engineering information technology : weight on bit

Showing posts with label weight on bit. Show all posts

Use Of Torque & Drag Programs For BHA Weight Evaluation

online engineering degree/engineering degree online/online engineering courses/engineering technology online/engineering courses online/engineering technician degree online/online engineering technology/electronic engineering online

Use Of Torque & Drag Programs For BHA Weight Evaluation

These programs have a wide range of applications, but have mainly been
used to evaluate drillstring design integrity and alternative well plans for
horizontal wells or complex, unusual directional wells. However, the
program can be used to check BHA weight calculations for normal
directional wells. The program will calculate axial drag for a non-rotated
assembly and also calculates the position of the neutral point in the
drillstring. In addition, the program calculates the forces on the drill pipe
and will “flag” any values of compressive load which exceed the critical
buckling force for the drill pipe.

Typical Drillstring - Wellbore Friction Factors

The E*C TRAK Torque and Drag Module

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

Computer Models of Drillstring Friction

Computer Models of Drillstring Friction

Proper evaluation of drillstring friction requires the use of a computer
program. These programs analyze drillstring friction for rotary drilling as
well as drilling with no drillstring rotation.
These mathematical models make a number of simplifying assumptions
and consider the drillstring as composed of discrete elements. Using these
models, it is possible to solve equations for the normal force of drillstring/
well bore contact at the bottom drillstring element, the friction force
deriving from that normal contact force, and the load condition at the upper
end of the drillstring element. Such methods, repeated for each drillstring
element over the length of the drillstring, yield the following information:
• Surface hookload and rotary torque
• Normal forces of drillstring/well bore contact at each drillstring
element
• Average torsional and tensile load acting upon each drillstring
element

Along Hole Components of Force

Along Hole Components of Force

Consider a short element of a BHA which has a weight W.
Effective weight in drilling mud = W(BF)
Component of weight acting along borehole = W(BF)cosq
If the BHA is not rotated, the force of friction, FFR acting up the borehole
on the BHA element is given by:
FFR = mN
...where m is the coefficient of friction,
N is the normal reaction force between the BHA element and the borehole
wall. If this normal reaction is due only to the weight of the BHA element
itself, then:
N = W(BF)sinq and hence
FFR = mW(BF)sinq
The net contribution to the WOB from this BHA element is therefore
WBIT = W (BF) (cosq - msinq)

Along Hole Components of Force

Torque & Drag

Torque & Drag

Several factors affect hole drag, including hole inclination, dogleg severity,
hole condition, mud properties, hole size, and drillstring component types,
sizes and placement. However, as mentioned earlier, in drilling situations
where the drillstring is not rotated (as when a steerable system is used in
the oriented mode) axial drag can become very significant and should be
evaluated using a Torque and Drag computer program. Torque and Drag
programs can be found in EC*Track and DrillByte.

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.

engineering information technology

Source of knowledge Engineering and information technology.

Pages

Use Of Torque & Drag Programs For BHA Weight Evaluation

Typical Drillstring - Wellbore Friction Factors

The E*C TRAK Torque and Drag Module

Computer Models of Drillstring Friction

Along Hole Components of Force

Along Hole Components of Force

Torque & Drag

Calculating BHA Weight With Drill Pipe In Compression - Summary

BHA Weight For Steerable Motor Assemblies

BHA Requirements When The Drillstring Is Not Rotated

Calculating BHA Weight With Drill Pipe In Compression

Calculating Critical Buckling Force

Running Drill Pipe In Compression

Required BHA Weight For Rotary Assemblies

BHA Weight & Weight-On-Bit

Labels

Engineering Blog Archive

Engineering Popular Posts