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
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
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
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
Regular Drill Pipe
Heavy Weight Drill Pipe(s)
Smaller Drill Collars
Crossover Sub to Smaller Drill Collars
Measurement While Drilling (MWD) Tool
Nonmagnetic Drill Collar
Roller Reamer Shock Sub
Near Bit Stabilizer Packed-Hole B.H.A.
10-1 Slick and packed hole BHAs
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
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
Inside Diameter of Drill Collar Figure
10-3 BHA as a hollow cylinder WOB
Negative Side Force or Pendulum Force
Outside Diameter of Drill Collar
Moment of Inertia for Round Drill Collars Stiffness
Coefficient = E•IE =
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 xπ •(8.04
-2.81254) / 64 = 5.9397 x 109 b.OD =
7” and ID = 2-13/16"Solution E•I =30.0 x
106 xπ •(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
Material Alloy steel
Monel Stainless steel Tungsten carbide
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
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- , H
10.1.2 Slick Assembly The simplest
type of BHA (bit, drill collars, drillpipe) is shown in Figure
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
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.
M = Moment of Inertia
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
M , M = Moments of Inertia 12
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.
S.F=-171 lb S.F=-249 lb S.F=-295 lb S.F=-210
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
10 20 30 40 50 60 Weight on Bit, 1000 lb
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
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
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
9,000 8,000 7,000 6,000 5,000 4,000 3,000 2,000 1,000
0 10 20 30 40 50 60
Inclination, degrees Figure
10-11 Inclination v sideforce for 3 BHAs
Bit Side Force,
2,600 2,400 2,200 2,000 1,800 1,600 1,400 1,200 1,000
12.25" hole, 10-lb/gal mud 2.25" x 8" collars 10
60' 30' 300'
60' 60' 300'
45' 30' 300'
0 10 20 30 40 50 60
Inclination, degrees Figure
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,
10-13 10.1.5.2Undergauge Second Stabilizer FG
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.
UG 10' FG Undergauge
(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
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
Assembly Hole Diameter
Well Bore Size Increased by Stabilizer
Drilling Assembly Initial Gauge
Side Force at Hole StabilizerF 2
D 1 Side Force While Drilling Causes
SideForceat EllipticalHole Bit F 1
Hole Diameter D1
Net Side Force Drcreases
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.
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' 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
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
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
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'-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
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
4. Gauge of the stabilizers. 5. Formationeffects. 6.
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
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' 60'-75' 30' 60'-75'
30'-60' 30' 30'-60'
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
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
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.
15' 30' 8" D.C. HWDP UG 8" SDC FG 8" NMDC
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
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
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
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
BHAIn 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
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
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
BHAsA "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
30' 8" D.C.
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
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
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
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
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
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
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
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
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
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
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
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
are not standard. Only use one when absolutely necessary. 13. DD
should be on the drill floor when washing/working rotary BHA
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
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
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
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!