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The E*C TRAK Torque and Drag Module

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The E*C TRAK Torque and Drag Module
This program, developed at the Drilling Research Center in Celle,
Germany, is used to calculate torque and drag when a friction factor
(coefficient of sliding friction) is known or estimated. It will calculate the
friction factor when either torque or hookload is known.
Software accuracy has been verified against actual field data, with inputs
and outputs handled in user selected units.
General Uses
The program may be used to:
• Optimize well path design for minimum torque and drag
• Analyze problems either current or post-well
• Determine drillstring design limitations
• Determine rig size requirements
Inputs Required
• Drillstring component data (OD, ID, tool joint, and material
composition)
• Survey data (actual or planned)
• Friction factor(s) or actual hookload or torque values (for friction
factor calculation)
Outputs
Information concerning loads, torques and stresses are calculated for
discrete points in the drillstring from rotary table to the bit. These values
are output in both tabular (summary or detailed) and graphical formats:
• Drag load (pick-up or slack-off)
• Pick up load
• Slackoff load
• Rotating off bottom load
• Drilling load
• Rotating off bottom torque
• Rotary torque (drilling and off-bottom)
• Maximum allowable hook load (at minimum yield)
• Drillstring weight (in air)
• Bit to neutral point distance drillstring twist
• Drillstring twist
• Axial stress
• Torsional stress
• Bending stress
• Total equivalent stress

Calculating BHA Weight With Drill Pipe In Compression - Summary

Calculating BHA Weight With Drill Pipe In Compression
Summary

• When drilling vertical wells, ordinary drill pipe must NEVER be run
in compression, in any hole size. Therefore, sufficient BHA weight
must be used to provide all the desired weight on bit with an
acceptable safety margin, except at higher inclinations.
• In large hole sizes (16-inch or greater) drill pipe should not be run in
compression.
• In smaller hole sizes on high-angle wells (over 45°), drill pipe may be
run in compression to contribute to the weight on bit, provided the
maximum compressive load is less than the critical buckling force.
This critical buckling force is the minimum compressive force which
will cause sinusoidal buckling of the drill pipe.
• A safety margin of at least 10% should be used in the calculation to
allow for some drag (friction) in the hole. However, axial drag is not a
major factor when assemblies are rotated.
The majority of the preceding discussion concerned rotary assemblies.
However, it would also apply to steerable motor systems used in the
rotary mode, with only minimal oriented drilling anticipated, the
required BHA weight could be calculated the same way. If a
significant amount of oriented drilling was likely, then the drag in the
hole should be evaluated using Torque and Drag computer programs.
In this type of situation, a proper engineering analysis of BHA weight
requirements is advised.

BHA Weight For Steerable Motor Assemblies

BHA Weight For Steerable Motor Assemblies

In practice, BHA weight for steerable assemblies on typical directional
wells is not a problem for the following reasons.
• The WOB is usually fairly low, especially when a PDC bit is used.
• When the drillstring is not rotated, the drill pipe is not subjected to the
cyclical stresses which occur during rotary drilling. Therefore,
sinusoidal buckling can be tolerated when there is no rotation of the
drillstring. Helical buckling however, must be avoided.
Helical buckling occurs at 1.41 FCR, where FCR is the compressive force
at which sinusoidal buckling occurs.
Therefore, if BHA weight requirements are evaluated as for rotary drilling,
the results should be valid for steerable systems in the oriented mode
except for unusual well paths which create exceptionally high values of
axial drag.

BHA Requirements When The Drillstring Is Not Rotated

BHA Requirements When The Drillstring Is Not Rotated

As stated earlier, when the drillstring is rotated, the component of sliding
friction (drag) is small and may be compensated for by using a safety factor
in BHA weight calculations. Drillstring friction for rotary assemblies will
mainly affect torque values. When the drillstring is not rotated (a steerable
motor system in the oriented mode) axial drag can become very significant
and drillstring friction should be evaluated.
A proper analysis of drillstring friction is more complex and must take into
account a number of factors, including wellbore curvature.

Calculating BHA Weight With Drill Pipe In Compression

Calculating BHA Weight With Drill Pipe In Compression
This means that on high-angle wells in small hole sizes, a fraction of the
weight on bit can safely be provided by having drill pipe in compression. It
is suggested that 90% of the critical buckling force be used as the
maximum contribution to the weight on bit from ordinary drill pipe.
Denoting the total air weight of the BHA by WBHA the weight on bit by
WBIT and the critical buckling load by FCR, we have:

Continuing example 4.5, recalculate the weight of the BHA required
(assuming some drill pipe is to be run in compression).
Suppose we are using New 5-inch Grade E drill pipe with 4.5-inch IF
connections.
Referring to the table for 5-inch drill pipe in a 12.25-inch hole, we see that
the critical buckling load at 60° inclination is approximately 26,000 lbs.
Our formula then gives:

Thus, a total air weight of 82,000 lbs is required. This is much more
feasible than the value of 138,000 lbs which was previously calculated.

Calculating Critical Buckling Force

Calculating Critical Buckling Force

Calculate the critical buckling load for 4.5-inch grade E drill pipe with a
nominal weight of 16.6 lb/ft (approximate weight 17.98 lb/ft; tool joint OD
6.375 inches: from API RP7G, Table 2.10) in an 8.5-inch hole at 50°
inclination.
1. Young's modulus, E, for steel is 29 x 10 psi

4.5-inch drill pipe with a nominal weight of 16.6 lbs/ft has an ID
of 3.826 inches. This information can be found under “New Drill
Pipe Dimensional Data” in the API RP-7G.

3. The approximate air weights for different sizes of drill pipe can
also be found in the API RP-7G.
Air weight = 17.98 lb/ft = 1.498 lb/in

Critical Buckling Force = 30,769 lbs

Running Drill Pipe In Compression

Running Drill Pipe In Compression

Example

Prior to drilling a 12.25-inch tangent section in a hard formation using an
insert bit, the directional driller estimates that they expect to use 50,000 lbs
WOB. The hole inclination is 60° and the mud density is 11 ppg.
What air weight of BHA is required if we are to avoid running any drill
pipe in compression? Use a 15% safety margin.

This is roughly the weight of ten stands of 8-inch drill collars, or
attentively, six stands of 8-inch collars plus 44 joints of HWDP!
This is just not practical! It would be a long, stiff and expensive BHA.

Critical Buckling Force
Dawson and Paslay developed the following formula for critical buckling
force in drill pipe.

where E is Young's modulus.
I is axial moment of inertia.
W is buoyed weight per unit length.
q is borehole inclination.
r is radial clearance between the pipe tool joint and the
borehole wall.
If the compressive load reaches the FCR, then sinusoidal buckling occurs.
This sinusoidal buckling formula can be used to develop graphs and tables
(see pages 4-18 through 4-23). If the compressive load at a given
inclination lies below the graph, then the drill pipe will not buckle. The
reason that pipe in an inclined hole is so resistant to buckling is that the
hole is supporting and constraining the pipe throughout its length. The low
side of the hole tends to form a trough that resists even a slight
displacement of the pipe from its initial straight configuration.
The graphs and tables provided in this section are for specific pipe/hole
configurations and may be used to look up the critical buckling force. The
following example illustrates how to calculate the critical buckling load.

Required BHA Weight For Rotary Assemblies

Required BHA Weight For Rotary Assemblies
When two contacting surfaces (i.e drillpipe and the borehole wall) are in
relative motion, the direction of the frictional sliding force on each surface
will act along a line of relative motion and in the opposite direction to its
motion. Therefore, when a BHA is rotated, most of the frictional forces
will act circumferentially to oppose rotation (torque), with only a small
component acting along the borehole (drag).
Measurements of downhole WOB by MWD tools has confirmed that when
the BHA is rotated there is only a small reduction in WOB due to drag.
This reduction is usually compensated for by using a “safety factor”.
Consider a short element of the BHA which has a weight “W” (see
following figure). Neglecting drag in the hole:
Effective weight in mud = W (BF)
Component of weight acting along borehole = W (BF) cosq
... where Q is the borehole inclination
Extending this discussion to the whole BHA,
WBIT = WBHA (BF) cosq
... where WBHA is the total air weight of the BHA and WBIT is the weight
on bit.
Therefore, if no drill pipe is to be run in compression

BHA Weight & Weight-On-Bit

BHA Weight & Weight-On-Bit

One important consideration in designing the BHA is determining the
number of drill collars and heavy-weight pipe required to provide the
desired weight-on-bit. When drilling vertical wells, standard practice is to
avoid putting ordinary drill pipe into compression (recommended by
Lubinski in 1950). This is achieved by making sure that the “buoyed
weight” of the drill collars and heavy-weight pipe exceed the maximum
weight-on-bit. This practice has also been adopted on low inclination,
directionally drilled wells.
In other types of directional wells, it must be remembered that since gravity
acts vertically, only the weight of the “along-hole” component of the BHA
elements will contribute to the weight-on-bit. The problem this creates is
that if high WOB is required when drilling a high inclination borehole, a
long (and expensive) BHA would be needed to prevent putting the drillpipe
into compression. However, for these high inclination wells, it is common
practice to use about the same BHA weight as used on low inclination
wells.
On highly deviated wells, operators have been running drillpipe in
compression for years. Analysis of drillpipe buckling in inclined wells, by
a number of researchers (most notably Dawson and Paslay), has shown that
drillpipe can tolerate significant levels of compression in small diameter,
high inclination boreholes. This is because of the support provided by the
“low-side” of the borehole.
Drillpipe is always run in compression in horizontal wells, without
apparently causing damage to the drillpipe.

Diamond Bit Salvage

Diamond Bit Salvage

When returning a bit for salvage, it is helpful to furnish a performance
report on the bit. The manufacturer can then inspect the bit with a better
understanding of how it was used in conjunction with its condition.
Salvage, or recovery of the stones in a diamond bit is done by electrolysis.
The binder material is plated out of the matrix, which allows the tungsten
carbide particles and the diamonds to drop out. The diamonds are screened
out of the resulting sludge, then chemically cleaned.
When brought to the sorting room, the diamonds are screened for sizing,
then each stone is inspected and graded under a magnifier by an expert.

Diamond Bit Selection

Diamond Bit Selection

Choice of bit style, diamond size and diamond quality can mean the
difference between an economical bit run or a costly bit run.
Some formations are more drillable with diamond bits than others, but
these formations and their drillability change from area to area. Diamond
bits normally perform better in hard formations, because it is easier to keep
the bit clean, the cuttings are smaller, and individual diamonds cut with a
plowing action rather than by chipping and tearing.
Diamond bits require hydraulics equivalent to, or greater than other bits in
order to stay clean and run cooler in softer, stickier formations. The smaller
the diamond bit, the better it performs - mainly because of hydraulics.
Since the cutting surface of a diamond bit runs very close to the formation,
the cuttings move from the center of the hole across the face of the bit to
the outside of the borehole. The larger the bit, the greater amount of
cuttings to be moved across the face, which may result in partial clogging
of the flow area and a decrease in penetration rate unless hydraulics are
maintained at high energy levels.

Special Designs

Standard bit styles can be used in most cases. Special designs, or standard
bits with special features, are manufactured for unusual applications. For
example:
1. Low pressure drop bits for downhole motors
2. Flat bottom, shallow cone designs for sidetracking with
downhole motors
3. Deep cone, short gauge bit design for whipstock jobs or
sidetracking
4. Core ejectors can be built into most styles where cone wear is a
problem or where larger cuttings are desired
5. Deep cones having a 70° apex angle are normally used to give
built-in stability and greater diamond concentration at the cone
apex. In certain formations, a deep cone could fracture the
formation horizontally, leaving a plug in the bit cone. Thereafter,
the formation plug would be ground and splintered away beneath
the bit face, inducing diamond breakage and premature failure.
In fracturing type formations, a shallower cone angle of about
90° or 100° may be used.

Selection Guideline
Because formations of the same age and composition change in character,
with depth, and drill differently, no universal bit selection guide can be
prepared. However, general guidelines include:

Soft formations
Sand, shale, salt, anhydrite or limestone require a bit with a radial fluid
course set with large diamonds. Stones of 1-5 carats each are used,
depending on formation hardness. This type of bit should be set with a
single row of diamonds on each rib and designed to handle mud velocities
ranging from 300-400 fps to prevent balling.

Medium formations
Sand, shale, anhydite or limestone require a radial style bit with double
rows of diamonds on each blade or rib. Diamond sizes range from 2-3
stones per carat. Mud should be circulated through these bits at a high
velocity. Good penetration rates can be expected in interbedded sand and
shale formations.

Hard, dense formations
Mudstone, siltstone or sandstone usually require a crowsfoot fluid course
design. This provides sufficient cross-pad cleaning and cooling and allows
a higher concentration of diamonds on the wide pads. Diamond sizes
average about 8 stones per carat.

Extremely hard, abrasive or fractured formations
Schist, chert, volcanic rock, sandstone or quartzite require a bit set with
small diamonds and a crowsfoot fluid course to permit a high concentration
of diamonds. The diamonds (about 12 per carat) are set in concentric
“metal protected” ridges for perfect stone alignment, diamond exposure
and protection from impact damage.

General Diamond Bit Drilling Practices - Drilling

Drilling

After the bit has been started, rotary speed should be increased to the
practical limit indicated by rig equipment. The drill pipe, hole condition,
and depth should also be taken into consideration.
Weight should be added as smoothly as possible in 2000 pound increments.
Observations of penetration rate after each weight increase should be made
to avoid overloading. As long as the penetration rate continues to increase
with weight, then weight should be increased. However, if additional
weight does not increase the penetration rate, then the weight should be
reduced back 2000 to 3000 pounds, to avoid packing and balling-up of the
space between the diamonds. Drilling should be continued at this reduced
weight.
After making a connection, be sure to circulate just off bottom for at least
five minutes, as cuttings in the hole could damage the bit. The time spent
here may lengthen the life of the bit by many hours.

General Diamond Bit Drilling Practices - Starting a Diamond Drill Bit

Starting a Diamond Drill Bit

It is recommended that circulation be started prior to reaching bottom and
that extreme care be used to find bottom. The bit should be rotated slowly
to bottom, or if possible establish bottom with zero rotation. Then circulate
with full volume and rotate slowly at a point about one foot or less off
bottom for a period of at least five minutes to clean the bottom of the hole.
After circulating, use extreme care to find bottom. Within the minimum bit
weight and full fluid volume, drill enough hole to form a new bottom hole
contour. This is important since a diamond bit does not get proper cleaning
and cooling action until the bottom of the hole exactly fits the bit profile.
Under some conditions, procedures may dictate touching bottom with full
pump force but no rotation in order to try to crush any irregular large
foreign particles on the bottom of the hole, with minimum of bit damage.
This procedure, when appropriate, should be used several times before
rotating the drill string.

General Diamond Bit Drilling Practices

General Diamond Bit Drilling Practices
Prior to running a diamond bit, clean the hole by running a junk basket on
the last roller cone bit.
Running a Diamond Bit into the Hole
Place the bit in the bit breaker and makeup with tongs on the collar, to the
same torque as used on the collar connection.
Use care going in the hole. Avoid striking ledges and pushing through tight
places which could damage the gauge diamonds.
Although diamond bits may be used to ream short intervals, care must be
taken, especially the first time a diamond bit is run. Remember, diamond
bits are solidly constructed and have no “give” as do roller cone bits. In a
reaming situation, most of the drilling fluid escapes through the junk slots
on the diamond bit and the mud cannot effectively cool the diamonds in the
gauge zone. During reaming, these diamonds absorb all applied weight and
may become overloaded.
When reaming, the bit weight of about 2,000 to 5,000 pounds maximum
should be used to avoid fracturing or burning the diamonds, and the rotary
speed should be moderate (40-60 rpm). If considerable reaming in hard,
abrasive formations is going to be necessary, the diamond bit should be
pulled and replaced with a diamond bit specifically designed for reaming.

Bit Technology - Diamond Bit - Torque and Bit Stabilization

Torque
Torque indications are very useful as a check on smooth operation. No
absolute values have been set up, but a steady torque is an indication that
the previous three factors are well coordinated.
Bit Stabilization
A diamond is extremely strong in compression, but relatively weak in
shear, and needs constant cooling when on bottom. The bit is designed and
the rake of the diamonds set, so that a constant vertical load on the bit
keeps an even compressive load on the diamonds, and even distribution of
coolant fluid over the bit face. If there is lateral movement or tilting of the
bit, an uneven shear load can be put on the diamonds with coolant leakage
on the opposite side of the bit.
Any of the standard “stiff-hookup” or packed hole assemblies are suitable
for stabilization when running diamond bits. It is recommended that full
gauge stabilizers be run near the bit, and at 10 feet and 40 feet from the
bottom.

Bit Technology - Diamond Bit - Rotary Speed

Rotary Speed

Rotary speed should be relatively high, with 100 rpm being average,
although 200 to 1000 rpm is not uncommon when downhole motors are
used. Penetration rate should increase at high speeds if hydraulics are good
and no roughness in drilling occurs.
Drill rate, with good hydraulics, is nearly a straight line function of rotary
speed. Drilling rate will, therefore, continue to increase as rotary speed is
increased. The limits are usually imposed by safety considerations for the
drill pipe.

Bit Technology - Weight-on-Bit

Weight-on-Bit

The weight on diamond bits should be somewhat less than for roller cone
bits. A good average weight is between 350 to 750 pounds per square inch
of bit area.
Hole conditions may make it necessary to slack off more weight, but
caution should be used in this respect since excessive weight-on-bit will
shorten its life. Formations which drill by a chipping action produce an
impact load against the diamonds. Drilling weight should be increased in
increments of 2,000 pounds until increases in weight does not show a
comparable increase in the penetration rate. When this occurs, the weight
should be decreased to the lowest weight at which the best penetration rate
was obtained.

Bit Technology - Diamond Bit Operating Parameters

Diamond Bit Operating Parameters

Hydraulics

Hydraulic programs for diamond bits must consider circulation rate and
pressure loss. There should be sufficient fluid and pressure to cool and
clean under the bit. Rig hydraulics do not require modification, but a good
optimum flow rate in the range of 4.5 to 7.0 gallons per minute per square
inch of hole area is necessary. It may be more or less if the hole or
operating conditions dictate and if the bit is designed for such conditions.
Each diamond on the bit is continually on bottom, continually doing work,
therefore the entire area must be continually cleaned and cooled. The bit
must be kept clean to prevent balling up, and to keep formations exposed to
the cutting action of the diamonds. The bit must be kept cool; excessive
heat is one of the diamond's worst enemies. Because of the diamond's
cutting action, heat is always being generated and a damage can only be
prevented with adequate flow rates. Other factors being equal, better
performance may be expected with higher rates of fluid flow.
Pressure is required to force the fluid over the face of the bit at velocities
high enough to provide adequate cooling and cleaning. When the bit is off
bottom, the fluid has a nearly unrestricted flow, but on bottom, the fluid
must pass through a small area made up of fluid courses in the bit and the
hole itself (clearance is the space between the bit matrix and the
formation). This results in an off-on bottom pressure difference in a range
of 100 to 1,000 psi depending on the total fluid area and operating
conditions (mud density, bit weight, pump pressure, etc.).

The Diamond Bit

The Diamond Bit

A diamond bit (either for drilling or coring) is composed of three parts:
diamonds, matrix and shank. The diamonds are held in place by the matrix
which is bonded to the steel shank. The matrix is principally powdered
tungsten carbide infiltrated with a metal bonding material. The tungsten
carbide is used for its abrasive wear and erosion resistant properties (but far
from a diamond in this respect). The shank of steel affords structural
strength and makes a suitable means to attach the bit to the drill string.
Diamond bits are sold by the carat weight (1 carat = 0.2 grams) of the
diamonds in the bit, plus a setting charge. The price will vary depending
upon classification (or quality) and size. The setting charge is to cover the
manufacturing cost of the bit. A used bit is generally returned to salvage
the diamonds and to receive credit for the reusable stones (which
materially decreases the bit cost). This credit is frequently as much as 50%
of the original bit cost.
Uses of Diamond Bits
As with any bit selection, the decision to run a diamond bit should be based
on a detailed cost analysis. There are, however, certain drilling situations
which indicate the likelihood of an economical application for diamond
bits.
• Very short roller cone bit life: If roller cone bit life is very short due to
bearing failure, tooth wear, or tooth breakage, a diamond bit can
increase on-bottom time dramatically. Diamond bits have no bearings
and each diamond has a compressive strength of 1,261,000 psi
(approximately 1.5 times that of sintered tungsten carbide). The
relative wear resistance is approximately 100 times that of tungsten
carbide.
• Low penetration rates with roller cone bits: Frequently, when roller
cone bits drill at slow rates (especially 5 ft/hr or less), due to high mud
weights or limited rig hydraulics, diamond bits can provide a savings.
The “plowing” type cutting action of diamond bits generally produces
higher penetration rates when using heavy muds. Since the drilling
fluid is distributed between the bit face and the formation in a smooth
uniform sheet, it takes less hydraulic horsepower per square inch to
clean under a diamond bit than under the same size roller cone bit.
• Deep, small holes: Roller cone bits that are 6-inch and smaller have
limited life due to the space limitations on the bearing, cone shell
thickness, etc. Diamond bits being one solid piece often last much
longer in very small boreholes.
• Directional drilling: Diamond side tracking bits are designed to drill
“sideways” making it a natural choice for “kicking off” in directional
drilling situations.
• Limited bit weight: Diamond bits drill at higher rates of penetration
with less weight than normally required for roller cone bits in the
same size range.
• Downhole motor applications: Roller cone bits generally have bearing
failures on motor applications due to high rotary speeds. Diamond bits
will have a very long life under these conditions.
• Cutting casing windows: Window cutting through casing using
diamond bits is now an effective, field-proven method for re-entering
older wells to increase production, to apply directional drilling
techniques, or to sidetrack. Using permanent casing whipstocks and
specially designed diamond bits, wider and longer windows are cut
when sidetracking.
• Coring: The use of diamond bits for coring operations is essential for
smooth, whole cores. Longer cores are possible with increased onbottom
time and cores “look better” because of the cutting action of
diamond bits as compared to those of roller cone bits.
There are some drilling situations which should be avoided when using
diamond bits:
• Very hard broken formations: Broken formations can cause severe
shock loading on diamond bits resulting in diamond breakage and a
short bit life.
• Formations containing chert or pyrite: Chert and pyrite tend to break
apart in large pieces and “roll” under a diamond bit, causing diamond
damage.
Reaming long sections in hard formations: Since the “nozzles” of a
diamond bit are formed by the formation on one side and the bit
matrix on the other side, hydraulic cooling and cleaning are extremely
poor during reaming. This can result in diamond “burning” or
breakage in the gauge area

Bit Technology - Diamond Bits - The Diamonds

The Diamonds

There are three classifications of diamonds used on diamond bits:

1. Single Crystal (West African-Bortz): These diamonds are

generally translucent, shiny and come in geometrically regular

shapes, such as octahedrons, dodecahedrons, and other shapes

tending towards spheres.

2. Coated (Congo): These diamonds have a heavy surface coating

or skin which is usually greenish or grayish in color, and does not

permit the transmission of light. They are balas (rounded) in

shape.

3. Carbonado (Black Diamond): So termed because the majority

are black in color and do not transmit light. The majority of these

diamonds have a non-crystalline or amorphous structure.

Diamonds used in oilfield bits are of natural origin and range from as small

as 15 stones per carat to as large as seven carats per stone. Diamonds are

resistant to abrasion, extremely high in compressive strength (the hardest

material known) but are low in tensile strength and have high thermal

capacity. The low tensile strength reduces its ability to withstand impacts.

The terminology used to describe diamond quality is quite varied, and

“quality” is roughly defined by the following factors:

1. Surface Condition: A glossy, smooth surface denotes a surface of

better quality.

2. Translucence: In crystalline diamonds, the ability to transmit

light is indicative of higher quality. This is not necessarily true

when non-crystalline diamonds and coated diamonds are being

evaluated.

3. Internal Structure: The absence of large internal fractures,

inclusions, and growth structures are indicative of high quality.

4. External Shape: A block-shape or nearly spherical diamond is

stronger and hence of higher quality.

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