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: ¾ geology,
¾ drilling fluids, ¾ directional drilling, ¾ drilling dynamics, & ¾ 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.
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 Prognosis Mud Program Directional Plan Offset Bit Records Offset FRR’s Mud Logs Electric Logs ANALYSE DATA REQUEST CUSTOMER WELL PROGRAM Summary of Well Data Bit Recommendations Predicted Performance Operating Parameters Hydraulics Economics Calculation Offset Information Product Information Pricing DRILLING FLUIDS INFLUENCES Mud Type Mud Weight GEOLOGY INFLUENCES Rock Type Strength Abrasiveness Stickiness PRIOR DRILLING HISTORY PARAMETERS RECOMMENDATION BIT SELECTION
Bit types used Performance standards Types of vibration DIRECTIONAL DRILLING
INFLUENCES Build & Walk rate reqd.
Tangent angle Drive type
Bit selection is at the heart of a process that begins and ends with the customer
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; ¾ county ¾ parish ¾ state ¾ offshore field ¾ block number hole sizes
casing setting depths and total depth (TD)
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;
¾ the kick off point ¾ rate of build ¾ hole angle ¾ 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.
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.
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.
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 PDM’s. 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.
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:
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
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.
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
<ROP Bit Whirl Bounce WOB Fluctuation Bounce
Surface Vibration Bounce
Post Run
Conn. Over torque/Back off Slip Stick
Twist off/Washout Slip Stick BHA Whirl Bounce Cutter impact damage Slip Stick Bit Whirl Bounce Over gauge hole Bit Whirl
Tool joint wear BHA Whirl Stabilizer damage BHA Whirl
4
If vibration is likely to occur in an application, an inherently stable bit design may be selected, or vibration reducing features may be applied to an existing design (refer to Drilling Dynamics Chapter).
Prior Drilling History
Analysis of offset Bit Records and Field Run Reports establishes the product type and drilling performance “standards” for the application. This contributes to bit selection, enables performance predictions to be made and can give guidelines for recommended operating parameters. This analysis is also used to make product performance comparisons with the competitors bits. These comparisons are very useful in bit proposals to
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 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
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 competitor’s 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
machinist measuring rule
Product Profile Sheet - Roller Cone Bit
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. 6-4-7-1-7Y) 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
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 DBS’s 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.
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.
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 customer’s 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 customer’s 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.
Well Programming
The information supplied in the well program should match the
customer’s 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
¾ Lithology column ¾ Casing program ¾ Mud program ¾ Directional plan
Bit Recommendations, including ¾ Predicted performance
¾ Recommended operating parameters
Hydraulics calculation and recommended nozzle sizes Economics calculation
Offset information used for analysis Product information, including
¾ Bit specifications ¾ 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.
Various hydraulics programs exist. Use the one that best suits your customer’s 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.
