth. Some bit walk may still be experienced when drilling with a packed hole assembly.

The following factors are of importance when designing stabilised BHAs:

• Stabiliser design.In large diameter holes (i.e. greater than 171/2") the use of straight bladed stabilisers is common. These are acceptable where the hole is vertical and the torque and drag when drilling is low. Due to its design, this style of stabiliser tends to dig into or "gouge" the well bore and will increase the torque and drag. For most hole sizes, stabilisers with 360° wall contact are available. These are of a long, wide, spiral blade design and provide full, effective support for the BHA without gouging the well bore.

• Near bit stabiliser.In all packed drilling assemblies, the near bit stabiliser must be full gauge. The stabiliser type and the area of blade contact with the hole wall require careful consideration to match formation and hole conditions. In areas of severe tendencies, tandem stabilisers can be used at the near bit position when stabilisers with long and wide blades are not available.

• Stabiliser spacing.The distance between the near bit stabiliser and the first string stabiliser, should be between 2 and 15 feet depending on hole size and hole condition. The shorter the spacing between the stabilisers the more rigid the assembly will be.

• First string stabiliser.The gauge of the first string stabiliser is of great importance and for most cases the stabiliser must be full gauge. (In areas where the assembly tends to drop, e.g. for deviated wells, an under gauge stabiliser is used to help maintain inclination.)

• Bit type.The two most commonly used bit types are tri-cone and PDC bits. The path drilled by a tri-cone bit will vary with applied weight on bit and rpm. PDC bits tend to drill straight holes regardless of weight on bit and RPM; long gauge PDC bits help to maintain a straight well path.

Where possible and depending on the formation, the use of PDC bits is recommended to help maintain a straight well path. With pendulum assemblies long gauge PDC bits can build angle as the long gauge acts as a near bit stabiliser.

• Rotary speed.

A higher rotating speed makes the BHA effectively stiffer and therefore less susceptible to deviate from the required well path. /....


• Formation Effect

The formation being drilled will have an effect on the directional stability of the drilling assembly, however this effect is not the same for all assemblies. Action can be taken to mitigate the effect of formation characteristics and formation changes by studying the behaviour of BHAs in previous wells and catering for the effects observed. The greatest effect will be seen where no near bit stabiliser is in the BHA. Where a packed assembly is in use, the formation effect can take a BHA configured for a slight drop tendency and force it to drop heavily or even build angle.

Figure L-2 shows several packed hole assemblies. These are graduated from a slight building to a slight dropping tendency.

Figure L-2 : Packed hole assemblies for holding inclination angle


THE STABILISATION PRINCIPLE (2)



THE PENDULUM PRINCIPLE

The pendulum principle was originally used to drill vertical wells with slick (non stabilised) BHAs. It was modified to incorporate stabilisers and is still in use today to reduce inclination. The principle uses the weight of the BHA hanging below the tangent point to produce, via gravity, a force that pushes the bit to the low side of the hole. The effect of the pendulum varies with the length of the BHA below the tangent point.

The fundamental pendulum assembly increases the restoring force by increasing the pendulum length with a stabiliser in the proper position. The following are important factors to be considered in the design of pendulum drilling assemblies :

• Near bit stabiliser gauge.All pendulum assemblies use either an under-gauge near bit stabiliser or omit the near bit stabiliser completely.

• Stabiliser spacingThe distance between the bit and the first string stabiliser controls the weight of the hanging portion of the BHA and therefore the pendulum force. If the first string stabiliser is placed too far away from the bit the tangent point will fall between the stabiliser and the bit, i.e. wall contact will take place, thereby reducing the effectiveness of the pendulum.

• Outside diameter of the drill collars.

Drill collar stiffness increases with the fourth power of the outside diameter. Stiffer drill collars will place the tangent point farther away from the bit and also increase the pendulum force. The weight per foot of the drill collars to be proportional to the second power of the outside diameter, i.e., heavier drill collars will produce a larger pendulum force.In summary: For the portion of pendulum BHA below the tangent point or first drill string stabiliser, it is desirable to run drill collars with the largest possible outside diameter. BUT potential problems associated with fishing the drill collars must be considered in the design stage.

• Bit type.To allow the pendulum force to work the bit must be free and unrestricted. Field experience has shown that tri-cone bits and short gauge, flat face PDC bits are the most effective with pendulum drilling assemblies.

• Weight on bit.

The higher the weight on bit, the more the assembly will bend. This can move the tangent point nearer to the bit and hence is detrimental to the effectiveness of the assembly. Furthermore, the side force at the bit, produced by the weight on bit, acts against the pendulum force. Weight on bit as low as possible is desirable for a pendulum assembly. /....


• Rotary speed.A higher rotating speed makes the BHA effectively stiffer and therefore the tangent point moves farther away from the bit. As the assembly becomes stiffer, less bending (due to weight on bit) is transmitted to the bit. Higher rotating speeds will help to enhance the performance of pendulum assemblies, but will also tend to stiffen the pendulum thus increasing the drop. This is most noticeable on shorter pendulum assemblies. This tendency can be counteracted by increasing the length of the pendulum.

Figure L-3 shows a graduated series of pendulum assemblies used to drop inclination.

Figure L-3 : Pendulum assemblies for dropping inclination


THE PENDULUM PRINCIPLE (2)


There is no such thing as a vertical well. All wells are deviated to some extent, the objective during drilling is to keep the well bore as close as possible to vertical. To achieve this objective the well is normally drilled with either a non stabilised slick assembly relying on the pendulum principle to keep the well pointing down, or it is drilled with a stabilised assembly. The principle then being that if it is properly stabilised it will not deviate from the desired path.

A typical method of drilling a vertical well is to use the special dropping assembly shown in Figure L-3. This assembly, when used in vertical holes with light weight on bit, acts as a minimum pendulum assembly but keeps any formation influenced building to a minimum. This type of assembly is mostly used with PDC bits which required low weight on bit.

In practice the wells are often drilled with a combination of both slick and stabilised assemblies.

Slick assemblies

When drilling in a vertical well with a slick assembly the pendulum principle applies.

An equation proposed by R. Hoch establishes a minimum drill collar outside diameter, ODdc, to be run with a specific bit size, ODb, into which a casing which has a coupling diameter of ODcc is to be run.

ODdc = 2 x ODcc - ODb

Stabilised assemblies

In hard formations vertical wells are drilled using packed assemblies to allow maximum weight on bit to be run in order to drill faster. In soft and unconsolidated formations (normally shallow), pendulum BHAs are used to drill vertical wells.

As packed assemblies will bend slightly when used, there is sometimes a tendency to build angle. If this happens a pendulum assembly is used to drop the inclination, followed by a packed assembly to allow more weight to be applied to the bit and drilling to continue.

If the inclination is reduced by the pendulum assembly at too fast a rate, unacceptably large angle changes (dog-legs) can be created. These can prevent the following packed assembly from being successfully run in the hole without first having to ream to bottom. An even worse effect is that large angle changes speed up fatigue failure.

To avoid these problems, it is advisable to have the pendulum portion of the assembly below the packed BHA, so that any dog-legs are reamed as soon as they are created. A further advantage is that the pendulum becomes more efficient due to less bending being transmitted from the upper part of the BHA through the packed section down to the bit.

When drilling vertical wells with packed drilling assemblies the near bit stabiliser should be full gauge. In the event that the well starts to deviate from the vertical, the near bit stabiliser should be examined and replaced if it is found to be under gauge. /....


VERTICAL WELLS


If the near bit stabiliser is full gauge, the width and length of the stabiliser blades should be checked, i.e. not too narrow or too short. If they are found to be acceptable then consideration should be given to either using a near bit stabiliser with wider and longer blades or by using tandem stabilisers in the near bit position.

Alternatively a "Big Bear" near bit stabiliser can be used. These are stabilisers of exceptional blade length, normally in the order of twice the blade length of that seen on a standard stabiliser (3 feet). They are therefore suitable to replace a tandem near bit stabiliser.

When applying any of these latter solutions, exceptional precautions have to be taken when running in hole. Due to the extreme stiffness of the near bit section great care should be taken not to mechanically stick the assembly, especially the first time such an assembly is run in the hole.


VERTICAL WELLS (2)


Picking up a mud motor

Motors are generally supplied with a lifting or handling sub for transporting them to and from the rig floor. These lifting subs are normally rated to lift the motors only and should not be used for heavier lifts such as the complete drilling assembly.

Surface checks prior to running a mud motor in hole

Using the lifting sub, pick up the motor and set into the slips at the rotary table. Install the drill collar safety clamp below the dump valve ports, unlatch the elevators and remove the lifting sub. Check that the dump valve is free to move by pressing downwards with a hammer handle on the upper face of the piston, the piston should travel down two to three inches and return to the open position when the downwards pressure is released.

To check that the dump valve is not leaking, press on the piston again and, whilst holding the valve down in the closed position, fill the valve cavity with water. Release the downward pressure, the piston should return to the open position and the water in the valve cavity will drain out through the ports.

Using a cross over sub, connect the kelly or top drive to the motor. Remove the safety clamp and pick up the motor until the bit sub is above the rotary table. Measure the gap between the bit sub and the bearing housing. Set the motor down, making sure to protect the box shoulder by landing the bit box on wood or on a rubber mat over the rotary table. Measure the gap between the bit sub and the bearing housing again. Check that the measured play is within the specified tolerances for the motor.

Lower the motor so that the dump valve ports are below the rotary table. Start the pumps and, once there is no more flow through the ports, pick up the motor and observe the bit sub rotating. There should be flow between the bearing housing and the bit box. Lower the motor until the dump valve ports are below the rotary table and shut down the pumps.

Pick up the motor and attach the bit using a bit breaker while holding the bit sub with a tong.

Tripping into the hole

Run the tool in the hole carefully. Care should be taken not to run the motor into bridges, ledges or the bottom of the hole. Work through tight spots with the pump on and slow rotation. Should difficulty be experienced when reaming through tight spots care should be taken not to side-track the well through the application of high weight on bit or high rotary speeds.

When running in the hole if the drill string does not self fill, due to the properties of the drilling fluid preventing it from entering the drill string via the dump valve, periodically break circulation to fill the drill string. /....

THE USE OF MUD MOTORS

GENERAL OPERATING PROCEDURES

Note :These mud motor operating procedures have been taken from Shell Expro's “Drillstring Failure Prevention - BottomHole Assembly Design Guidelines” (WEIN 553), also available as SIEP Report EP 94-1103.


In hot wells, above 250°F bottom hole temperature, break circulation periodically while running in the hole to cool down the motor.

When using a PDC bit, avoid circulating inside the casing to prevent damage to the casing and to the bit.

Drilling

To commence drilling, with the bit two or three feet off bottom, start the pumps and slowly increase the flow rate to that required for drilling. Do not exceed the maximum flow rate for the motor. Once the pressure has stabilised make a note of the flow rate and the pump pressure, gently lower the bit to bottom and slowly increase the weight on bit, as the weight on bit increases there will be a corresponding increase in pump pressure.

For each motor there is a specified maximum differential pressure, the difference between the on bottom and off bottom pressure, this maximum should not be exceeded. It is good drilling practice to keep this differential pressure and the flow rate constant.

Tripping out

The procedures for tripping out of the hole are the same as when a rotary drilling assembly is in use.

However, once out of the hole, the bearing clearance should be checked in the same manner as it is checked prior to running in the hole. The motor should also be flushed with fresh water, and the bit removed. The same lift sub used to pick up the motor prior to running in the hole should be screwed in to the top of the motor and made up to a reduced torque valve. The lift sub should not be screwed in hand tight for lifting operations.


GENERAL OPERATING PROCEDURES (2)



STEERING BY MEANS OF “MAGNETIC TOOLFACE”

The magnetic toolface angle is the projection onto the horizontal plane of the angle between Magnetic North and the toolface. Steering tools are used in the magnetic toolface mode to change azimuth in near-vertical (less than about five degrees) wells.

45°Bit and mud motor trying to kick-off in azimuth 45° (Magnetic).

Toolface

Magnetic North

Looking down the drill string towards the bit



STEERING BY MEANS OF “HIGH-SIDE (GRAVITY) TOOLFACE”

The high-side is the top of the hole viewed along the borehole axis. Assuming that the hole has inclination, the low side is the path a small, heavy, ball would follow if rolling slowly down the well. Steering tools are used in the high-side toolface mode to change azimuth in wells with an inclination of more than about five degrees..



STEERING BY MEANS OF “HIGH-SIDE (GRAVITY) TOOLFACE” (2)

High-side

Right

Low-side

Left

High-side

Right

Low-side

Left

High-side

Right

Low-side

Left

High-side

Right

Low-side

Left

a) Toolface = 0°Bit and mud-motor trying to build angle while maintaining azimuth

d) Toolface = 300° (60° left)Bit and mud-motor trying to build angle and turn the well to the left

c) Toolface = 90°Bit and mud-motor trying to maintain inclination and turn the well to the right

b) Toolface = 180°Bit and mud-motor trying to drop angle while maintaining azimuth

Looking down the drill string towards the bit

ToolfaceToolface

Toolface

Toolface



REACTIVE TORQUE

A clockwise rotating downhole motor applies right-hand torque to the bit. There is therefore an equal and opposite torque applied by the bit to the stator housing, and thence to the string. Called 'reactive torque', this can easily be controlled by the operator, by controlling weight on bit. During directional drilling, this reactive torque must be taken into consideration, because it tends to turn the drill string to the left. The actual angle of twist created at the bottom of the string by reactive torque is governed by:• The magnitude of the torque• The length of drill pipe• The torsional elasticity of the drill pipe• The length and torsional elasticity of the HWDP and BHA.

The HWDP and BHA are both much shorter and much stiffer than the drill pipe and can therefore be neglected when estimating the BHA rotation due to reactive torque, given the accuracy to which the estimate is required.

This BHA rotation in a drill string with a mud motor may be estimated as follows:• Measure the standpipe pressure with the bit on bottom, when flow rate and weight on

bit are adjusted to drilling conditions.• Measure the standpipe pressure when the bit is lifted off bottom with the flow rate

being kept constant.• Calculate difference in standpipe pressure.• If a diamond bit is in use, reduce the above value by the pressure drop at the bit.• Read the reactive torque values for the calculated differential pressure from tables.• Obtain the corresponding torsion angle per unit length for the drill pipe in use from the

graphs on the facing page.

After orientation by single shot measurement, the string has to be aligned to produce the required bore hole direction. To do so, the above calculated reactive torque angle is considered as a right-hand angle in addition to the direction change. Having applied the accumulated angle of the string with the rotary table, the string should be raised and lowered several times over a 30 ft interval.

Once a few feet/metres of hole have been made with the new settings, the result will be checked and the drill pipe alignment adjusted in light of the actual results. This is the reason why the preliminary estimate is only required to an "order of magnitude" accuracy.



REACTIVE TORQUE CHARTS

0 1,500 3,000 4,500

180°

150°

120°

90°

60°

30°

0°

540°

450°

360°

270°

180°

90°

0 1 2 3 4 5 6 7Torque in kN-m

Torque in lbs-ft

Tors

iona

l ang

le fo

r 1,

000

m D

P

Tors

iona

l ang

le fo

r 1,

000

ft D

P

4-1/

2", 1

6.6

lbs/

ft5"

, 19.

5 lb

s/ft

4-1/

2", 2

0 lb

s/ft

4", 1

4 lb

s/ft

5-1/

2", 2

0.9

lbs/ft

0 375 750 1,125

180°

150°

120°

90°

60°

30°

0°

540°

450°

360°

270°

180°

90°

0 0.5 1.0 1.5 2.0Torque in kN-m

Torque in lbs-ft

Tors

iona

l ang

le fo

r 1,

000

m D

P

Tors

iona

l ang

le fo

r 1,

000

ft D

P

1,500

2-3/

8", 6

.7 lb

s/ft

2-7/

8", 1

0.4

lbs/

ft3-

1/2"

, 13.

3 lbs

/ft

3-1/2

", 15

.5 lbs

/ft


NA

VI-

DR

ILL

PE

RF

OR

MA

NC

E D

ATA

MIX

5:6

300-

600

180-

365

1,00

03,

000

520

10-2

030

4,80

083

016

-32

45M

1XL

5:6

300-

600

180-

365

2,00

06,

000

975

18-3

730

9,60

01,

560

29-6

045

M1A

DM

5:6

300-

600

65-1

251,

300

2,00

096

07-

1330

3,20

01,

540

10-2

045

*DD

SII

5:6

300-

600

180-

365

1,30

04,

000

600

11-2

3--

6,40

096

018

-37

--

*DD

S7:

850

0-70

026

0-37

090

04,

800

920

25-3

6--

7,70

01,

470

40-5

7--

M1C

5:6

250-

700

120-

340

1,60

05,

500

1,20

015

-43

308,

800

1,92

024

-68

55M

21:

225

0-80

025

0-80

090

05,

000

650

17-5

429

8,00

01,

040

27-8

755

MIX

5:6

400-

1,20

011

0-32

51,

200

5,00

01,

850

21-6

348

8,00

02,

960

34-1

0110

0M

1XL

5:6

400-

1,20

011

0-32

52,

100

9,50

03,

530

41-1

2048

15,2

005,

650

65-1

9210

0M

2PX

L2:

330

0-1,

000

180-

600

1,30

011

,000

1,95

037

-123

4817

,600

3120

59-1

9610

0M

1C5:

630

0-90

010

0-30

01,

000

5,00

01,

600

17-5

048

8,00

02,

560

27-8

010

0M

1P/H

F5:

660

0-1,

200

105-

210

1,30

04,

000

2,30

025

-51

486,

400

3,68

040

-81

100

M1A

DM

5:6

600-

1,20

055

-110

1,30

02,

000

2,20

013

-25

483,

200

3,52

020

-41

100

M2

1:2

300-

1,00

019

5-65

080

05,

000

1,00

020

-68

488,

000

1,60

033

-109

100

*DD

SII

7:8

5-85

015

0-25

580

02,

400

820

13-2

2--

3,80

01,

310

21-3

5--

*DD

SIII

7:8

5-85

015

0-25

51,

000

4,20

01,

420

22-3

8--

6,70

02,

270

36-6

1--

MIX

5:6

1,00

0-2,

500

90-2

201,

500

3,20

03,

650

34-8

410

15,

100

5,84

055

-135

170

M1X

L5:

61,

000-

2,50

090

-220

2,40

06,

000

6,85

065

-158

101

9,60

010

,960

103-

252

170

M2P

XL

2:3

700-

2,00

023

5-43

01,

400

8,00

03,

650

90-1

6410

112

,800

5,84

014

4-26

317

0M

1C5:

670

0-1,

800

100-

260

1,10

05,

000

3,80

040

-103

101

8,00

06,

080

64-1

6617

0M

1P7:

81,

000-

1,80

011

0-20

01,

200

6,00

05,

800

67-1

2110

19,

600

9,28

010

7-19

417

0M

1P/H

F7:

81,

300-

2,30

010

0-18

01,

700

5,00

06,

500

68-1

2310

18,

000

10,4

0010

9-19

617

0M

1AD

M7:

81,

300-

2,30

055

-95

1,40

02,

500

5,80

033

-58

101

4,00

09,

280

53-9

217

0M

21:

270

0-2,

000

190-

550

800

5,00

02,

500

50-1

4410

18,

000

4,00

080

-230

170

*DD

S7:

81,

000-

1,80

011

0-20

01,

200

3,00

02,

900

33-6

1--

4,60

04,

640

53-9

7--

Pow

erS

ectio

nLo

beco

nfig

.F

low

rat

e

l/min

Bit

spee

d

rpm

No

load

pres

sure

(mea

n Q

)kP

a

Ope

ratin

gD

iff.

pres

sure

kPa

Torq

ueN

-m

Pow

erou

tput

kWW

OB

kNW

OB

kN

Diff

.pr

essu

rekP

aTo

rque

N-m

Pow

erou

tput

kW

Tool

siz

e–

Bit

size

31/ 8

"–

31/ 2

"- 4

3 /4"

33/ 4

"41

/ 2"-

43 /4 "

33/ 4

"–

43/ 4

"- 5

7 /8"

43/ 4

"–

57/ 8

"- 7

7 /8"

43/ 4

"–

57/ 8

"- 6

1 /2"

63/ 4

"–

83/ 8

"- 9

7 /8"

Max

imum

SI U

NIT

S


M1C

5:6

1,20

0-2,

600

85-1

901,

300

4,00

06,

100

54-1

2115

56,

400

9,76

087

-194

300

M1P

7:8

1,50

0-2,

500

90-1

5090

06,

000

10,5

0099

-165

155

9,60

016

,800

158-

264

300

M1P

/HF

9:10

2,00

0-3,

400

90-1

502,

000

5,00

011

,500

108-

181

155

8,00

018

,400

173-

289

300

M1A

DM

7:8

2,00

0-3,

400

50-8

01,

500

2,50

010

,100

53-8

515

54,

000

16,1

6085

-135

300

M2

1:2

900-

2,60

015

5-45

080

04,

000

3,25

053

-153

155

6,40

05,

200

84-2

4530

0

M1X

L5:

62,

000-

4,00

080

-165

1,80

06,

000

14,6

0012

2-25

221

49,

600

23,3

6019

6-40

440

0M

1C5:

61,

500-

2,80

010

0-19

01,

000

5,50

09,

300

97-1

8521

48,

800

14,8

8015

6-29

640

0M

1P7:

81,

800-

3,00

080

-130

700

6,00

015

,000

126-

204

214

9,60

024

,000

201-

327

400

M1P

/HF

9:10

2,50

0-4,

200

80-1

301,

600

5,00

017

,000

142-

231

214

8,00

027

,200

228-

370

400

M1A

DM

7:8

2,50

0-4,

200

40-7

01,

300

2,50

015

,000

63-1

1021

44,

000

24,0

0010

1-17

640

0M

21:

21,

500-

3,00

020

0-40

090

06,

000

6,45

013

5-27

021

49,

600

10,3

2021

6-43

240

0

M1C

5:6

2,00

0-4,

300

80-1

701,

600

4,50

013

,200

111-

235

227

7,20

021

,120

177-

376

500

M1P

9:10

3,00

0-4,

800

70-1

101,

600

5,00

024

,000

176-

276

227

8,00

038

,400

281-

442

500

M2

1:2

2,00

0-4,

300

155-

330

800

4,00

07,

500

122-

259

227

6,40

012

,000

195-

415

500

Pow

erS

ectio

nLo

beco

nfig

.F

low

rat

e

l/min

Bit

spee

d

rpm

No

load

pres

sure

(mea

n Q

)kP

a

Ope

ratin

gD

iff.

pres

sure

kPa

Torq

ueN

-m

Pow

erou

tput

kWW

OB

kNW

OB

kN

Diff

.pr

essu

rekP

aTo

rque

N-m

Pow

erou

tput

kW

Tool

siz

e–

Bit

size

8" –91

/ 2"-

121 /

4"

91/ 2

"–

121 /

4"-

171 /

2"

111 /

4"–

16"-

26"

Max

imum

Do

g-l

eg c

apaa

bili

ties

The

dog

-leg

capa

abili

ties

of a

ssem

blie

s in

corp

orat

ing

the

abov

e m

otor

sec

tions

var

y w

ith th

e ho

le s

ize,

the

mot

or d

iam

eter

, the

mot

or ty

pe, t

he A

KO

set

ting,

the

stab

ilise

r co

nfig

urat

ion

and

the

drill

ing

para

met

ers.

The

fig

ures

in th

e ta

ble

alon

gsid

e ha

ve b

een

take

n fr

om B

HI's

Nav

i-Dril

l Mot

or H

andb

ook

(199

6) a

s a

guid

e to

the

rang

es a

vaila

ble

usin

g th

e st

anda

rd s

erie

s of

mot

or s

ectio

ns.

The

ser

vice

com

pany

sho

uld

be c

onta

cted

for

reco

mm

enda

tions

for

part

icul

ar c

ases

.

* M

otor

sec

tion

type

s D

DS

, DD

SII

and

DD

SIII

are

spe

cial

ised

mot

ors

used

for

drill

ing

shor

t rad

ius

build

-up

sect

ions

. T

hese

can

be

used

to d

rill s

ectio

ns w

ith a

rad

ius

of c

urva

ture

of 1

2 -

50 m

(1.

1 -

4.8

° pe

r m

etre

).

Tool

Dog

-leg

diam

eter

capa

bilit

y(

°/30

m)

31/ 8

"

3 -

4043

/ 4"

0.2

- 26

63/ 4

"

0 -

1991

/ 2"

0

- 9

.511

1 /4"

1

- 11


NA

VI-

DR

ILL

PE

RF

OR

MA

NC

E D

ATA

MIX

5:6

80-1

6018

0-36

514

543

538

513

-27

6769

562

021

-43

102

M1X

L5:

680

-160

180-

365

290

870

720

25-5

067

1,39

01,

150

39-8

010

2M

1AD

M5:

680

-160

65-1

2519

029

071

09-

1767

465

1,14

014

-27

102

*DD

SII

5:6

80-1

6018

0-36

519

058

044

015

-31

--93

070

024

-49

--

*DD

S7:

813

0-18

526

0-37

013

069

568

034

-48

--1,

110

1,09

054

-76

--

M1C

5:6

65-1

8512

0-34

023

080

088

520

-57

671,

280

1,42

032

-92

122

M2

1:2

65-2

1025

0-80

013

072

548

023

-73

651,

160

770

37-1

1712

2

MIX

5:6

105-

315

110-

325

175

725

1,36

529

-84

108

1,16

02,

180

46-1

3522

2M

1XL

5:6

105-

315

110-

325

305

1,38

02,

605

55-1

6110

82,

210

4,17

087

-258

222

M2P

XL

2:3

80-2

6518

0-60

019

01,

595

1,44

049

-165

108

2,55

02,

300

79-2

6322

2M

1C5:

680

-240

100-

300

145

725

1,18

022

-67

108

1,16

01,

890

36-1

0822

2M

1P/H

F5:

616

0-31

510

5-21

019

058

01,

695

34-6

810

893

02,

710

54-1

0822

2M

1AD

M5:

616

0-31

555

-110

190

290

1,62

517

-34

108

465

2,60

027

-54

222

M2

1:2

80-2

6519

5-65

011

572

574

027

-92

108

1,16

01,

180

44-1

4622

2

*DD

SII

7:8

130-

225

250-

255

115

350

600

17-2

9--

560

960

28-4

7--

*DD

SIII

7:8

130-

225

150-

255

145

610

1,05

030

-51

--97

51,

680

48-8

1--

MIX

5:6

265-

660

90-2

2022

046

52,

690

46-1

1322

874

54,

300

74-1

8038

2M

1XL

5:6

265-

660

90-2

2035

087

05,

050

87-2

1222

81,

390

8,08

013

8-33

838

2M

2PX

L2:

31,

85-5

3023

5-43

020

51,

160

2690

120-

220

228

1,85

54,

300

192-

352

382

M1C

5:6

185-

475

100-

260

160

725

2,80

553

-139

228

1,16

04,

490

85-2

2238

2M

1P7:

826

5-47

511

0-20

017

587

04,

280

90-1

6322

81,

390

6,85

014

3-26

138

2M

1P/H

F7:

834

5-61

010

0-18

024

572

54,

795

91-1

6422

81,

160

7,67

014

6-26

338

2M

1AD

M7:

834

5-61

055

-95

205

365

4,28

045

-77

228

585

6,85

072

-124

382

M2

1:2

185-

530

190-

550

115

725

1,84

567

-193

228

1,16

02,

950

107-

309

382

*DD

S7:

826

5-47

511

0-20

017

543

52,

140

45-8

1--

695

3,42

072

-130

--

Pow

erS

ectio

nLo

beco

nfig

.F

low

rat

e

gals

/min

Bit

spee

d

rpm

No

load

pres

sure

(mea

n Q

)ps

i

Ope

ratin

gD

iff.

pres

sure

psi

Torq

uelb

s-ft

Pow

erou

tput

HP

WO

Blb

s x

103

WO

Blb

s x

103

Diff

.pr

essu

reps

iTo

rque

lbs-

ft

Pow

erou

tput

HP

Tool

siz

e–

Bit

size

31/ 8

"–

31/ 2

"- 4

3 /4"

33/ 4

"41

/ 2"-

43 /4 "

33/ 4

"–

43/ 4

"- 5

7 /8"

43/ 4

"–

57/ 8

"- 7

7 /8"

43/ 4

"–

57/ 8

"- 6

1 /2"

63/ 4

"–

83/ 8

"- 9

7 /8"

Max

imum

OIL

FIE

LD U

NIT

S


M1C

5:6

315-

685

85-1

9019

058

04,

500

73-1

6334

893

07,

200

117-

260

674

M1P

7:8

395-

660

90-1

5013

087

07,

745

133-

221

348

1,39

012

,390

212-

354

674

M1P

/HF

9:10

530-

900

90-1

5029

072

58,

480

145-

242

348

1,16

013

,570

233-

388

674

M1A

DM

7:8

530-

900

50-8

022

036

57,

450

71-1

1334

858

511

,920

113-

182

674

M2

1:2

240-

685

155-

450

115

580

2,39

571

-205

348

930

3,83

011

3-32

867

4

M1X

L5:

653

0-1,

055

80-1

6526

087

010

,770

164-

338

488

1,39

017

,230

262-

541

894

M1C

5:6

395-

740

100-

190

145

800

6,86

013

1-24

848

81,

280

10,9

8020

9-39

789

4M

1P7:

847

5-79

580

-130

100

870

11,0

6516

9-27

448

81,

390

17,7

0027

0-43

889

4M

1P/H

F9:

1066

0-1,

110

80-1

3023

072

512

,540

191-

310

488

1,16

020

,060

306-

497

894

M1A

DM

7:8

660-

1,11

040

-70

190

365

11,0

6584

-147

488

585

17,7

0013

5-23

689

4M

21:

239

5-79

520

0-40

013

087

04,

755

181-

362

488

1,39

07,

610

290-

580

894

M1C

5:6

530-

1,13

580

-170

230

655

9,73

514

8-31

551

01,

050

15,5

8023

7-50

411

24M

1P9:

1079

5-1,

270

70-1

1023

072

517

,700

236-

371

510

1,16

028

,320

377-

593

1124

M2

1:2

530-

1,13

515

5-33

011

558

05,

530

163-

347

510

930

8,85

026

1-55

611

24

Pow

erS

ectio

nLo

beco

nfig

.F

low

rat

e

gals

/min

Bit

spee

d

rpm

No

load

pres

sure

(mea

n Q

)ps

i

Ope

ratin

gD

iff.

pres

sure

psi

Torq

uelb

s-ft

Pow

erou

tput

HP

WO

Blb

s x

103

WO

Blb

s x

103

Diff

.pr

essu

reps

iTo

rque

lbs-

ft

Pow

erou

tput

HP

Tool

siz

e–

Bit

size

8" –91

/ 2"-

121 /

4"

91/ 2

"–

121 /

4"-

171 /

2"

111 /

4"–

16"-

26"

Max

imum

Do

g-l

eg c

apab

iliti

esT

he d

og-le

g ca

pabi

litie

s of

ass

embl

ies

inco

rpor

atin

g th

e ab

ove

mot

or s

ectio

ns v

ary

with

the

hole

siz

e, th

e m

otor

di

amet

er, t

he m

otor

type

, the

AK

O s

ettin

g, th

e st

abili

ser

conf

igur

atio

n an

d th

e dr

illin

g pa

ram

eter

s. T

he fi

gure

s in

th

e ta

ble

alon

gsid

e ha

ve b

een

take

n fr

om th

e B

HI's

Nav

i-Dril

l Mot

or H

andb

ook

(199

6) a

s a

guid

e to

the

rang

es

avai

labl

e us

ing

the

stan

dard

ser

ies

of m

otor

sec

tions

. T

he s

ervi

ce c

ompa

ny s

houl

d be

con

tact

ed fo

r re

com

men

datio

ns fo

r pa

rtic

ular

cas

es.

* M

otor

sec

tion

type

s D

DS

, DD

SII

and

DD

SIII

are

spe

cial

ised

mot

ors

used

for

drill

ing

shor

t rad

ius

build

-up

sect

ions

. T

hese

can

be

used

to d

rill s

ectio

ns w

ith a

rad

ius

of c

urva

ture

of 4

0 -

165

ft (0

.35

- 1.

45 °

per

foot

).

Tool

Dog

-leg

diam

eter

capa

bilit

y(

°/10

0 ft)

31/ 8

"

3 -

4043

/ 4"

0.2

- 26

63/ 4

"

0 -

1991

/ 2"

0

- 9

.511

1 /4"

1

- 11


Turb

odril

ls fo

r st

raig

ht h

oles

Turb

odril

ls fo

r de

viat

ed h

oles

Nom

inal

siz

e5"

71/ 4

"71

/ 4"

91/ 2

"91

/ 2"

33/ 8

"43

/ 4"

43/ 4

"65

/ 8"

91/ 2

"91

/ 2"

Type

T2

T2

T3

T2

T3

FB

SF

BS

MK

2F

BS

SB

SS

BS

Sta

ndar

dH

igh

flow

OD

5"73

/ 8"

73/ 8

"91

7 /32

"91

7 /32

"33

/ 8"

43/ 4

"43

/ 4"

65/ 8

"91

/ 2"

91/ 2

"B

it si

ze55

/ 8"-

63/ 4

"81

/ 2"-

95/ 8

"81

/ 2"-

95/ 8

"11

"-15

"11

"-15

"33

/ 4"-

53/ 8

"55

/ 8"-

63/ 4

"55

/ 8"-

63/ 4

"75

/ 8"-

97/ 8

"12

1 /4"

-171

/ 2"

121 /

4"-1

71/ 2

"S

peed

ran

ge (

rpm

)80

0-1,

800

700-

1,40

070

0-1,

400

400-

1000

300-

700

300-

700

Ben

t hou

sing

ang

le :

Sta

ndar

d1°

1°1°

1°3 /

4°3 /

4°A

vaila

ble

11/ 4

°, 1

1 /2°

3 /

4°,1

1 /4°

1 /2°

,1°

1 /2°

,1°

Dog

-leg

angl

e ca

pabi

lity

with

sta

ndar

d be

nt h

ousi

ng (

°/10

0ft -

°/3

0 m

)13

810

-12

6-8

44

Nom

inal

flow

rat

e(g

pm)

160

475

475

650

650

100

160

200

475

650

650

(l/se

c)10

3030

4141

6.3

1012

.630

4141

Pre

ssur

e dr

op(p

si)

1,43

51,

510

2,15

01,

525

2,21

01,

537

1,41

51,

598

1,87

5(k

Pa)

9,90

010

,400

14,8

0010

,500

15,2

0010

,600

9,80

011

,000

12,9

00P

ower

(HP

)78

243

365

379

568

5174

104

280

520

520

(kW

)58

181

272

283

424

3855

7820

938

838

8To

rque Max

imum

drlg

(lbs-

ft)

1,47

52,

460

5,00

05,

000

(N-m

)2,

000

3,35

06,

780

6,78

0 S

talli

ng(lb

s-ft)

32

586

0(N

-m)

440

1,16

0

NE

YR

FO

R T

UR

BIN

E D

ATA

Not

e :

The

pre

ssur

e dr

op, p

ower

and

torq

ue fi

gure

s gi

ven

abov

e ar

e va

lid fo

r th

e no

min

al fl

ow r

ate,

an

d fo

r a

drill

ing

fluid

den

sity

of 0

.52

psi/f

t or

11.7

5 kP

a/m


No

tes

on

tab

le*

Whi

chev

er is

app

licab

le**

If a

wire

line

surv

ey is

not

mad

e fr

om s

urfa

ce, i

t sho

uld

over

lap

at le

ast 1

000

ft (3

00 m

) of

the

prev

ious

su

rvey

. M

agne

tic s

urve

ys s

houl

d be

take

n in

to th

e la

st c

asin

g sh

oe.

1.IN

(F

IND

S o

r R

IGS

) to

rep

lace

GM

S if

ava

ilabl

e.2.

Whe

n co

nduc

tors

hav

e be

en b

atch

inst

alle

d, a

ll sh

ould

be

clea

ned

out a

nd s

urve

yed

prio

r to

dril

ling

the

first

wel

l.3.

Can

use

MW

D a

nd E

MS

whe

n th

ere

are

prob

lem

s of

get

ting

gyro

dow

n. R

un E

MS

prio

r to

run

ning

ca

sing

.4.

EM

S o

r D

ip M

eter

sur

vey

allo

wed

bel

ow th

e to

p of

the

low

est h

ydro

carb

on b

earin

g zo

ne (

in o

pen

hole

).5.

In h

ot w

ells

>12

0°C

(25

0°F

) th

ere

may

not

be

enou

gh r

oom

for

the

gyro

hea

t shi

eld.

Run

EM

S p

rior

to

runn

ing

casi

ng.

6.E

SS

is p

refe

rred

but

MS

S m

ay b

e us

ed.

7.G

MS

/EM

S m

ust b

e ta

ken

prio

r to

ent

erin

g an

y po

tent

ial z

one

that

cou

ld b

low

out

.8.

GM

S/E

MS

may

be

omitt

ed w

here

it is

pro

ven

that

the

wel

l will

not

pen

etra

te a

pot

entia

l blo

w o

ut z

one

in th

e ne

xt o

pen

hole

sec

tion

and

(1)

ther

e is

a G

MS

/EM

S in

th

e pr

evio

us s

ectio

n an

d (2

) th

e op

en h

ole

mag

netic

sur

vey

of th

at s

ectio

n is

goo

d.9.

GM

S s

urve

ys s

houl

d be

eve

ry 1

00 ft

(25

m),

but

this

sho

uld

be r

educ

ed to

eve

ry 5

0 ft

(15m

) th

roug

h se

ctio

ns w

ith d

ogle

gs o

ver

2.5°

/100

ft (

2.5°

/30m

).10

.Sur

vey

ever

y st

and

(90

ft) w

hen

usin

g M

WD

. Int

erva

l may

be

incr

ease

d to

300

ft (

100

m)

whe

n us

ing

an E

SS

.11

.IN

(R

IGS

) m

ay b

e co

nsid

ered

in s

peci

al c

ases

of h

igh

accu

racy

req

uire

men

ts.

12.E

MS

to b

e ta

ken

whe

n M

WD

/ST

/ES

S s

urve

ys h

ave

ques

tiona

ble

qual

ity.

13.W

here

crit

eria

for

relie

f wel

l dril

ling

have

bee

n re

laxe

d, in

clin

atio

n on

ly s

urve

ys m

ay b

e co

nsid

ered

.14

.Sur

vey

ever

y st

and

(90

ft) w

hen

usin

g E

MS

, but

this

sho

uld

be r

educ

ed to

eve

ry s

ingl

e (3

0 ft)

thro

ugh

sect

ions

with

dog

legs

ove

r 2.

5°/1

00 ft

(2.

5°/3

0 m

).

FR

EQ

UE

NC

Y A

ND

TY

PE

S O

F S

UR

VE

YS

TO

BE

TA

KE

N

GS

S=

Gyr

o S

ingl

e S

hot (

Sur

face

rea

d-ou

t pre

ferr

ed)

MW

D=

Mea

sure

men

t Whi

le D

rillin

gS

T=

Ste

erin

g To

olE

SS

=E

lect

roni

c M

agne

tic S

ingl

e S

hot

MS

S=

Mag

netic

Sin

gle

Sho

t (E

SS

pre

ferr

ed)

DIP

=D

ip M

eter

Log

(w

hich

giv

es g

ood

surv

ey r

esul

ts)

EM

S=

Ele

ctro

nic

Mag

netic

Mul

ti-S

hot

GM

S=

Gyr

o M

ulti-

Sho

t (N

orth

See

king

Gyr

o pr

efer

red)

IN=

Iner

tial N

avig

atio

nM

MS

=M

agne

tic M

ulti-

Sho

t (E

MS

pre

ferr

ed)

Pla

tform

/Clu

ster

/Tem

plat

e W

ells

and

Oth

er W

ells

Isol

ated

ver

tical

wel

lsD

urin

g D

rillin

gVer

ifica

tion

Sur

vey

Dur

ing

Dril

ling

Ver

ifica

tion

Sur

vey

Dur

ing

Dril

ling

Ver

ifica

tion

Sur

vey

Type

of

Sur

vey

Type

of

Sur

vey

Type

of

Sur

vey

Type

of

Sur

vey

Sur

vey

Sur

vey

Inte

rval

**S

urve

yIn

terv

al**

Sur

vey

Inte

rval

**S

urve

yIn

terv

al**

Sto

ve P

ipe/

Fou

ndat

ion

Pile

*N

one

Non

eN

one

Non

e

Mar

ine

Con

duct

or*

GS

S30

ft/

GM

S25

ftE

SS

at s

ectio

nG

MS

/EM

S50

ft10

m1,

28m

6,13

TD

1,7,

8,14

15 m

Con

duct

or S

trin

g (2

0/18

5 /8"

Cas

ing)

GS

S/M

WD

/ST

/ES

S30

-90

ftG

MS

100

ftM

WD

/ST

/ES

S30

0 ft

GM

S/E

MS

100

ft6,

10,1

210

-30

m1,

925

m6,

10,1

2,13

100

m1,

7,8,

9,14

25 m

Sur

face

Str

ing

(133

/ 8"

Cas

ing)

MW

D/S

T/E

SS

30-9

0 ft

GM

S10

0 ft

MW

D/S

T/E

SS

300

ftG

MS

/EM

S10

0 ft

6,10

,12

10-3

0 m

1,9

25 m

6,10

,12,

1310

0 m

1,7,

8,9,

1425

m

Inte

rmed

iate

Str

ing

(95 /

8" c

asin

g)M

WD

/ST

/ES

S30

-90

ftG

MS

100

ftM

WD

/ST

/ES

S30

0 ft

GM

S/E

MS

100

ft6,

10,1

210

-30

m1,

3,9

25 m

6,10

,12,

1310

0 m

1,7,

9,14

25 m

Pro

duct

ion

Str

ing

(7"

Cas

ing/

Line

r)M

WD

/ST

/ES

S30

-90

ftG

MS

100

ft M

WD

/ST

/ES

S30

0 ft

GM

S/E

MS

100

ft6,

10,1

210

-30

m4,

9,11

25 m

6,10

,12

100

m4,

9,14

25 m

Pro

duct

ion

Line

r (4

1 /2"

Lin

er)

ES

S/E

MS

as r

equi

red

GM

S/E

MS

100

ftE

SS

/EM

S/D

IP30

0 ft

EM

S/D

IP10

0 ft

4,6

4,5,

925

m4,

610

0 m

425

m


Totcos are normally run by the driller. The pre-survey checklist and running procedure are given below. (When using a magnetic single shot tool for inclination only surveys follow the running procedure for MSS.)1. Check that the instrument landing assembly will seat correctly in the landing ring

(Totco ring), and not jam or land eccentrically.2. Install the landing ring in the proper place when making up the BHA.3. Avoid landing the instrument directly on top of bit, mud motor or turbine. The

instrument could get stuck and furthermore make circulation impossible.4. Check that the fishing tool will fit over the fishing neck.5. Check that the instrument will pass the BHA above the landing ring and not hang up

(e.g. in the jar).6. Check that the instrument kit box is complete and that the angle units have been

checked in the workshop before delivery to the well site. Check that no angle unit has been used more than 25 times after calibration.

7. Use sinker bars if the drilling fluid has a high density and/or is viscous.8. Before surveying circulate sufficiently to avoid a back flow of cuttings into the BHA.9. Estimate the time lapse. This should be equal to the sum of the times required to:

- mount the instrument in the barrel- run the instrument through the drill string- provide a safety margin of a few minutes (3-5 minutes) in case of any delays.

PRE-SURVEY CHECKLISTS

Totcos

Magnetic Single Shots

An OU representative should ensure that the following is carried out :1.Check that the required length of NMDC is available.2.Check that the instrument landing assembly will seat correctly in the landing ring

(TOTCO ring), and will not jam or land eccentrically.3.Check whether the instrument is to be top or bottom landed or used with a mule shoe.4. Install the landing ring in the proper place when making up the BHA. Avoid landing the

instrument directly on top of bit, mud motor or turbine. The instrument could get stuck and furthermore make it impossible to circulate.

5.Check that the instrument will pass the rest of the BHA above the landing ring and not hang up (e.g. in the jar).

6.Check that the instrument kit box is complete and that the angle units have been checked in the workshop before delivery to the well site. Check that no angle unit has been used more than 25 times after calibration.Specifically check that the kit box includes:• two angle units of each range, which should be used alternately• batteries specified for the instrument• film discs• developing chemicalsand ensure that the film is kept dry before the survey is run.

7.Check the angle unit in the field test stand. Ensure that the angle unit inclination readings agree with the field test stand inclinations.


The directional surveys at consecutive stations (at AHD1 and AHD2) measure values of A1, A2, I1 and I2. These values are then substituted into the equations given below to yield values of dog-leg angle, ∆N, ∆E, ∆TVD and ∆PHD.

cos DL = cos (I2 - I1) - sin I1.sin I2(1 - cos (A2 - A1))

DLS = DL x characteristic length∆AHD

∆N = ∆AHD (sin I1.cos A1 + sin I2.cos A2).RF2

∆E = ∆AHD (sin I1.sin A1 + sin I2.sin A2).RF2

∆TVD = ∆AHD (cos I1 + cos I2).RF2

∆PHD = ∆N.cos At + ∆E.sin At

Where: AHD/TVD = Along hole / True vertical depths

RF = Ratio Factor = 180 x 2 x tan DL π.DL 2DL = Dog-leg angle in degrees

DLS = Dog-leg severity in degrees per characteristic length (usually °/100 ft or °/30 m)

At = target AzimuthPHD = Projected horizontal distance (in direction At)

MINIMUM CURVATURE METHOD EQUATIONS


BASIC VECTOR DIAGRAM

I1, I2, A1, A2 and DL are as given on the previous pageTFS = Tool Face Setting angle, positive in the sense shown to give increasing

azimuth

Knowing the value of any three of the sides/angles of the triangle allows the other three to be calculated using the standard equations :

If two angles and a side are known : a = b = csin A sin B SinC

If two sides and the included angle are known : a2 = b2 + c2 - 2bc.cos A etc.

If two sides and a non-included angle are known : a = c.cos B ± b2 - c2.sin2B or a = b.cos C ± c2 - b2.sin2C

Note : For maximum change in Azimuth the vector representing A2 is tangent to the circle whose radius represents DL.

A1

A2

∆AzTFS

I1

I2

DL

A1

A2

∆AzTFS

I1

I2

DL

Date post:	24-Oct-2014
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