10.1 RotaryBHA
Before the advent of MWD tools and/or steerable motors, the “classic" approach to a typical DD job (e.g. kickoff point in 17 1/2" hole) was as follows:
1. One or more rotary BHAs (typically in 36" and 26" hole sizes) were used to drill the top hole section. A 17-1/2" rotary BHA was used to drill out the 20" casing shoe and drill down to the kickoff point. The well would normally be planned to have sufficient open hole from the 20" casing to the kickoff point to eliminate the possibility of magnetic interference when kicking off.
2. A bit (17 1/2" or smaller) / mud motor / bent sub combination was RIH. Magnetic (or, where necessary gyro) single-shot surveys were taken at short intervals. Hole inclination was built to 8° in hard formation and typically +/- 15° in softer formation. Having achieved the required hole azimuth (lead angle taken into account), this BHA was then POOH.
3. A rotary build BHA was RIH. The inclination was built up close to the required maximum angle on the well plan. By controlling the drilling parameters (particularly WOB and RPM) every effort was made to hold the well azimuth on course. This BHA was then POOH.
4. A rotary lockup BHA was then RIH. In a slant well, the normal objective was to hold the inclination until the next casing point. Small variations in inclination were permissible. Again, drilling parameters were varied as deemed necessary. Because the BHA was “stiff”, in theory it gave the best possibility of keeping the well azimuth within the prescribed limits.
From the above scenario, it is clear that several trips were required for BHA changes (even assuming that the well behaved perfectly from a DD standpoint). When directional problems occurred (unpredictable BHA behavior), several days were often lost. Even worse, a "crooked hole" occasionally resulted.
MWD surveys meant that the DD had more control over survey intervals. It became common to survey every single in the kickoff and buildup phases. Even better, in soft formation it became possible to build up to the required maximum angle (even up to +/- 50° inclination) with the bit/mud motor/ bent sub/ MWD combination, provided hole friction did not become excessive. This eliminated one round trip.
The arrival of steerable motors meant that a complete hole phase became possible using a single BHA which included a bit steerable motor/ string stabilizer/ MWD combination. BHAs of this type are covered in Chapter 11.

The significant extra cost incurred from using the steerable motor was counteracted by the savings in trip time and the rig convenience and reduced wear on the drillstring.
The comparison of the steerable and “classic" BHAs, however, is more complex than the above. In certain areas, steerable BHAs are indeed the most cost-effective for the client. However, there are also many areas where the conventional approach is actually cheaper. In addition, the hole condition is usually better (less friction) where more than one round trip is made. Case studies which compare the two types of BHA (conventional rotary versus steerable) have been made for DSE projects. They illustrate the above.
Which approach do we recommend to the client? Often the client has a preference for one or the other. A cost/benefit analysis should be made where possible. Use of steerable motors means more revenue for ANADRILL than use of straight motor/ bent sub. However, ultimately the cost to the client is the determining factor. Finally, it is common practice to have conventional mud motors and bent subs on rigs where steerable motors are used. They are there as a backup. Their rental cost is relatively cheap.
The arrival of surface-adjustable and downhole-adjustable bent housings has made steerable motors more versatile. The DD is no longer “caught-out" if the desired dog-leg severity is not achieved by a particular bent housing. However, there will continue to be applications where the straight-housing motor/ bent sub will be preferred on cost grounds e.g. sidetracks.
10.1.1 Rotary BHA Theory
Once the initial deflection and direction of the well (i.e. the kickoff) has been achieved by the bit/ mud motor/ bent sub, the remainder of the well (apart from correction runs) is drilled using conventional rotary drilling techniques.
10.1.1.1Principles of the Rotary BHA
The BHA affects the wellbore trajectory. The design of BHA can vary from very simple (bit, drill collars, drillpipe) to a complicated hookup (bit, shock sub, roller reamers, stabilizers, non-magnetic drill collars, steel drill collars, crossover subs, extension subs, jars, heavy weight drillpipe and drillpipe). Figure 10-1 illustrates the two extremes.
Slick B.H.A.
Bit
Regular Drill Pipe
Heavy Weight Drill Pipe(s)
Drilling Jars
Smaller Drill Collars
Crossover Sub to Smaller Drill Collars
Measurement While Drilling (MWD) Tool
Stabilizer
Nonmagnetic Drill Collar
Roller Reamer Shock Sub
Near Bit Stabilizer Packed-Hole B.H.A.
Drillpipe
Collars
Figure 10-1 Slick and packed hole BHAs
10.1.1.3Stiffness

10.1.1.2Side Force
All BHAs cause a side force at the bit (Figure 10-2) that leads to an increase in hole inclination (positive side force - Fulcrum effect), no change in inclination (zero net side force - Lockup BHA) or a drop in inclination (negative side force - Pendulum effect). In addition, changes in hole direction (bitwalk) may be either minimized or increased by specific rotary BHAs and drilling parameters.
Build Force or Positive Side Force
Figure 10-2
BHA side forces
Most drilling components used in a BHA (e.g. drill collars) can be treated as hollow cylinders (Figure 10-3). Their stiffness can be easily calculated.
Inside Diameter of Drill Collar
Figure 10-3 BHA as a hollow cylinder
WOB
WOB
a
Negative Side Force or Pendulum Force
Outside Diameter of Drill Collar
ID
OD
Moment of Inertia for Round Drill Collars

Stiffness Coefficient = E I E = Young’s Modulus (lb/in2)
where I = Moment of Inertia (in4)
Moment of Inertia I = π ( OD4 - ID4) /64
where OD = outside diameter ID = inside diameter.
Stiffness coefficient is a measure of component rigidity. A table of Young’s Modulus values for various materials is given in Table 10-1. Note how limber aluminum is and how rigid tungsten is compared to alloy steel, e.g., determine stiffness of a steel drill collar having:
a. OD = 8" and ID = 2-13/16" Solution
E I = 30.0 x 106 x π • (8.04 -2.81254) / 64 = 5.9397 x 109
b. OD = 7” and ID = 2-13/16" Solution
E I =30.0 x 106 x π • (7.04-2.81254) / 64 = 3.444 x 109
In this case, a reduction in O.D. of 12.5% (for the same I.D.) results in a reduction in stiffness of 42%!
It is important to take drill collar stiffness into account when designing BHAs. Where an MWD tool is to be used close to the bit, it is absolutely essential to know the stiffness of the MWD collar. Otherwise, dogleg severity achieved may differ greatly from what was expected.

Material
Alloy steel Aluminum
Monel Stainless steel Tungsten carbide Tungsten
Used In
Drill pipe Drill collars Drill pipe Drill collars Non-magnetic collars Non-magnetic collars Bit inserts
Collars
lb/in2
30.0 X106 30.0 x 106 10.5 x 106 10.5 x 106 26.0 x 106 28.0 x 106 87.0 x 106 51.5 x 106
Table 10-1 Modulus of elasticity
WOB
H = Negative Side Force
where:
L = BC = Wc = a =
H = (Wc.L.BC.SINa)/2
Tangency length Buoyancy Factor Weight of collars in air (lbs/ft) Inclination
H
Increased WOB
H- , H

10.1.2 Slick Assembly
The simplest type of BHA (bit, drill collars, drillpipe) is shown in Figure 10-4.
Tangency Point
L W W-,W
Tangency Point
Figure 10-4 Pendulum force and weight on bit
With zero weight on bit, a negative side force (pendulum force) only applies. The maximum pendulum force at the bit is given by:
The greater the hole inclination, the higher the pendulum force.
If we apply an axial load (weight on bit), a positive (bending) force is introduced. The tangency point moves closer to the bit. The pendulum force is thus reduced. A condition of zero net side force is achieved at some point.
If we use stiffer drill collars, a larger pendulum force results. A higher weight on bit must be used to achieve a balanced condition. It may not even be possible.
It is obvious that the uncertainty (lack of control) when using a slick assembly leads to unpredictable results. Thus, this type of BHA is not used in deviated wells.
10.1.3 Single stabilizer BHAs
An easy way to control the tangency point is to insert a stabilizer in the BHA (Figure 10- 5). If the stabilizer is far enough back from the bit, it has no effect on BHA behavior. However, if the stabilizer is moved closer to the bit, the tangency point changes. The collar(s) between the bit and stabilizer bend when a certain weight on bit is applied. A point is reached where maximum negative (pendulum) side force occurs. Moving the stabilizer closer to the bit reduces the pendulum force.

L-,L
Bottom Hole Assemblies
Eventually, a point is reached where zero side force occurs. Moving the stabilizer further down gives a positive side force. The collar directly above the stabilizer bends when weight is applied. The stabilizer forces the bit towards the high side of the hole. This is called the fulcrum effect. Increases in weight on bit (up to a certain point) lead to increased buildup rate.
2
M
1
L
L
=
Tangency
M = Moment of Inertia
H
WOB
Figure 10-5
Single stabilizer BHA
The more limber the collar directly above the near-bit stabilizer, the greater the buildup rate. The smaller the O.D. of the collar directly above the near-bit, the closer to the bit the contact point becomes. Thus, a higher positive side force is achieved.
Single-stabilizer buildup BHAs are not normally used. Under no circumstances should a single stabilizer be run if, later in the hole, multi-stabilizer BHAs are to be run. More predictable BHA behavior and better hole condition results from using two or more stabilizers in every BHA.
10.1.4 Two stabilizer BHAs
The simplest multi-stabilizer BHA has a near-bit stabilizer (3’-6’ from the bit to the leading edge of the stabilizer blade) and a second stabilizer at some distance above this (Figure 10-6).
L
L3
L2
1
Tangency
M , M = Moments of Inertia 12
H
WOB
Figure 10-6
Two stabilizer BHA
For a given weight on bit, the distance from bit to first stabilizer (L1) and between the stabilizers (L2) determines the tangency point.
If tangency occurs between the bit and the bottom stabilizer, negative side force results (Figure 10-7).
Figure 10-7 Negative side force
90 ft.
70 ft.
50 ft.
30 ft.
S.F=-171 lb S.F=-249 lb S.F=-295 lb S.F=-210 lb

M1
M2
Bottom Hole Assemblies
A comparison of side force values for a single-stabilizer pendulum BHA versus a two-stabilizer pendulum BHA is seen in Figure 10-8. The second stabilizer increases the negative side force by reducing the effect of the positive building force.
Figure 10-8 Comparison of sideforces on single and two stabilizer BHAs
Figure 10-9 shows a two-stabilizer 90’ buildup BHA in which tangency occurs between the two stabilizers. Various bit and collar sizes are shown, together with the bit side forces achieved for WOB = 30,000 lbs. in each case.
Figure 10-9 Buildup BHA using two stabilizers.
Figure 10-10 shows the effect of increasing weight on bit. In practice, weight on bit is one of the most important ways the DD has of controlling buildup rate.
-400
-500
-600
-700
10 20 30 40 50 60 Weight on Bit, 1000 lb
60'
60' 30'
8" 7" 6" Collars Collars Collars
12-1/4" 9-7/8" 8-1/2"
Bit S.F.=814 lb S.F.=1521 lb S.F.=2587 lb S.F.=3343 lb
9-1/2" Collars
14-3/4"
Bit Bit Bit

70 ft
S.F.=855 lb S.F.=962 lb S.F.=1,002 lb 20,000 lb WOB 30,000 lb WOB 40,000 lb WOB
Figure 10-10 Effect of WOB increase on sideforce.
Reaming in soft formation (and flow rate) has a significant effect.
10.1.5 Multi-stabilizer BHAs
Addition of a third stabilizer at 30’ above the original top stabilizer has a significant effect on the response of a building BHA. Figure 10-11 is a plot of inclination versus side force at the bit for three 2-stabilizer BHAs. Figure 10-12 shows how the use of a third stabilizer increases the side force.
12.25" hole, 10-lb/gal mud 2.25" x 8" collars 25,000 lb collars
10,000
9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000
0 -500
90' 300'
60' 300'
45' 300'
0 10 20 30 40 50 60
Inclination, degrees
Figure 10-11 Inclination v sideforce for 3 BHAs

Bit Side Force, lb
2,800
2,600 2,400 2,200 2,000 1,800 1,600 1,400 1,200 1,000
800
12.25" hole, 10-lb/gal mud 2.25" x 8" collars 10
̊ inclination
60' 30' 300'
60' 60' 300'
45' 30' 300'
45'
60' 300'
0 10 20 30 40 50 60
Inclination, degrees
Figure 10-12
Increase of side force with addition of one stabilizer
In lock-up BHAs, use of the third stabilizer is essential. Otherwise, BHA behavior is erratic and unpredictable.
However, in drop-off (pendulum) BHAs, two-stabilizer BHAs are normally sufficient. A third stabilizer would have negligible effect in most cases.
Unless absolutely necessary (e.g. differential sticking problems), it is advisable to limit the number of stabilizers in any BHA to three. It helps keep rotary torque within acceptable limits and reduces mechanical wear on the hole. This is the approach in most locations worldwide.
10.1.5.1Undergauge Near-bit Stabilizer
If the near-bit stabilizer is undergauge (Figure 10-13), a loss of bit side force results. With a buildup BHA, rate of buildup is thus reduced. With a lockup BHA, a drop in inclination results.
The more undergauge, the greater the effect. In drop-off BHAs, use of an undergauge near-bit stabilizer is recommended (where economics permit) in "S" wells at the start of the drop-off.

Bit Side Force, lb
FG
30'
FG
30'
UG
Figure 10-13 10.1.5.2Undergauge Second Stabilizer
FG
30'
FG 10' UG
Undergauge near bit stabilizer
If the second stabilizer is undergauge (Figure 10-14), it becomes easier to get a tangency point below it. It becomes easier to build angle. The more undergauge, the greater the effect.
FG
30'
UG
30'
FG
Figure 10-14
FG
30'
UG 10' FG
Undergauge second stabilizer

In holding (locked) BHAs, an undergauge second stabilizer is usually deliberately included in the BHA. The objective is to reach a condition of zero net side force at the bit.
10.1.5.3Hole Washout
In soft formations, hole erosion occurs due to high annular velocities (Figure 10-15). Attempts at holding or building inclination are more difficult (impossible to keep sufficient weight on bit).
In very soft formation, it may be necessary to use a lower flow rate while drilling but wash through each stand/single at full flow rate before making the connection. If this does not solve the problem, a round trip for a more limber bottom collar ("gilligan" BHA) may be necessary. If this is not acceptable, a motor run may be required. It’s important for the DD to ensure he is not so far behind the program" due to slow buildup rate that a plug back and sidetrack is required.
Hole Diameter Side Force at D StabilizerF 3
1
Static Assembly
Hole Diameter D2
Well Bore Size Increased by Stabilizer Cutting
Dynamic Drilling Assembly
Initial Gauge Hole
Side Force at Hole StabilizerF 2
Diameter
D 1 Side Force While Drilling Causes
SideForceat EllipticalHole Bit F 1
Axial Weight
D1
Top View
Hole Diameter D1
Net Side Force Drcreases
D
2
Figure 10-15 Effect of hole washout on side force
Sometimes it may be necessary to drill a pilot hole first and follow up with a hole opener/under-reamer. Let us examine typical BHAs designed to build, hold or drop. It is important to note that these are only guidelines. Experience in a particular field/area will help the DD in “fine-tuning" the BHA.

Figure 10-16

10.1.6 BHAs for building Inclination
Figure 10-16 shows examples of commonly used BHAs for building inclination. Rates of build of the order of 5°/100' and higher are possible with BHA No. 9, depending on the geology, inclination, hole diameter, collar diameter and drilling parameters.
Highest Building Response
(9) (8) (7) (6) (5) (4) (3) (2) (1)
90' 30' 90'
50'-75' 30'
50'-75' 30'-50' 30'
30' 30' UG
30' 30' 30'
BHAs for building inclination
BHA No. 3 is used as a slight-to-medium building assembly, depending on how much undergauge the middle stabilizer is and how responsive to weight the BHA is. For any buildup BHA, the near-bit stabilizer has to be close to full gauge. The smaller the hole size, the more critical this becomes.
The rate of increase in inclination (buildup rate, in °/100') is very important. The safe maximum is about 5°/100'). If the rate of curvature of the wellbore is high and it occurs at a shallow depth, key seats may form in the curve as we drill ahead. If the curve is cased, the casing may become worn through as the lower part of the hole is drilled. This wear is caused by the pipe rotating in tension past the area of high curvature (Chapter 13). Several clients will set a dogleg severity maximum of 3°/100' (or even less).
It's important to be aware of the client's acceptable limit for buildup rate. The effective stiffness of a drill collar increases as RPM is increased. This leads to a reduced buildup rate.
As hole inclination increases, it becomes easier to build angle. Thus, where MWD is available, it is advisable to survey every single during the buildup phase. This allows the DD to avoid unnecessary and unwanted doglegs. Weight on bit may need to be reduced and/or reaming initiated where such an acceleration in buildup rate occurs.
It is common practice to use the minimum number of drill collars in the BHA. Two stands of collars is typical. The remaining weight on bit is got from heavyweight drillpipe. A weight calculation (Chapter 11) must be made at the BHA design stage (taking into account hole inclination, buoyancy factor, drilling jar position and safety factor). On no account should the drillpipe be run in compression in a normal directional well.

10.1.7 BHAs for maintaining Inclination
In order to keep the hole inclination within a small "window" (a so-called lockup situation), a condition of zero net side force on the bit has to be aimed for. This type of BHA must be stiff. The stiffness of the BHA also helps to control bit "walk".
In practice, slight changes in hole inclination often occur even with a good choice of locked BHA. However, the objective is to get a complete bit run without needing to POOH for a BHA change. Experience in a location should give the DD the data for fine-tuning the BHA.
Figure 10-17 gives some typical lockup BHAs.
(7) (6) (5) (4) (3) (2) (1)
15'-20' 30' 30'
5'-20' 30' 30' UG
12'-15'
12'-15'
12'-15'
5'-12'
30' 30' 30' 30' 30' 30'
30' 30' 30' 30' 30'
(2) Can Vary From Positive to Negative Tendency (1) Special Holding BHA to Achieve Positive Tendency
Figure 10-17 BHAs for maintaining inclination
A typical lockup BHA for 12-1/4" hole at 30° inclination is shown in Figure 10-18. If a slight build is called for (semi-build BHA), the second stabilizer should be reduced in gauge - typically down to 12".
12 1/4"
12'-15' 30' 8" D.C. HWDP FG 8" SDC UG 8" NMDC FG
(12 1/8")
Figure 10-18 Typical locked up BHA for 12-1/4 in. hole
The DD would be well advised to have at his disposal a range of undergauge stabilizers from 11-1/2" up to 12-1/8" in increments of 1/8".
BHA No. 1 in Figure 10-17 can have either a building or a dropping tendency. This BHA using 8" collars in 17-1/2" hole in soft formation may barely hold inclination. However, using the same BHA and collars in 12-1/4" hole may lead to a significant buildup rate (0.5°-1.0°/100').

Figure 10-19
BHAs for dropping inclination

The response of this type of BHA is determined by the following factors: 1. Holesize. 2. Distance between the near-bit and lower string stabilizers. 3. Stiffness of the collar directly above the near-bit.
4. Gauge of the stabilizers. 5. Formationeffects. 6. Drillingparameters.
To summarize, reducing the gauge of the second stabilizer gives the same result as leaving the stabilizer alone but increasing the distance between it and the near-bit by a certain amount. However, for directional control purposes, the former approach is better.
Lockup BHAs account for the biggest percentage of hole drilled in deviated wells. Thus, the DD’s judgment and expertise in BHA selection is vital in saving trips.
10.1.8 BHAs for Dropping Inclination
A selection of common dropping assemblies is listed in Figure 10-19.
Maximum Dropping BHA
Special Dropping BHA
(7) (6) (5) (4) (3) (2) (1)
75'-90' 30'
75'-90' 60'-75' 30' 60'-75'
30'-60' 30' 30'-60'
30'-75' 30'
UG
BHA No. 5 (60' pendulum) is the most common where a high drop-off rate (1.5°-4°/100') is needed, i.e., in "S"-type directional wells. However, “S"-type wells are normally planned to have a drop-off rate of 1°- 2°/100'. This is in order to avoid keyseats and excessive wear on the drilling tubulars. Thus, a common approach is to start the drop-off earlier than the program with a less-aggressive BHA incorporating an undergauge near-bit stabilizer (a modification of BHA No. 1). A drop-off rate of about 1°-1.5°/100' is often achievable with such a BHA. When the inclination has fallen to about 15° (at which point the gravity force is much less), a round trip is made. BHA No. 5 is then used to drill to TD. This plan should, however, be discussed with the client before the job starts. An "extra" trip is involved.

(12 1/16")
10.1.9 Special BHAs
Figure 10-20 Semidrop BHA

Rate of drop-off usually slows significantly below 8°-10° inclination. When the inclination falls to 2°, the well is considered vertical. However, the inclination should continue to be monitored, to ensure it does not start to increase again. It's advisable to ream each connection.
There is very little control over hole direction when using a pendulum BHA. Sometimes the well walks excessively when using a tricone bit during the drop-off. The DD should thus have some tolerance available in hole direction when he starts the drop-off. RPM should be kept high (this also helps the drop-off rate).
A lock-up BHA incorporating an undergauge near-bit (Figure 10-20) is known as a semi-drop BHA. This type of BHA is often used in slant wells where the DD is "above the line" and wants to drop into the target with a nice slow drop-off rate (typically 0.1°-0.5°/100'). The drop-off rate achieved is determined by how much undergauge the near-bit is. Part of the art of the DD is to choose the correct stabilizer gauge in a given situation. Experience from offset wells is indispensable.
12 1/4"
15' 30' 8" D.C. HWDP UG 8" SDC FG 8" NMDC FG
Tandem Stabilizers It's fairly common to run a string stabilizer directly above the near-bit. This is normally for directional control purposes. An alternative is to run a near-bit with a longer gauge area (greater wall contact).
High rotary torque may result in either case. It is dangerous to run tandem stabilizers directly after a more limber BHA. It's advisable to ream to bottom at the first indication of the bit "taking weight".
Because of the increased stiffness of a tandem stabilizer, it's normally necessary to increase the spacing between it and the next stabilizer, compared to when a standard near-bit stabilizer is used.
Roller Reamers In medium/hard formation where rotary torque is excessive, it may be necessary to dispense with some or all of the stabilizers in the BHA. Roller reamers are a good alternative. However, while they are relatively easy to rotate, they behave differently to stabilizers from a directional viewpoint. As a rule, they have a tendency to drop angle. Thus, the spacing between the near-bit roller reamer and the lower string roller reamer/stabilizer has to be greater than in the conventional lock-up using stabilizers only. The exact spacing should come from experience in the area.
A tandem near-bit roller reamer/string stabilizer combination is another alternative. It's important to check the condition of the roller reamers after each run and replace the cutters/pins/blocks as required.

Jetting BHA In very soft formation, jetting is an easy and cost-effective way to kick off a well. Jetting is perfectly compatible with MWD. Although some "spudding" of the drillstring is normally required, the shock loading on the MWD tool is not excessive (formation is soft).
Jetting has the advantage that the well can be kicked off along the required direction and the inclination built up all the way to maximum angle in one run.
Another application of jetting is "nudging" a well on a multiwell platform. Where insufficient/imprecise survey information is available for surrounding wells, jetting is a safer anti-collision approach than using a mud motor.
As mentioned previously, a jetting BHA is a modified buildup BHA. Aligning the key of the mule shoe sleeve directly above the center of the large open nozzle (where two blanks are used) or above the center of the two large nozzles (where one blank is used) is the basic difference.
A typical jetting BHA used to kickoff in 17-1/2" hole at a shallow depth (e.g. 500’) in soft formation is shown in Figure 10-21.
Nozzles (28,0,0) 17 1/2"
90' 30' 240' X/O HWDP FG FG D.C. FG D.C.
Figure 10-21 Typical jetting BHA
Precautions to be taken when running a jetting BHA:
1. Plan the job! Pick up enough drill collars in the BHA (kickoff point is shallow) to allow sufficient BHA weight for spudding/slacking off as required. Ensure that the driller does not spud with more weight than you have available. Otherwise, a bent kelly/string will result (not a good situation!). It’s advisable to have 12x8" drill collars and 30x5" HWDP in the string when doing a jetting job. Account for inclination etc. in your available WOB calculation as you pick up drill collars and HWDP.
2. Do not run drilling jars in the jetting BHA.
3. Do not jet too long an interval! Check dogleg severity on each single. Decrease/increase jetted interval as required. Wipe out excessive doglegs by reaming/washing and re-surveying. A good guideline is to jet 5’ and drill the remainder of each of the first 2 singles. Check the resulting dogleg severity.
Straight-hole BHAs Several years ago, a 60’ Pendulum BHA was most often used to control deviation in vertical wells. This approach is still used in some areas which do not have severe formation dip. However, if high weight on bit is applied with such a BHA, the bit may be "kicked off" and a crooked hole will result.
Now, a stiff (packed-hole) BHA is preferred. It gives a much better possibility of giving a near-vertical hole. If, due to severe formation effects, the hole becomes crooked, it may be necessary to run a mud motor or a Pendulum BHA (with low WOB and high RPM), to get the well back to vertical before re-running the stiff BHA.
(UBHO+NMDC's+D.C.)

Gilligan BHAs A "Gilligan" BHA is a flexible buildup BHA designed for certain specific applications where high buildup rates are required, e.g. in a conventional DD job when we're far “below the line" on the directional plot - probably also with significantly less inclination than needed at that point; in horizontal drilling - use of rotary buildup is faster and easier in the buildup phase (less hole friction) for the DD than using a mud motor - provided hole direction can be corrected later using a steerable motor.
Buildup rates of the order of 6°-11°/100' are possible, depending on the flexibility of the tubular component (flexible collar, heavyweight or even drillpipe) directly above the near-bit stabilizer. It's vital to take surveys at close intervals to “track" the buildup rate achieved. Again, as hole inclination increases, buildup rate increases.
It was quite common before the advent of mud motors to use a type of gilligan BHA to perform a “blind” sidetrack (vertical well) by “bouncing off” the cement plug.
This would include a flexible joint (e.g. heavyweight) directly above the bit. Because of its crude nature and high dog-leg severity induced, this latter application for a gilligan BHA is seldom, if ever, seen. However, gilligan BHAs are still used in other applications. An example of a gilligan BHA is given in Figure 10-22.
FG
30' 8" D.C.
30'
30'
FG/UG
8" O.D. Steel D.C.
8" O.D. NMDC
6 1/2" O.D. 30' NMDC
FG 12 1/4"
Figure 10-22 Example of a Gilligan BHA

10.2 Common BHA Problems 10.2.1 Formation Effects
It often happens that when a certain TVD is reached, BHA behavior changes significantly e.g. A BHA which held inclination down to 5,000’ may start to drop angle. Why? Assuming that the near-bit has not gone undergauge, it’s probably due to formation effects (change in formation, change in dip or strike of the formation etc.). It’s vital to keep a good database and try to anticipate the problem for the following well.
Abrasive formations pose problems for the DD. Ensure the bit has good gauge protection. Use stabilizers with good abrasion resistance, e.g. geothermal dressing or pressed-in TCIs. Check the gauge of the stabilizers when POOH. Watch out for a groove cut on the leading edge of stabilizers - indication of need to change out the stabilizer.
When it’s difficult to drop inclination, sometimes a larger O.D. drill collar is used as the lower part of the pendulum. Another possibility is the use of a tungsten short collar - the concentration of the same weight into a much shorter element should give a more effective pendulum side force.
10.2.2 Worn Bits
In a long hole section in soft formation interbedded with hard stringers, the long-toothed bit may get worn. ROP will fall sharply. Net side force will decrease due to stabilizers undercutting the hole.
Thus, a BHA which had been holding inclination up to that point will start to drop angle. However, if the survey point is significantly behind the bit, this decrease in angle will not be seen in time. If the worn teeth are misinterpreted as a balled-up bit and continued lengthy efforts made to drill further, serious damage may be done to the hole. It has happened that a drop in inclination of 6 (with a severe dogleg severity) has happened in this situation. In addition, a bit having worn teeth has a tendency to lose direction. Thus, it is important to POOH a worn bit in such a situation.
10.2.3 Accidental Sidetrack
In soft formation, where a multi-stabilizer BHA (either Buildup or Lockup) is run immediately after a mud motor/bent sub kickoff run, great care must be taken. Circulation should be broken just before the kickoff point. The BHA should be washed/worked down, using full flow rate. The DD must be on the drill floor while this is happening. Try to work through tight spots. If string rotation is absolutely necessary, keep RPM low and cut rotating time to the absolute minimum. The risk of sidetracking the well (with subsequent expensive plug-back and redrill) is high. Several kickoffs have been lost in various parts of the world by carelessness on the part of the DD.
Where the kickoff is done in a pilot hole in soft formation, an under-reamer or hole opener is used to open the hole prior to running casing. Again, to avoid an unwanted sidetrack, a bull-nose (not a bit) and possibly an extension sub/short collar should be run below the under-reamer/hole opener.

10.2.4 Pinched Bit

In hard formation, it’s especially important to check each bit for gauge wear etc. when it’s POOH. When RIH with a new bit and/or BHA, it’s imperative that the driller start reaming at the first sign of under-gauge hole (string taking weight). If he tries to “cram" the bit to bottom, it will become “pinched". Bit life will be very short.

10.2.5 Differential Sticking

Where differential sticking is a problem, more than three stabilizers may be run in an effort to minimize wall contact with the drill collars. However, the distance between these “extra" stabilizers normally has to be such that they have little effect. They only lead to increased rotary torque.
It is vital to minimize time taken for surveys (even with MWD) in a potential differential sticking area.

10.2.6 Drilling Parameters

High rotary/top drive RPM acts to stiffen the string. Thus, for directional control, if possible, high RPM should be used during the rotary buildup phase, when the BHA is most limber. However, it's vital to check with MWD engineer for acceptable range of RPM (to avoid resonance). On a new job the rig specifications (particularly mud pumps and drawworks) should be checked with the toolpusher.
Typical values in 17-1/2" hole during rotary build/lock phases with a milled- tooth bit would be 160-170 RPM. The rotary transmission would normally have to be put into high gear. In 12-1/4" hole, RPM is normally less (e.g. 100-140), due to bit life and other factors.
Conversely, to induce right-hand walk, it's recommended to slow the RPM (if the hole direction allows). Weight on bit may be simultaneously increased, if the hole inclination allows.
PDC bits normally have a tendency to walk left. This should be allowed for when planning the lead angle at the pre-kickoff stage. Again, experience in the area has to be used in making this decision.
To increase rate of buildup, increase the weight on bit. This is normally the case. However, when the WOB reaches a certain value, reverse bending may occur when using a flexible buildup BHA (e.g. 90' between near-bit and bottom string stabilizers). Suggested maximum value of WOB for 17 1/2" hole is 55,000 lbs. If inclination is not building enough at this WOB, it's very unlikely that increasing the WOB will improve the situation. Look to hydraulics or possibly POOH for a more limber hook-up.
It's vital that the DD observe the buildup rate carefully. Drilling parameters normally have to be changed very often (typically after every survey). With MOOD, there's no excuse for not keeping close control of buildup rate. The client normally will not complain about the DD taking too many surveys. He will complain if the well goes off course due to insufficient control by the DD!


10.3 BHA Equipment and Tools
It’s the responsibility of the DD to ensure that everything needed (within reason) for future BHAs is available on the rig. This applies regardless of whether the tools come from ANADRILL, the client or a third party. As stated in the DD UOP, the DD must check all the directional equipment thoroughly on arrival at the rigsite. Additional equipment must be ordered with plenty of lead time. Sufficient backup of motors, bent subs, etc., should be at the wellsite.
For rotary BHAs, following are some suggestions:
1. A selection of stabilizers (normally a combination of sleeve- type and integral blade design for 17-1/2" and smaller hole sizes) with 360 wall coverage should be available.
2. Short drill collars are a vital component of a lockup BHA. If possible, a selection of short collars (e.g. 5’, 10’ and 15) should be available. In addition, in a well where magnetic interference from the drill-string (mud motor) is expected to be a problem during the buildup phase, non-magnetic (rather than steel) short collars should be provided
3. Check that the rig has sufficient drill collars and HWDP available.
4. Check that the client has sufficient bit nozzles of each size (including what’s needed when running a mud motor).
5. Have at least one spare non-magnetic drill collar of each size. As NMDCs are more prone to galling, damaged collars should be returned to the shop for re-cutting/re-facing when replacements arrive.
6. Any crossover subs, float subs, bit subs etc. required later must be on the rig. Think ahead! The DD should be thinking at least one BHA ahead!
10.4 Recap
1. To build inclination, always use a full-gauge nearbit stabilizer.
2. The more limber the bottom collar, the greater the buildup rate achievable.
3. Take frequent surveys (e.g. every single with MWD) during the buildup phase (all wells) and the drop-off phase ("S"-type wells) in order to react quickly to unexpected trends.
4. A jetting BHA is a modified buildup BHA. Don’t jet too far! Watch the WOB available for jetting/spudding.
5. To drop inclination, either use an under-gauge near-bit (semi-drop BHA, for low drop-off rate) or no near-bit (pendulum BHA, for sharp drop-off rate).
6. A locked BHA which is holding inclination with an under-gauge stabilizer above the short collar will start to drop inclination if this stabilizer is made full -gauge.
7. In an “S”-type well, try to start the drop-off early using a semi-drop BHA. Change to a pendulum BHA at, say, 15 inclination.
8. Try not to have to build inclination into the target - better to drop slowly into the target.
Provisory - 06 Dec 96 Confidential Directional Drilling 10-22
Bottom Hole Assemblies
9. Three stabilizers are normally sufficient in a BHA. In pendulum BHAs, two stabilizers should suffice.
10. Use as few drill collars as possible. Use heavyweight drillpipe as remaining available weight on bit.
11. Try to use a fairly standard (reasonably predictable) BHA. Do not try any “fancy" BHAs in a new area. Get some experience in the field first!
12.
Gilligan” BHAs are not standard. Only use one when absolutely necessary. 13. DD should be on the drill floor when washing/working rotary BHA through kickoff
section in soft formation. Avoid sidetracking the well!
14. After a kickoff or correction run in medium and hard formations, ream carefully through the motor run with the following rotary BHA until hole drag is normal.
15. In hard and/or abrasive formations, gauge stabilizers carefully when POOH. Replace stabilizers as required. Check the bit. If bit is undergauge, reaming will be required! Do not let the driller "pinch" the bit in hard formation.
16. Check all DD equipment before and after the job. It's good practice to caliper all the DD tools and leave list on drill floor for drillers. Watch out for galled shoulders!
17. In potential differential sticking areas, minimize survey time. If using single-shot surveys, reciprocate pipe. Leave pipe still only for minimum interval required.
18. A BHA which behaves perfectly in one area may act very differently in another area. Local experience is essential in “fine-tuning" the BHAs!
19. Deciding when to POOH for a BHA change is one of DD's main responsibilities. Ideally, this should coincide with a trip for bit change.
20. In the tangent section of a well, a BHA change may simply entail changing the sleeve on the stabilizer directly above the short collar. The trick is - by how much does the DD change the gauge? Sometimes a change in gauge of 1/16" may lead to a significant change in BHA behavior!
21. High RPM "stiffens” the BHA- helps to stop walk due to formation tendencies.
22. It's usually easier to build inclination with lower RPM. However, DD may want to use high RPM during buildup phase (for directional control). WOB is the major drilling parameter influencing buildup rate.
23. To help initiate right-hand walk, it's advisable to use higher WOB and lower RPM.
24. In soft formation, it may be necessary to reduce mud flow rate to get sufficient WOB and reduce hole washout. Be careful! Wash each joint/stand at normal (full) flow rate before making the connection.
25. Reaming is effective in controlling buildup rate in soft formation. It becomes less effective as formation gets harder. However, even in hard formation, reaming before each connection helps keep hole drag low.
26. Lower dogleg severity = smoother wellbore = lower friction = lower rotary torque = less keyseat problems = less wear on tubulars = less problems on trips. All these things mean a happier client! however, we must hit the target also!