DART Drilling Solutions

| bakerhughes.com
DART Drilling Solutions
Solving drilling challenges, creating opportunities
1
Challenging Situations,
Smart Solutions
The Baker Hughes DART™ drilling solutions are developed by
cross-functional teams of highly experienced technical personnel
to address specific drilling challenges for key Baker Hughes
customers. Each DART (Drilling Application Review team) team
works in a collaborative, learning environment to develop specific
solutions to meet, or even beat, the customer’s drilling objectives.
DART teams are assembled with just the right mix of technical
experts to address the challenges at hand–bit design engineers,
bit application engineers, drilling system engineers, materials
scientists, and manufacturing engineers. After studying the
customer’s objectives, each DART team gathers relevant drilling
application data, conducts root cause analyses, identifies the
primary performance limiters, and evaluates possible
solutions for game-changing improvements in
overall performance.
By evaluating the details of an application and
how the drill bit, along with each of the components
in the bottomhole assembly (BHA), affects the
overall performance of the drilling system in that
particular application, the DART team can provide
Capture
unique insights and tailored solutions. But the action
need not stop there. If called upon, ensuing field results
may be reviewed and evaluated to continue the learning
and process improvement cycle on subsequent jobs.
Customer satisfaction in the drilling objectives achieved
is always the ultimate goal.
Root Cause Analysis
Develop Solution
Knowledge
Test Solution
2
Systems Approach to Problem Solving–Beyond the Bit
The industry’s relentless quest for new oil and gas discoveries
around the globe often involves ever greater measured depths,
deeper water depths, high-temperature/high-pressure conditions,
and more complex wellpaths. Any of these can increase the
technical challenges that need to be addressed. Today’s advanced
drilling systems include highly specialized drill bits and complex
BHAs with many components, any of which can cause inconsistent
performance or inefficiencies. Finding the root cause can be
difficult, but with the right knowledge and combined product and
field expertise evaluating the many drilling interdependencies, a
search for the root cause can be fine-tuned.
For any given challenge, the DART drilling solution will engage
Baker Hughes experts from across the company to help define,
evaluate, and deliver a final solution. The DART solutions team,
which is uniquely staffed for each drilling challenge, will conduct
a root cause investigation, develop possible solutions, and
evaluate those solutions to deliver optimal performance.
DART solutions are the culmination of the extensive knowledge
and experience provided by each of its participating experts.
For every solution developed over time, knowledge is captured
and applied going forward to advance performance in similar
situations as part of the continuous improvement process.
DART teams combine engineers, processes, and the latest
technology to deliver customized, multidisciplined solutions.
The OASISTM certification program helps Baker Hughes engineers
develop a defined level of technical competence, demonstrating
skills and achievements that enable them to provide premium
engineering services.
Drilling Interdependencies
Health, safety, and environment
nn
Customer’s objectives
nn
Spread rate
nn
Rig considerations
nn
Power
nn
Lithology
nn
Well plan
nn
Drill bit design
nn
Drilling fluid
nn
Hydraulics
nn
Drill string
nn
BHA
nn
Drilling parameters
nn
Downhole electronics
nn
Drive system
nn
Vibrations
nn
Torque and drag
nn
Steerability
nn
System compatibility
nn
Performance
nn
Trip reductions
nn
3
Advancing Solutions with Proprietary Modeling and Testing
The identified solution will often require extensive testing for proof of concept, and Baker Hughes is uniquely prepared to
evaluate ideas from start to finish through proprietary, advanced computer modeling, world-class laboratory facilities,
and field testing expertise.
Computer Modeling
BitGenie Software
The Baker Hughes BitGenie™ is a
unique drill bit selection software
system that correlates thousands
of laboratory tests and kinematic
and dynamic models with field
performance to effectively consolidate
the myriad combinations of drill bit
design features into drill bit behaviors.
Baker Hughes drill bit engineers use
the tool to choose the right bit from
among thousands of existing designs.
The tool also provides predictive
guidance in the new bit design process
for tailored bit performance in real
world applications.
Power Curves and MSE
Baker Hughes introduced mechanical
specific energy (MSE) and power
curves to the oil and gas drilling
industry to maximize drilling efficiency,
and continues to lead the way in the
effective application of these powerful
field performance evaluation methods.
These tools are used to identify
performance limiters, and are often
an essential part of the root cause
analysis process.
Data Visualization and Analysis
Foot-based drilling and dynamics data
is plotted, along with well log and
formation tops, for both offset and
test wells to evaluate and correlate
trends in drilling behavior in various
formations and to measure the effects
of bit dulling in service. Lithology logs
are used to estimate rock strength
and drillability. Advanced visualization
using MSE and power curves identifies
poor drilling performance and drilling
dysfunctions. The highly graphical
plots aid in identifying opportunities
for improvement with targeted drill
bit, BHA, and operating parameter
recommendations.
BHASysPro Analysis Software
This proprietary Baker Hughes finite
element analysis software program
suite analyzes the static and dynamic
forces on drill strings and can be
run in time- or frequency-domain
mode. Application engineers use this
powerful program to optimize bit
designs for specific drive systems and
BHAs, as well as to predictively identify
optimum drilling parameters for
smooth, efficient drilling and improved
overall system reliability. The software
also estimates BHA tilt angles.
Directional Drill-Ahead Simulator
This proprietary Baker Hughes software
models the dynamic directional
behavior of a particular BHA and
drill bit combination. It takes into
account drilling parameters, formation
characteristics, BHA design, and drill
bit design to predict the 3D wellbore
trajectory.
Bit-Reamer Matching
Concentric reamers have become an
integral part of modern drilling systems
in many world-wide operations, such
as complex, offshore drilling programs.
One of the keys to successfully
applying concentric reamers is
matching the aggressiveness of the
bit to the reamer, since the bit and
the reamer are not always drilling
in the same formation at any given
time. Baker Hughes engineers can
effectively match a bit to a particular
reamer system to optimize the drilling
response in the field, improving overall
system performance and reliability.
4
Kinematic and Dynamic Modeling
Used to predict bit stability, dynamic dysfunctions, and
drilling responses for new bit designs, this proprietary
numerical modeling method iterates the design/evaluate
process until a final, optimized solution is delivered.
Visual Single-Point Cutter Machine
The rock-cutting mechanics of PDC cutters are captured
in high-definition, high-speed videos to visually determine
how different cutters perform under specific downhole
drilling conditions in various rock types.
Finite Element Analysis Models
Test bit designs are evaluated to ensure the strength,
integrity, and reliability of structural components such
as polycrystalline diamond compact (PDC) bit blades
and rolling cone bit legs.
Vertical Boring Mills
PDC cutter performance, primarily cutter wear resistance,
durability, and thermal degradation are evaluated using
vertical boring mills with various rock types.
Computational Fluid Dynamics Modeling
Computational fluid dynamics modeling is used to
develop PDC bit designs with optimized hydraulic
cleaning and cooling characteristics for different
drilling applications.
Scientific Laboratories and Resources
Baker Hughes has numerous specialized laboratories
in its various world-class technology centers for the
characterization of steel, carbide, diamond, and
elastomer materials; and extensive microscopic and
analytical equipment used for failure analyses and
formation evaluation.
Laboratory Testing
High-Pressure Drilling Simulator
Full size drill bits up to
14¾-in. can be
performance-tested
with a wide range of
formation types under
high-pressure, downhole
drilling conditions
simulating up to
20,000 ft (6 096 m) depths.
Atmospheric Surface Rig
Bit performance and
drilling response are
evaluated under
atmospheric conditions
with different rock types
to quantify bit stability,
side-cutting and buildup
rates, and performance on
rotary or downhole motors.
Field Testing
BETA Test Facility
The Baker Hughes BETA
experimental test facility,
one of the most heavily
instrumented drilling rigs
in the world, provides
real-time drilling data
for immediate analysis.
Drilling solutions can be
tested across a range of
geological formations and
depths in advance, while
eliminating the potential
risk and downtime
associated with testing
leading-edge technologies
on a customer’s commercial
drilling operation.
Putting Knowledge
DART Solution Set New Daily Footage and ROP Drilling Records, Reduced Cost per Foot 42%,
and Saved Operator USD 2.1 million
Location: Challenge: Solution: Offshore Brazil
Pre-salt reservoirs
Custom-designed Kymera hybrid drill bit with proprietary Stabilis and StaySharp cutters
A third design using larger, Stabilis™
reinforced cutters with proprietary,
modified chamfer geometry and backup
StaySharp cutters in the PDC portion of
the bit, along with optimized heel rows
and new carbide grades in the roller
cones, proved to be the optimal solution.
The average ROP of this third Kymera bit
enabled a field record of 24.0 ft/hr (7.3
m/hr), dropping the cost per foot to USD
2,487. The run also delivered the field’s
daily footage record of 735 ft (224 m).
to the pre-salt, the Kymera bit provided
much better toolface control than other bit
types by reducing torque fluctuations and
vibrations.
In the pre-salt field, the first run using the
Kymera bit with StaySharp cutters achieved
an average ROP of 9.5 ft/hr (2.9 m/hr), but
was pulled out of the hole with a cored
center and damaged cutters.
Baker Hughes recommended a DART
solution involving a Kymera™ hybrid
drill bit with special StaySharp™ cutters,
combined with a Baker Hughes AutoTrak™
rotary steerable system (RSS). The bit,
with its combined PDC and roller cone
technologies, has been shown to smoothly
drill challenging carbonate formations.
Based on modeling and lab tests
conducted using a formation type similar
For the second run, team members
modified the design of the Kymera bit’s
cutting structure and hydraulics to add
greater stability. The changes resulted in
improved dull grades, no coring, and an
even faster ROP of 11.8 ft/hr (3.6 m/hr),
but further design improvements were
needed to optimize the bit’s durability.
$10,000.00
Results of the DART drilling solution
dropped the cost per foot for the third
Kymera run by 60%, saving the operator
USD 2.1 million. The unique combination
of new Kymera bits and the AutoTrak RSS
drilling system achieved the desired well
trajectories for all three wells.
30.0
Cost per Foot Comparison
Pre-Salt Santos Basin - 12¼-in. Section
$7,359
$6,958
$6,128
$5,000.00
25.0
$7,671
$7,218
$6,015
20.0
$5,905
15.0
$4,341
$4,054
$3,932
$3,652
10.0
$2,487
5.0
0.0
$0.00
2
t#
Offse
1
t#
Offse
3
t#
Offse
4
t#
Offse
5
t#
Offse
a
1
mer
st Ky
6
t#
Offse
8
t#
Offse
9
t#
Offse
10
t#
Offse
2n
a
a
mer
d Ky
3
mer
rd Ky
ROP, ft/h
An operator drilling pre-salt in a 12¼-in.
section of an offshore well was challenged
by the slow rate of penetration (ROP)
provided by impregnated diamond bits.
Impregnated bits in offset wells averaged
an ROP of 6.6 ft/hr (2 m/hr) at a cost of
USD 6,183 per foot. However, impregnated
bits still fared better than either tricone or
PDC drill bits in this formation.
Cost per Foot, USD
5
to Work
6
–Case Studies
Integrated DART Solution for Curve and Extended Lateral Sections
Eliminated a Trip, Increased ROP, and Saved 2 Drilling Days
Northeastern US
Horizontal shale plays
BHA design using application-specific bit and rotary steerable system
Wells in the Marcellus and Utica shale
plays in the mountainous Northeastern
United States require lengthy horizontal
lateral sections. These wells have
typically been drilled with a two-trip
process—one trip with a conventional
bent-motor BHA to drill the curve, and
a second trip using a Baker Hughes
AutoTrak Curve™ RSS BHA. Bent-motor
BHAs require sliding in the curve section,
which in turn cause pipe drag and
directional orientation issues, so once
the curve is completed, it is switched
with the AutoTrak Curve RSS BHA to
more efficiently drill the lateral section.
The DART Drilling Solutions team worked
with directional drillers, directional
systems engineers, and operators to
design a single BHA that could drill both
curve and lateral hole sections while
improving overall ROP and extending the
lateral sections.
Bit durability was not a major concern
for the soft formations, but important
features such as cutter profile, gauge
cutter count and configuration, polished
cutters, cutter exposure, and gauge pad
geometry were developed to improve
build-up rates, ROP, and steerability,
as well as to mitigate vibrations and
Days
0
0
1.5
3
2000
4.5
6
7.5
9
RSS Drilling Days
RSS Overall Days
4000
Depth, feet
Location: Challenge: Solution: Conventional Bent Motor
Average Days
6000
8000
10000
12000
2.2 Days
14000
Performance comparison of RSS tool/custom RSS bit and conventional bent submotor average
any balling tendencies specific to the
specialized BHA.
Computer modeling of bit designs
with the RSS BHA using typical drilling
parameters and RSS steering force
allowed DART drilling solutions to specify
the optimum bit features. By modeling
the bit and BHA using a directional
prediction simulator, the custom RSS bit
showed better directional control than
previously applied standard bits.
Lab tests using formations similar to
that of the Marcellus and Utica shale
plays showed that the RSS-specific bits
were more stable and efficient, and
provided greater depth-of-cut control in
the lateral sections.
Field runs show that the custom RSS
PDC bits, when used with the AutoTrak
Curve RSS, increased ROP significantly,
saving operators an average of 33 hours
over standard PDC bits used with the
same tool. Field runs also demonstrated
that drilling with the RSS tool and
custom RSS PDC bits reduced drilling
time by an average of 2 days compared
to drilling with conventional bent
sub motors.
| bakerhughes.com
Disclaimer of Liability: This information is provided for general information purposes only and is believed to be accurate as of the date hereof; however, Baker Hughes Incorporated and its affiliates do not make any
warranties or representations of any kind regarding the information and disclaim all express and implied warranties or representations to the fullest extent permissible by law, including those of merchantability,
fitness for a particular purpose or use, title, non-infringement, accuracy, correctness or completeness of the information provided herein. All information is furnished “as is” and without any license to distribute. The
user agrees to assume all liabilities related to the use of or reliance on such information. BAKER HUGHES INCORPORATED AND ITS AFFILIATES SHALL NOT BE LIABLE FOR ANY DIRECT, INDIRECT, SPECIAL, PUNITIVE,
EXEMPLARY OR CONSEQUENTIAL DAMAGES FROM ANY CAUSE WHATSOEVER INCLUDING BUT NOT LIMITED TO ITS NEGLIGENCE.
© 2015 Baker Hughes Incorporated. All rights reserved. 42807 08/2015