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Engineered Bit Design and Drilling Parameters Mark Breakthrough Drilling
Performance in Interbedded Damaging Carbonates
Waleed Agawani, Baker Hughes; Abdullah M. Al-Ajmi, Kuwait Oil Company; Wasim Fawaz, Baker Hughes;
Abdulaziz Al-Rushoud, Kuwait Oil Company; Mehul Pandya, Baker Hughes; Hussain Ali Al-Haj, Kuwait Oil
Company; Atef Abdelhamid, Baker Hughes; Mohammed El-Sherif, Kuwait Oil Company
Copyright 2017, Society of Petroleum Engineers
This paper was prepared for presentation at the SPE Kuwait Oil & Gas Show and Conference held in Kuwait City, Kuwait, 15-18 October 2017.
This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents
of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect
any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written
consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may
not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.
West Kuwait's 22-in. section comprises a vertical hole through 3,500 feet of interbedded carbonates
varying significantly in compressive strength, and drilled commonly with minimal or no fluid returns. The
section is typically drilled with roller-cone tungsten carbide insert (TCI) bits because large polycrystalline
diamond compact (PDC) bits are extremely costly and require expensive performance motors to support
their generated torque. PDC bits are also at risk of impact damage when drilling through the interbedded
formations in this interval. Operators tend to apply higher drilling parameters while in the lower compressive
strength intervals to achieve higher rates of penetration (ROP). Consequently, when the TCI bit enters the
following harder formations with the same high operating parameters, it often suffers severe cutting structure
damage. The result is reduced ROP. Greater weight on bit is then applied, causing further bit damage and
possible sealed bearing failure.
An engineering project was launched to develop a TCI bit specifically for the interbedded carbonates of
this section. The primary challenges of the project were:
Ensure the bit finishes the section in one run
Improve dull condition of bit coming out of hole
Surpass current field average ROP consistently
Maintain efficient cleaning at lower flow rates for drilling in complete fluid-loss scenario
Based on data and experience in drilling the application, an engineering process took place where several
designs improvements with potential to improve performance were identified and trialled. Field engineers
then worked onsite to identify how to drill the interval with optimal parameters for each sub-layer. The
final design included:
Specialized TCI cutting structure for carbonate drilling
High impact-resistant insert geometry
Simulated hydraulic efficiency to improve hole cleaning
Improved high aspect ratio elastomer seals designed to endure longer runs
Specialized tungsten carbide to improve cutting structure durability
The engineering process yielded a design that successfully drills the complete section in one fast run the fastest of the section - with an improved field average penetration rate to 63%, saving the operator more
than 38% in associated cost for drilling the section. The application-engineered cutting structure enabled
the use of lower drilling parameters than normal, thereby improving drilling efficiency and enhancing the
post-drilling dull condition from the average of 3-3-BT to 1-2-WT.
The paper shows a case study in Kuwait demonstrating the engineering and results of designing a TCI
bit matched to application.
Application Summary
This paper discusses the 22-in. section that spans a vertical interval of ~4,000 ft. of primarily carbonate
formations. Table A-1 summarises the lithological breakdown of the column drilled. Formation unconfined
compressive strengths (UCS) typically range from 15 to 35 Kpsi. Due to the interbedded nature of some
intervals and the varying UCS of different formations, bits drilling the section typically face impact forces
that can be detrimental to the cutting structure. Due to these forces the bits are subjected to the section
characteristically require a minimum of two bit runs to complete. The initial bit run's ROP drops because
cutting structure suffers damage, necessitating a bit trip to continue the section.
Table A-1—Lithological Breakdown of Section
Fluid System
One of the challenges in the section involved drilling with partial or complete losses. To avoid losing
expensive oil-based muds, water-based mud is used with a typical mud weight of 8.9 ppg maintained
throughout the section. Severe circulation loss reduces flow rates and lowers the mud levels, resulting in
lower hydraulic cleaning efficiency of cutting structure. The compounded issues of limited flow rate and
water-based mud in presence of shale beds caused partial balling on bit cutting structure.
Bottom Hole Assembly
As the interval drilled involved a vertical hole, the bottom hole assembly (BHA) was a packed 3 full gauged
stabiliser rotary BHA:
22-in. bit with a full-gauge near-bit stabilizer
12-in. shock sub with a full-gauge string stabilizer
9.5-in. drill collar (29 ft.) with a full-gauge string stabilizer
9.5-in. drill collars
Operator Objectives
The operator's main objective was to reduce the financial and temporal overhead in drilling the section. In
this application two main goals were set to meet this objective:
Complete section in one run consistently – The section typically requires two bit runs to complete,
costing the operator one trip per well. By eliminating one trip, the time and cost of trip time plus an additional
bit's expense are eliminated.
Maintain or improve cost per foot (CPF) – A heavier set bit may improve overall durability but may
drill more slowly; hence taking as much time as it takes to drill the interval with two bits with minimal
overall benefit. The goal here was to sustain drilling performance by remedying issues faced while drilling
and improving durability to complete the section in one run, thus the need for minimizing insert breakage
without increasing the insert count.
Solution Development Process
The process of improving performance involved analysing current runs and identifying performance limiters
and proposing solutions to remedy them. Data were gathered from various sources and analysed to identify
challenges preventing the goals from being achieved:
Dull grading of bits. Post-run bit dulls of current designs were reviewed to identify repeat failure
patterns and the types of wear faced across several bit designs. This review and other data enabled
the inference of the causes of breakage and decisions on the best approach to address it.
Rates of penetration and distance drilled by current designs. Cutting structure and cutter types of
longer runs were reviewed and compared with faster runs to optimise a design that would achieve
acceptable ROP while drilling extensive footage.
Surface parameters used in drilling the section.
Uncompressive strength analysis. Correlate formation hardness with other logs to better understand
bit behaviours in various formations.
Terminal Formations
Fig. B-1 plots several offset runs with older 22-in. TCI designs. From the figure, most runs terminated
in the transition zone between the Tayarat and Hartha. The Tayarat is a loss-prone formation, which can
mean drilling through inconsistent bottom-hole formations. This would cause drilling instability and result
in impact damage. Hartha has a typically high compressive strength (30+ Kpsi) that can further deteriorate
cutting structure and cause impact damage.
Figure B-1—Previous Design Run Depth Drilled
Bearing Life
TCI bit bearings are rated to a recommended maximum number of rotations as a safety margin before
bearings have higher potential of failure. This is based on engineering knowledge and field experience
from running the bits equipped with the bearings in the given application. Where ROP is reduced in longer
intervals, bearings are subjected to longer drilling times that can push the total revolutions on a bit beyond
its recommended bearing life.
In this particular application the interval is relatively long, and bits complete their runs nearing the end
of their recommended limits. For various reasons ROP may decrease, thereby pushing the bit beyond the
recommended range and result in bearing failure. Drilling with a failed bearing can result in severe damage
to the cutting structure similar to that seen in Fig. B-2. In this example the bearing has seized, resulting in
dragging the cone across the bottom-hole surface.
Figure B-2—Example of Cutting Structure Damage from Bearing Failure
Impact Damage
The primary types of damage seen on most post-run dull gradings of bits in this section were broken or
chipped teeth. This type of damage is typically seen when the cutting structure sustains impact loading
during drilling. Causes of impact damage in this application can be attributed to interbedded formations and
incorrect drilling parameters applied while drilling. Fig. B-3 is displays typical examples of impact damage
seen on post-run cutting structures.
Figure B-3—Impact Damage on Cutting Structure – Broken Inserts
Broken teeth damage typically begins in one row and then spreads to the closest offset row in
neighbouring cones. When a row is compromised, the result affects the remaining cutting structure in
two ways. First, the reduced number of inserts in the row causes the remaining inserts to work harder to
compensate. Secondly, the large broken inserts may become junk on the hole bottom, which can cause
further broken inserts across the cutting structure. In general, ROP drops quickly after a cutting structure
is compromised.
Uneven Wear
Typical post-run analysis of a drill bit that had been drilling efficiently tends to show uniformly distributed
wear across the cutting structure, with areas of the bit exposed to greater work showing higher indications
of wear. Uneven wear indicates abnormal drilling and the distribution of the wear on the cutting structure
can sometimes reveal the possible cause of the damage.
A phenomenon seen in some post-run dull inspections is that the inner rows suffered insert breakage
while outer cutting structure is still intact, such as that displayed in Fig. B-4. This type of irregular breakage
is sometimes seen when improper parameters, such as excessive WOB, are applied resulting in inefficient
Figure B-4—Non-Uniform Wear on Inner Cutting Structure
Balled Cutting Structure
In some cases bits came out of hole with a partially balled cutting structure. This is another challenge
observed in the section as it crosses shale beds and in the event of lost circulation, flow rates are reduced
to maintain drilling fluid levels. Even with full circulation rates, the hydraulic horsepower per square inch
(HSI) is typically quite low (< 0.5 hp/in2) on large diameter bits such as the subject 22-in bits. Both issues
result in an increased chance of cuttings accumulating on the cutting structure and reducing its drilling
Typical nozzle configuration on larger bits in this kind of application would involve three outer nozzles
and one centre nozzle focused on the inner portion of the cutting structure. Due to the size of the bit in
question, this kind of configuration may not sufficiently cover the bits cutting structure. Consequently, a
customized nozzle configuration may be required to maintain sufficient cone coverage cleaning efficiency.
Parameter Review
Drilling across varied lithologies requires varying parameters to maintain efficient drilling performance. The
effect of parameters used in drilling formations in reference wells were compared with the ROP achieved
in each formation and the post-run dulls of the bits. Reference wells were selected for a variety of scenarios
where different parameters were applied to better evaluate the effect of parameters and come to a conclusion
on how to optimise them.
The well referenced in Table B-1 started with conservative parameters that were progressively increased
throughout the run. While ROP in most formations was relatively higher overall throughout the run than
other reference wells, the parameters trended similar to the results from other offset wells. Because no losses
were encountered in the run, the GPM could be maintained higher, which may have aided hole cleaning
and sustained ROP. In the transition zone between the Tayarat and Hartha formations the relatively high
WOB and RPM were maintained but the ROP dropped considerably, ending the run. The post-run inspection
revealed impact damage across the entire cutting structure that would have caused the drop in ROP near
the end of the run.
Table B-1—Reference Well 1 Parameter Breakdown
The second reference well (Table B-2) involved high parameters applied throughout the run. Overall ROP
was significantly improved, particularly in softer formations; however the run terminated before reaching
Hartha formation and with substantially worse post-run dull condition. ROP dropped considerably in the
transition zone between the Tayarat and Hartha until it wasn't economically feasible to continue drilling.
Table B-2—Reference Well 2 Parameter Breakdown
Reference well 3 (Table B-3) had average parameters applied throughout the section that were managed
carefully through the transition zones. Fluid losses were encountered in the transition between the Rus and
Radhuma and in the Tayarat, resulting in reduced GPM that improved late in the run. Relatively lower
drilling torque was observed at the start of the run, but this increased later in the run as GPM was reduced.
Post-run dull analysis showed the bit had reduced damage in comparison with offset runs that may be
attributed to the carefully managed parameters through the transition zones.
Table B-3—Reference Well 3 Parameter Breakdown
Well 4 referenced in Table B-4 represents a scenario where conservative parameters are observed
throughout the run. Although post-run dull conditions were improved, the overall ROP was relatively lower
compared to offset runs.
Table B-4—Reference Well 4 Parameter Breakdown
In cases where parameters were optimised through maintaining conservative parameters across transition
zones and in harder formations the post-run dulls were better. Maintaining conservative parameters
throughout the run as in reference well 2 resulted in the best post-run dull, but the section ROP was relatively
low in comparison to the other wells which used more aggressive parameters. A relationship between higher
flow rates and lower drilling torque was observed that resulted in improved ROP. This can be attributed
to higher flow rates improving hydraulic cleaning and thus reduced bit balling that lowered drilling torque
and improved performance.
New Bit Design
Typically, bits used in carbonate formations exhibit different drilling characteristics, which often lead to
compact chipping and breakage. Large-diameter bits with relatively high seal sliding speeds as compared to
smaller diameter bits suffered too because they endured more wear on elastomer seals. In addition, because
of the relatively high distance between the nozzle exit and bottom hole, large-bit hydraulics are often less
effective in achieving sufficient bit and/or hole cleaning. The application-specific TCI bit blends specific
features with tougher, impact-resistant carbide grades, innovative compact shapes and advanced cutting
structures and hydraulics designed specifically to combat these challenges.
After reviewing previous bit performance in this application and inspection of dull bits, the following
design features were considered when designing the new TCI bit for the application:
Engineered Compacts
The previous bit design utilized a typical carbonate drilling grade that still encountered breakage in almost
all locations on the bit. To support the durability of the inserts on the new TCI design while keeping the
aggressive chisel-shaped inserts, tougher carbides that better resist thermal fatigue and minimize insert
breakage had to be utilized (Fig. D-1), increasing achievable footage and ROP. Varying the grain sizes and
compositions of the tungsten carbide crystals and the cobalt binder content yields different carbide grade
material properties, and when matched with aggressive tooth shapes, may extend bit life in applicationspecific runs. uns.
Figure D-1—Toughness vs. Wear Resistance for Drill Bit Tungsten Carbide Grades
Robust Seal Geometry
The geometry of previous O-ring elastomer seals was not optimised for long drilling hours and highWOB applications. The movement and twisting of the O-ring seal against the internal cone seal recess
may accelerate wear and increases the likelihood of bearing seal failure. On this TCI bit, a high aspect
ratio (HAR) elastomer seal was added to the already field-tested precision bearing. Thanks to their unique
geometry, HAR seals maintain greater sealing integrity than O-ring seals when subjected to identical drilling
conditions. Stabilizing ribs or rings were also specified to maintain the optimal seal position within the cone
seal recess for long seal life and reliability. (Fig. D-2). The result was significantly longer seal life in a
bearing designed for maximum load capacity in both rotary and motor applications.
Figure D-2—High Aspect Ratio Seal
Computer Modelled Insert Arrangements
When designing the cutting structure, engineers used computer modelling to statistically improve resistance
to tracking (Fig. D-3). Tracking occurs when compacts consistently fall into previously cut formation,
this results in lower ROP and higher vibrations. The spacing of the inserts was optimized to eliminate bit
tracking, reduce cutter damage and improve penetration rate. Moreover, the placement of the inserts was
optimized to deliver superior borehole quality via consistent 2D bottom-hole coverage that ensures efficient
rock removal.
Figure D-3—Tracking of Inserts vs. Cutting (No Tracking)
Bit Hydraulics
The size of the bit and the application dictates that flow reaches all parts of the bit and hole. The new
TCI design positions three jets in the centre of the bit aimed at the upper side of all three cones, thereby
improving cleaning efficiency and reducing bit balling. Each of the centre jets is equipped with its own
nozzle for more effective flow to reduce bit balling than can be achieved with a single-centre jet nozzle.
Improved hole cleaning and coverage translates into faster ROPs and less risk of bit balling, especially in
a low HSI environment. Moreover, computational fluid dynamics further improved hydraulic efficiency by
minimizing body erosion and blind spots (Fig. D4)
Figure D-4—Computational Fluid Dynamics module
Bit Body Hardfacing
To improve overall integrity of the bit, an extremely wear-resistant hardfacing material was applied to the
shirttail and leg of the bit to protect these areas from the effects of back-reaming and up-drilling, thereby
extending the overall life of the bit.
Field Trial Results
The new design was field trialled over several wells against sample offset wells of current conventional
designs used in field to evaluate its relative performance. Benchmarking each trial was primarily based
on average and best performance for total footage drilled and ROP achieved over the complete run. As a
secondary evaluation criteria, post-run dull grading was included in the performance comparison to quantify
the improved durability of the new design.
ROP and Footage Drilled
Fig. E-1 references ROP and footage drilled for offset runs representative of typical legacy design field
performance and contrasts them with the new field design trials. Several observations can be made from
the figure:
The new design with optimised parameters completed the interval consistently on all runs, thereby
achieving the first goal of consistently completing the section in one run.
The section ROP was consistently above the field average and almost always faster than offset
runs, even without including the additional trip time for a second or third bit run in the offset wells.
New field record of 40.4fph was set for complete section ROP on Trial Well 4.
Figure E-1—Offset and Trial Run Performance
CPF and ROP Improvements
CPF improvements gained in the section came from maintaining an overall ROP higher than field average,
eliminating the trip time for a second or third run, and eliminating the incremental cost of a second or
third new bit. Table E-1 summarises the improvements gained in ROP and CPF against the field average
performance. Overall, the runs improved on the average run performance of older designs and, when
combined with eliminated bit trips and extra bit costs, resulted in a 22% to 39%, lower CPF in all these
field trial runs.
Table E-1—ROP and CPF Improvement on Field Average
Post-Run Dulls
Overall post-run dulls (Fig. E-2) of the trial runs showed reduced cutting structure breakage, indicating
more efficient drilling performance as the cutting structure survived to complete the interval with minimal
damage. Bearings were consistently effective, meaning the new seal package was better suited for the longer
interval in this section.
Figure E-2—Post-Run Dulls of Trial Runs
Minimal bit balling was encountered, indicating that the hydraulic design of the new bit improved
cleaning efficiency and provided better coverage of cone cleaning.
Through utilising the latest technological advances in TCI bits and optimising drilling parameters in
problematic formations the goals set out at the start of this paper were achieved.
Cutting structure durability was improved, enabling the section to be drilled with one bit consistently.
Post-run dull analysis showed reduced insert breakage, indicating the combination of the new design and
improved carbide grades was better matched to the application than the older designs. This enabled the bits
to achieve the first goal of completing the section with a single bit run.
Optimised drilling parameters and stronger impact resistant cutting structure yielded an ROP
improvement of up to 53% on average. The increased robustness of the new design allowed it to be pushed
harder and longer than the old design, resulting in 22% to 39% lower CPF achieved through faster ROP,
eliminated bit trips, and additional bit costs.
Successful deployment of the new design yielded a saving of almost $80,000 USD and three days in
rig time per well.
The authors of this paper thank Kuwait Oil Company and Baker Hughes for permission to publish the data
and technical information presented in this paper. Thanks to all those involved in the process of developing
and trialling the designs mentioned in this paper; without them it wouldn't have been a success.
Unconfined Compressive Strength
Bottom Hole Assembly
Rate of Penetration
Tungsten Carbide Insert
Finite Element Analysis
Cost Per Foot
Finite Element Analysis
High Aspect Ration
Horsepower per Square Inch
Gallons per Minute
Weight on Bit
Rotations per Minute
Agawani, W., Al-Ajmi, A.M., Taha, M., Gohain, A., Omar, M.G., Al-Haj, H.A. et al 2016, SPE-180673-MS - Application
Focused Drill Bit Engineering Delivers Consistent Improvement in Efficient Drilling Performance, Proceedings
from IADC/SPE Asia Pacific Drilling Technology Conference and Exhibition, 22-24 August, Singapore, Singapore,
Available from: OnePetro Digital Library. [20 August 2017].
Al-Baghli, W.J., Al-Khaldy, A.D., Al-Mutawa, F., Saradhi, V., Maliekkal, H., Fayed, M. et al 2011, SPE-147867-MS
- Performance Step Change: New 16-in TCI Design Solves Multiple Middle East Carbonate Drilling Challenges,
Proceedings from SPE/IADC Middle East Drilling Technology Conference and Exhibition, 24-26 October, Muscat,
Oman, Available from: OnePetro Digital Library. [20 August 2017].
Al-Saeedi, M.J., Al-Fayez, F.A., Sounderrajan, M., Al-Mudhaf, M.N., Portwood, G.R., Ghoneim, O. et al 2012,
SPE-151615-MS - Solving Multiple Carbonate Challenges: TCI Delivers Performance Step-Change Drilling Deep 28in Hole Section, Proceedings from SPE Middle East Unconventional Gas Conference and Exhibition, 23-25 January,
Abu Dhabi, UAE, Available from: OnePetro Digital Library. [20 August 2017].
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