Use Of Torque & Drag Programs For BHA Weight Evaluation

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

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

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:

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.

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.

Tubulars - Make-Up Torque

Make-Up Torque


Part of the strength of the drillstring and the seal for the fluid conduit are
both contained in the tool joints. It is very important therefore, that the
correct make-up torque is applied to the tool joints. If a tool joint is not
torqued enough, bending between the box and pin could cause premature
failure. Also, the shoulder seal may not be properly seated, resulting in
mud leaking through the tool joint, causing a washout. Exceeding the
torsional yield strength of the connection by applying too much torque to
the tool joint could cause the shoulders to bevel outward or the pin to break
off the box. Recommended make up torques for drill pipe and tool joints
are listed in the API RP 7G.

Tubulars - Tool Joints

Tool Joints


Tool joints are short sections of pipe that are attached to the tubing portion
of drill pipe by means of using a flash welding process. The internally
threaded tool joint is called a “box”, while the externally threaded tool joint
if the “pin”.
API specifications also apply to tool joints:
• Minimum Yield Strength = 120,000 psi
• Minimum Tensile Strength = 140,000 psi
Because tool joints are added to drillpipe, the weight of given to pipe in
many tables is the “nominal weight”. The exact weight will require adding
the weight of the tool joints to the tubing portion. Since two joints do not
weigh the same, it is difficult to determine the weight of a joint of drillpipe
and so an “approximate weight” is used in many calculations.
The tool joints on drill pipe may contain internal and/or external upsets. An
upset is a decrease in the ID and/or an increase in the OD of the pipe which
is used to strengthen the weld between the pipe and the tool joint. It is
important to note that under tension, the tool joint is stronger than the
tubular.

Tubulars - Drill Pipe Classification

Drill Pipe Classification


Drill pipe class defines the physical condition of the drill pipe in terms of
dimension, surface damage, and corrosion. Drill pipe class is indicated by
paint bands on the drill pipe according to the following code:

Class 1 drill pipe is New and therefore the strongest. As pipe is used, the
wall thickness will be gradually reduced. This reduction of the drill pipe
cross sectional area results in a lower Total Yield Strength in pounds. This
yield strength in pounds can be calculated using the following formula:
YIELD STRENGTH = Yield Strength x p/4 (OD2 - ID2)
(in pounds)(in psi)

Tubulars - Drill Pipe Grades

Drill Pipe Grades


There are four common grades of drill pipe which define the yield strength
and tensile strength of the steel being used.


Grade E, composed of a lower grade of steel, is sometimes referred to as
“mild” steel, because it has the lowest yield strength per unit area. As such,
mild steel is generally defined as steel with a yield strength of less than
80,000 psi. As can be seen, Grade E drill pipe has a lower yield strength in
psi than the high strength drill pipe grades, however once the yield strength
is exceeded, it can withstand a greater percentage of stretch or “strain”
prior to parting. Lower grades of steel such as Grade E are also more
resistant to corrosion and cracking. Grade E has been utilized in medium
depth wells (10,000 to 15,000 feet).
In the 1980's, as horizontal drilling, high inclination extended reach wells
and deep hole drilling applications increased, so has the demand for high
strength drill pipe. It is common in deep hole applications for high strength
drill pipe to be utilized in the upper portion of the string to keep the tension
load within the capabilities of the steel. In high dogleg environments, such
as those encountered in medium and short radius horizontal wells, high
strength drill pipe can withstand the associated bending stresses. In high
inclination and horizontal wells, high strength drill pipe is also commonly
run in compression. One drawback of higher grades of steel is that they are
generally less resistant to corrosion, like that caused by hydrogen sulfide
(H2S). Limited availability also contributes to the higher cost.
The yield and tensile strengths are in “pounds per square inch of the cross
sectional area” of the drill pipe. In order to calculate yield strength in
pounds, this cross sectional area must be known. This leads to a discussion
of drill pipe classes.

Tubulars - Drill Pipe Yield Strength and Tensile Strength

Drill Pipe Yield Strength and Tensile Strength


If drill pipe is stretched, it will initially go through a region of elastic
deformation. In this region, if the stretching force is removed, the drill pipe
will return to its original dimensions. The upper limit of this elastic
deformation is called the Yield Strength, which can be measured in psi.
Beyond this, there exists a region of plastic deformation. In this region, the
drill pipe becomes permanently elongated, even when the stretching force
is removed. The upper limit of plastic deformation is called the Tensile
Strength. If the tensile strength is exceeded, the drill pipe will fail.
Tension failures generally occur while pulling on stuck drill pipe. As the
pull exceeds the yield strength, the metal distorts with a characteristic
thinning in the weakest area of the drill pipe (or the smallest cross sectional
area). If the pull is increased and exceeds the tensile strength, the drillstring
will part. Such failures will normally occur near the top of the drillstring,
because the top of the string is subjected to the upward pulling force as
well as the downward weight of the drillstring.

Tubulars - Introduction

Tubulars

Introduction

Drill pipe and collars are designed to satisfy certain operational
requirements. In general, downhole tubulars must have the capability to
withstand the maximum expected hookload, torque, bending stresses,
internal pressure, and external collapse pressure. Operational capabilities
of different sizes and grades of drill pipe and collars are tabulated in the
API RP 7G to assist the drilling engineer in selection of pipe and collars for
a given drilling situation. Other concerns, such as the presence of H2S,
must also be considered in the selection process.