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Bit Selection and Well Programming Bit selection is the heart of
Applications Engineering. But choosing the right bit is only the
first step. Optimum operating parameters must be specified and
performance predicted before the process is complete.
As described in this module, well programming is the
presentation of bit recommendations, supplemented with additional
information to assist the customer in deciding which bits to
choose, and guidance on how to achieve the best drilling
performance.
Learning Objectives Upon completion of this module, you should
be able to:
Define the information required to compile a set of bit
recommendations.
Explain bit selection criteria resulting from the influence
of:
geology,
drilling fluids,
directional drilling,
drilling dynamics, &
prior drilling history.
Make bit recommendations for any application.
Predict drill bit performance in an application.
Specify operating parameters for your bit recommendations.
Prepare bit recommendations in a graphical format.
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Introduction Each customer and application is different, so
every bit program needs to be constructed to meet the customer's
individual requirements.
The bit selection process varies in complexity from the customer
specifying exactly what bit he wants, to an in-depth study of all
aspects influencing the selection of the right bit for the
application.
This module outlines all the steps that could be required in
developing well programs tailored to your customers' needs. In the
field you may find that not all the steps detailed here are
necessary.
GATHER DATA:Well PrognosisMud ProgramDirectional PlanOffset Bit
RecordsOffset FRRsMud LogsElectric Logs
ANALYSE DATA
REQUEST
CUSTOMER
WELL PROGRAM Summary ofWell Data
BitRecommendations Predicted
Performance
OperatingParameters
Hydraulics EconomicsCalculation
OffsetInformation
ProductInformation
Pricing
DRILLING FLUIDSINFLUENCES
Mud TypeMud Weight
GEOLOGYINFLUENCES
Rock TypeStrength
AbrasivenessStickiness
PRIORDRILLING HISTORY
PARAMETERSRECOMMENDATION
BITSELECTION
Bit types usedPerformance standardsTypes of vibration
DIRECTIONAL DRILLINGINFLUENCES
Build & Walk rate reqd.Tangent angle
Drive type
Bit selection is at the heart of a processthat begins and ends
with the customer
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Bit Selection The two elements of bit selection are:
Gathering relevant information
Analyzing the information to make recommendations
Information The information required for selecting a bit for an
application falls into two categories:
Information concerning the proposed well
Offset information
The information about the proposed well describes the intended
characteristics of the well and the drilling process and techniques
that will be used to construct the well.
Offset information is taken from wells that have already been
drilled nearby and is by far the most important source of data to
indicate what can be expected during the drilling of the well.
Information Concerning the Proposed Well This comprises; the
well prognosis, the mud program and the directional plan. The
quality of the bit recommendations is dependent upon having
complete information on the proposed well. The information required
is:
the name of the operator or contractor
the name of the customer
the name of the proposed well
the location it is to be drilled in such as;
county
parish
state
offshore field
block number
hole sizes
casing setting depths and total depth (TD)
Bit Selection and Well Program
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a lithology column for the well
mud types to be used in each section
mud properties for each hole size from surface to total
depth
In directional wells;
the kick off point
rate of build
hole angle
end of build
any potential hole problems
Offset Information Useful information from offset wells is
gathered from:
Bit Records
Field Run Reports
Mud Logs
Electric Logs
Structure Maps
Maps of the proposed well areas are useful to pin point the
exact location and the offset wells that have been drilled in the
surrounding area. Offshore maps listing the fields and blocks are
also used to locate offsets in the area of interest and the
surrounding blocks. The numbering of sections on land and the
blocks offshore is not always in sequential order, making these
maps a valuable tool in locating and sorting the best possible
offset bit records.
When looking up offset Bit Records/Field Run Reports for the
proposed well always try to match hole sizes, lithologies, casing
depths and mud types and weights to the requested well profile.
Very often not all can be matched, but the more matches you can
find the more accurate the well program will be.
Offset Bit Records and Field Run Reports are only as accurate as
the information entered. These records and reports are the most
valuable tool in the preparation of a well program. The records are
pulled from our bit record files and database. To be of use to you,
the records and reports need to be in our database, and need to be
as complete as possible.
Mud logs are usually obtained from the operator and are
sometimes available from one of the local log service
companies.
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These logs are sometimes available from the operator who has
drilled wells in the area and is requesting the well program. The
electric logs can more often be obtained from the operator or local
log service companies if they have been released by the
operators.
Analysis Analysis of the information collected defines the
characteristics of the application. This will include:
drilling process to be used
desired outcomes for the well
drilling conditions likely to be encountered
standard products currently used in the application
standard performance achieved in the application
The aspects of the well which will influence the bit selection
for a given hole section are:
section length
drilling fluids
directional drilling
geology
drilling dynamics
prior drilling history
Section Length The length of section to be drilled may give rise
to the necessity for a compromise to be made between footage
drilled and rate of penetration. This could mean choosing a heavier
set bit (roller cone or fixed cutter), choosing an insert bit over
a tooth bit or a fixed cutter bit instead of a roller cone.
Drilling Fluids Information about the drilling fluid to be used
will be given in the well prognosis and mud program. This is
information about the process and techniques that will be used to
drill the well.
This may also represent information about desired outcomes of
the well. For example, the drilling fluid may be designed to be
non-damaging to the reservoir.
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The type of drilling fluid and its characteristics are usually
designed to satisfy requirements other than maximizing the rate of
penetration. This means that the nature of the drilling fluid will
be predetermined and the bit selection will need to be adapted to
the specified fluid.
Roller Cone Bits Drilling fluid does not significantly influence
either the choice of roller cone bit type or any design features
incorporated on the bit.
Fixed Cutter Bits PDC bit selection is influenced by the type of
drilling fluid used. Different choices may be made depending upon
whether oil based or water based mud is used. Water based mud does
not clean PDC bits as effectively as oil based mud does. This
becomes significant in hydrateable formations like clay or shale.
It is most significant when these formations are softer.
In these applications, PDC bits with less blades and/or larger
cutters than would be used in an oil based mud application should
be used. Fewer blades will mean that the bit will be lighter set,
which can be compensated for by using more wear-resistant cutters.
Another option may be to increase the junk slot area, while keeping
the blade count the same. This will improve the efficiency of
cuttings removal.
Directional Drilling Information relating to directional
drilling will be given in the well prognosis and directional plan.
This will include both desired outcomes for the well, like specific
build or turn rates and processes and techniques that will be used
to drill the well, like the type of drive to be used (downhole
motor or rotary).
The aspects of directional drilling that will influence the bit
selection are:
the requirement to change azimuth (hole direction) in rotary
applications
the rate of build or turn required
the type of drive system to be used
the type of steerable motor used
If rotary assemblies are to be used and a change in azimuth is
planned, a bit with a specific walk tendency may be required.
Roller cone bits tend to walk right in most applications. The walk
tendency of a fixed cutter bit varies depending on its profile and
gauge length.
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It should be noted that the formation dip and the bottomhole
assembly (BHA) configuration also affect the walk tendency. The
formation dip can have a strong effect on the walk tendency, often
over-riding the natural walk tendency of a bit.
The rate of change of build or turn required could influence the
bit selection. Roller cone bits will all tend to exhibit similar
build and turn characteristics, dependent on the BHA rather than
differences in the bit design. The build and turn rates achievable
with fixed cutter bits will be dictated by design aspects of the
bit.
Most roller cone and fixed cutter bits will be capable of
holding angle in a tangent section, provided an appropriate BHA is
used.
All roller cone and PDC bits can be run on rotary. Some natural
diamond and TSP fixed cutter bits are best run on a downhole motor,
particularly those with smaller diamonds (e.g. impregnated
bits.)
There is a limit to the rotary speed that can be used with
roller cone bits. This means that they are not suitable for use on
motors that operate at high rotary speeds. This applies to some
turbines and some PDMs. Similarly, flatter profile fixed cutter
bits are not suited to high RPM motors.
When a PDC bit is used with a downhole motor it exerts a
reactive torque on the motor. This is due to the cutting action of
the bit which fails the rock by shearing. Reactive torque causes
the body of the motor to turn by a certain amount to the left. This
causes the toolface to turn also. The toolface is what the
directional driller uses to determine the direction the well is
going.
If the on-bottom torque while drilling varies, the toolface will
swing erratically from left to right. This makes it very difficult
to steer the well in the right direction.
When a downhole motor is to be used for directional work in
softer formations, the likelihood of an erratic toolface will be
higher if lighter set PDC bits or PDC bits with larger cutters are
used. The bit selection should take this into account and avoid it
if possible.
Directional work using a downhole motor involves a bend in the
BHA. This could be above the motor or on the motor body. The bend
offsets the drill bit so that it contacts the wall of the hole.
This imparts side force to the bit proportional to the amount of
offset. The side force is necessary for the bit to drill
directionally but can affect performance or at worst damage the
bit.
Fixed cutter bits, particularly those with a rounded profile
suffer least under these side loading conditions.
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Geology The sources of information for an analysis of geological
considerations are:
Bit Records
Field Run Reports
Mud Logs
Electric Logs
The aspects of geology the influence bit selection are the rock
properties of:
hardness
abrasiveness
stickiness
A standard classification of rock compressive strength is given
in the "Engineering Classification for Intact Rock" as shown in the
table below.
Engineering Classification for Intact Rock
Classification Compressive Strength (psi) Very Low Strength <
4,000 Low Strength 4,000 - 8,000 Medium Strength 8,000 - 16,000
High Strength 16,000 - 32,000 Very High Strength > 32,000
Reference: Deere, D.U., and Miller, R.P., "Engineering
Classification and Index Properties for Intact Rock", Report No.
AFWL-TR-65-116, U.S. Air Force Weapons Laboratory, Kirtland Air
Force Base, New Mexico, 1966, p 137.
Roller Cone Bit Selection A general correlation between the
standard IADC bit codes and rock strength is given in the following
table:
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Fixed Cutter Bit Selection A general guide to cutter selection
is
provided. Note that bit design, bit size, and formation
abrasivity are not taken into account.
Classification Mill Tooth
TCI EB TCI
Very Low Strength 1 Low Strength 1,2 4,5 4,5 Medium Strength 2,3
5,6 4,5,6 High Strength 3 6,7 5,6,7 Very High Strength
8 8
Bit Selection and Well Program
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Classification Compressive Lithology Cutter Type Strength (psi)
Type
Very Low Strength < 4000 Anhydrite PDC Chalk PDC Salt PDC
Sandstone PDC Shale PDC
Low Strength 4000 - 8000 Anhydrite PDC Chalk PDC Limestone PDC
Salt PDC Sandstone PDC Shale PDC
Medium Strength 8000 - 16000 Anhydrite PDC Basalt Nat. Dia.
Chalk PDC Dolomite TSP/PDC Limestone TSP/PDC Sandstone TSP/PDC
Shale TSP/PDC Volcanic Tuff Nat. Dia.
High Strength 16000 - 32000 Basalt Nat. Dia./Impreg. Dia. Chert
TSP/Nat. Dia./Impreg. Dia. Dolomite TSP/Nat. Dia./PDC Granite
TSP/Nat. Dia./Impreg. Dia. Limestone TSP/Nat. Dia./PDC Quartzite
TSP/Nat. Dia./Impreg. Dia. Sandstone TSP/Nat. Dia./PDC Shale
TSP/Nat. Dia./PDC Volcanic Tuff Nat. Dia./Impreg. Dia.
Very High Strength >32000 Basalt Nat. Dia./Impreg. Dia. Chert
Nat. Dia./Impreg. Dia. Dolomite Nat. Dia./Impreg. Dia. Granite Nat.
Dia./Impreg. Dia. Limestone Nat. Dia./Impreg. Dia./PDC Quartzite
Nat. Dia./Impreg. Dia. Sandstone Nat. Dia./Impreg. Dia./PDC Shale
Nat. Dia./Impreg. Dia./PDC Volcanic Tuff Nat. Dia./Impreg. Dia.
Bit Selection and Well Program
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Drilling Dynamics The occurrence of vibration during drilling in
an application may be detected from bit records, field run reports
or electric logs. It is important to determine if vibration is
likely to occur and if so, what kind of vibration it is. The table
below gives ways of detecting different types of vibration.
Real Time Torque Fluctuation Slip Stick
>Torque Cyclicity Slip Stick
>MWD Shocks Slip Stick BHA Whirl
>Torque Cyclicity BHA Whirl Bit Whirl
High Freq. D/H Lat./Tor. vibration BHA Whirl Bit Whirl
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justify bit selections and demonstrate superior levels of
performance to the customer.
The analysis of Bit Records or Field Run Reports can be broken
down into a series of steps:
Comparison of bit types
Comparison of drilling performances
Selection of the proposed bit
Prediction of the performance of the proposed bit
Specification of the operating parameters for the proposed
bit
Comparison of Bit Types Hundreds of Roller Cone and Fixed Cutter
bit designs are commercially available for oilfield use. Four major
manufacturers market competitive product lines of 1000 or more
distinctly different bits. Several smaller manufacturers produce at
least 100 additional bits. Why are there so many bit designs? The
following explanation was published over 30 years ago but it
remains equally true today:
The efficiency of any drilling operation depends largely upon
the choice of a bit type most suitable for a given set of
conditions. Differences in information and drilling techniques
require a large number of bit types for optimum results.
In the past, the industry was also guilty of making changes
without a full analysis of the requirements and solutions required.
We also need to better evaluate dulls and performance from a true
system perspective.
Roller Cone Bit Comparison The history of roller cone bits
reveals a decades-long evolution of technical ingenuity applied to
drilling holes in the earth. At least three factors typify this
period:
Every new drilling environment results in the development of new
bit designs
New generations of better bits are introduced much more
frequently due to new application design and software
improvements.
As the new bits replace older designs, step change development
is increasing in pace. Educating all concerned on the real issues
has helped accelerate the pace of new developments.
Bit Selection and Well Program
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Bit Design The primary design factors to be considered in roller
cone bit comparisons are:
Tooth Extension
Tooth Shape
Number of Teeth
Insert Diameter
Insert Material
Bottom Hole Profile
Cone Offset
Hydraulic Design
Hard Facing Material
Age of Design
Tooth Extension Longer Teeth allow the teeth to penetrate
through un-removed cuttings and filter cake on bottom and transfer
weight to the tips of the teeth contacting un-fractured rock. Under
perfect hydraulic cleaning conditions, small differences in
projection should not affect ROP. However, in most field
situations, hydraulic cleaning is a factor and more projection
provides higher ROP.
Tooth Shape Tooth shape affects ROP by virtue of the
relationship between cross sectional area of the tooth in contact
with the rock at a given penetration of the tooth into the rock.
The sharper tooth presents a smaller cross sectional area at a
given depth of penetration providing a higher stress on the rock
for a given weight supported by the tooth. This higher stress
fractures a larger volume of rock and makes a bigger crater at each
tooth impact.
Number of Teeth Number of teeth on the bit affects ROP in two
ways:
More teeth, closely spaced, increases the balling tendency of
the bit
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The more teeth on the bit, the more teeth in contact with the
formation at any time sharing the available WOB.
This reduces the weight applied to each tooth and reduces stress
on the rock producing smaller craters. On the other hand, more
teeth provide more tooth impacts per revolution, thereby creating
more craters per revolution.
The net effect of more teeth is generally less ROP since the
reduction in stress per tooth is more important (volume of crater)
than the increase in number of craters formed per revolution. The
obvious correction for a bit with more teeth is to run more WOB to
increase the weight per tooth.
Cone Offset Larger cone offset or skew (refer to Chapter3,
Roller Cone Bit Product Knowledge) increases ROP by emphasizing the
dragging action of the bit teeth. This dragging action helps remove
broken rock chips from the craters formed by the stress applied to
the rock. It is important in soft formations where the chip
formation rate is high or in highly overbalanced conditions where
chip removal is difficult due to high chip hold down forces. Larger
Cone offset will mean greater wear on the gauge of the bit. When
comparing bit performances, cone offset needs to be similar to have
a more valid comparison.
Comparison using the IADC Classification IADC classification
assigned to the design is based on count, extension, offset,
journal angle, and considered application relative to formation of
competitors designs. This procedure is at best a guess.
Thus, the I.A.D.C. classification chart for bit selection should
only be used as a guideline. A more precise method is by design
profile comparison.
Profile/Competitive Product Sheet These are available for many
of Security DBS products, but if not they can be obtained at the
field stock-points or on location. Instruments used to measure the
relevant bit design features are:
depth gauge
circle templates
radius gauge
caliper
gauge ring
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machinist measuring rule
Bit Selection and Well Program
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Product Profile Sheet - Roller Cone Bit
Bit Selection and Well Program
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Completing Product Profile Sheets for competitor products can
provide useful information to determine possible strengths and/or
weaknesses and more so, to make bit selection a science.
Problem: Offset bit records show that a Smith 7 7/8" F7 was run
for a certain interval. Performance and dull conditions were
acceptable. The customer likes Security DBS and wants to know what
your recommendation would be. The F7 is 7-3-7-Y. What would be your
best selection based on the following:
Bit type
IADC Code
Total Count
Gauge Count
Ext. Insert Shape
Offset
F7 7-3-7Y 144 46 .250 DC 0 XS87 7-4-7Y 156 53 .220 DC 1 XS73
7-1-7Y 150 49 .250 DC 1 XS69 6-4-7Y 150 49 .250 DC 2
Based on the comparisons, the choices would be the XS73
(I.A.D.C. 7-1-7Y) or XS69 (I.A.D.C. 6-4-7Y) based on count,
extension, and offset. NOTE:
Even though the XS87 (I.A.D.C. code 7-4-7Y) would be the likely
choice based on the I.A.D.C. classification chart, penetration rate
would probably have suffered due to the increased insert count.
The major design factors for competitive bits obtained from the
Product Profile Sheets can be listed in chart format to facilitate
comparison.
The more we know about our products, as well as those of the
competition the better prepared we will be to perform our job
functions. Customer acceptance and perception will be enhanced as a
result.
It is strongly recommended that bit design data be accumulated
in area, and distributed to all sales personnel as a technical
sales tool. In conjunction, the sales force would benefit from
training in gathering the preceding design criteria.
Fixed Cutter Bit Comparison The fixed cutter bit design aspects
that should be considered when comparing performances on a Bit
Record or Field Run Report are:
Cutter count
Cutter size
Cutter type
Blade count
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Hydraulic configuration
Junk slot area
Profile
Cutter Count The cutter count indicates how heavily set the bit
is. When comparing fixed cutter bit runs on a Bit Record or Field
Run Report, the bit with less cutters (providing they are of
similar size and type) will usually have a higher rate of
penetration. Normally, this will be at the expense of bit life
normally.
Cutter Size For a given bit diameter, larger cutters take up
more space, therefore there are less of them. This means that if
you compare two bits of the same diameter having different sized
cutters, the one with larger cutters will drill faster.
Cutter Type There are numerous variations of PDC cutters and
different grades of natural diamond cutters. The cutter type should
be checked when making performance comparisons between bits to
ensure that an apples to apples comparison is being made. Security
DBSs PDC cutters types and their main characteristics are listed
below along with our competitors premium offerings.
Security DBS Cutter Characteristic Ring Claw High impact
resistance with standard
abrasion resistance. Z3 Good impact resistance with industry
leading abrasion resistance and thermal mechanical
integrity.
Competition Competitor Premium Offering Hughes Christensen
Zenith
Hycalog
T-Rex
GeoDiamond H.O.T.
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Blade Count The lower the number of blades on a PDC bit, the
better its cleaning characteristics. This will translate to higher
rates of penetration. Compare blade count on bits in similar
applications to see if this accounts for differences in
performance.
Hydraulic Configuration The hydraulic configuration of a fixed
cutter bit determines how efficiently the cuttings are removed from
the bit face. The better the cleaning, the faster the bit will
drill. The hydraulic configuration of a PDC bit is the relationship
between the number of nozzles and the number of blades. An
optimized configuration is one (or more) nozzle per blade. When
comparing PDC bits, check the number of nozzles and the number of
nozzles per blade.
There are two main types of hydraulic configuration for surface
set bits, radial flow and crossflow. These should be match for
valid comparisons of surface set bits.
Junk Slot Area Bits with the same number of blades may have
different junk slot areas. The bit with the larger junk slot area
is likely to exhibit better cleaning characteristics, particularly
in WBM applications when soft clay or shale is being drilled.
Profile The profile of a fixed cutter bit is a very significant
feature which influences; rate of penetration, bit life, dynamic
stability and steerability. In comparing fixed cutter bit
performances, it is essential to check how the profiles of the bits
being compared match. The closer the match, the more relevant the
comparison will be.
Comparison of Drilling Performances With the comparison of
drilling performances you are looking for like bit types achieving
similar performances.
Carefully review the offset records, comparing rates of
penetration footage drilled, hours on the bit (mainly for roller
cone bits) and dull conditions. The bit dull grading information on
a bit record is a very important aspect of the performance of
offset bit runs. The drilling parameters used for each run; weight
on bit, rotary speed and flow rate should be checked for
differences that could account for differences in performance.
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Always examine the runs for building or dropping angle, because
the rate of penetration will almost always be lower when
directional work is being done.
Check the formations listed and any remarks that are listed next
to the run.
Grouping two or three bit runs or a certain footage interval can
give you a better picture of what bit to recommend. Go through each
individual bit run on all the offset wells for the different hole
sizes being programmed. A good bit selection depends upon the
results of the comparisons made.
This analysis establishes the benchmark performance for the set
of offset information used. The benchmark performance is the
performance that, based on your analysis of the offset Bit Records,
you consider the standard for the application. The accuracy of this
assessment is entirely dependent on the amount and quality of the
data you have used.
The bit type that, as a result of your analysis, has been
established as the standard for the application can be used as the
basis of your bit selection. The next step is to assess the
suitability of this bit in relation to the other factors that
influence bit selection.
If your final bit choice matches the bit type that you
established as the standard for the set of offset information you
analyzed, the average performance achieved for that bit and the
operating parameters used can form the basis of your performance
prediction and parameter recommendations.
Establishing the benchmark performance for specific bit types in
similar applications allows performance comparisons to be made.
These comparisons strongly influence the customers bit choice
Bit selection is the analysis of well and drilling process
information in relation to drill bit design. The quality of the
final bit recommendations is dependent upon the quantity and
quality of the information available for analysis.
The bit recommendations you make will be tailored to your
customers requirements. It is important that you know what these
requirements are before you try to put together your
recommendations. A clear understanding of what the customer
considers a good performance is necessary if you are going to put
together a successful bit program for his well.
Be aware that good performance can relate to aspects such as
well quality or directional objectives and not simply rate of
penetration and bit life. Also try to assess his level of
satisfaction with bit performance in recent offset wells. Your
objective may be to match a previous performance or surpass it if
the customer considers the previous efforts inadequate.
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Well Programming The information supplied in the well program
should match the customers requirements. This will mean that
individual programs will differ in appearance and style. Whatever
information the customer requires in your proposal, it should be to
a high standard of presentation. It is strongly recommended to use
one of the various spreadsheets, graphics programs or custom
written software available for the purpose.
A complete well program will contain the following:
Summary of well information supplied, including
Lithology column
Casing program
Mud program
Directional plan
Bit Recommendations, including
Predicted performance
Recommended operating parameters
Hydraulics calculation and recommended nozzle sizes
Economics calculation
Offset information used for analysis
Product information, including
Bit specifications
Photographs
Pricing information
The summary of well information allows the customer to verify
that your understanding of the application and that your
recommendations are based on the actual circumstances of his
well.
A single page with the information represented graphically and
in color is the most effective way of presenting the summary of
well information, bit recommendations, predicted performance and
recommended operating parameters.
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Various hydraulics programs exist. Use the one that best suits
your customers needs.
An economics calculation is an excellent way of justifying the
selection of a Security DBS bit in preference to one from a
competitor. The economics calculation may also be used to propose a
fixed cutter bit to replace several roller cone bit runs.
The credibility of your recommendations will be enhanced by
including the offset records used in your analysis of the
application. This allows the customer to see what has been used
before in the application giving him confidence in your bit
selection.
Inclusion of product information is very important. It allows
the customer to make comparisons with other products being
recommended. Make sure that design features differentiating your
recommendation from that of a competitor are highlighted.
Finally, every customer will be interested in knowing the
price.
Bit Selection and Well Program
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Learning ObjectivesIntroductionInformationInformation Concerning
the Proposed WellOffset InformationAnalysisSection LengthDrilling
FluidsRoller Cone BitsFixed Cutter BitsDirectional
DrillingGeologyEngineering Classification for Intact RockRoller
Cone Bit SelectionFixed Cutter Bit SelectionDrilling DynamicsPrior
Drilling HistoryComparison of Bit TypesRoller Cone Bit
ComparisonBit DesignTooth ExtensionTooth ShapeNumber of TeethCone
OffsetComparison using the IADC ClassificationProfile/Competitive
Product SheetFixed Cutter Bit ComparisonCutter CountCutter
SizeCutter TypeBlade CountHydraulic ConfigurationJunk Slot
AreaProfileComparison of Drilling PerformancesWell Programming