Technological Advances in Hydraulic Fracturing

© 2017 Halliburton. All rights reserved.
Technological Advances in
Hydraulic Fracturing
Primer Congreso Chileno-Americano
del Petróleo y Energía
Juan Carlos Bonapace
Punta Arena, Chile. 17-20 June 2017

2© 2017 Halliburton. All rights reserved.
7,299 tcf gas and 345 MMbbl tight oil recoverable
shale gas reserves in
41 countries around the world
71 percent located outside of North America
Map: Global Map of Shale Potential, PacWest
Unconventional Resources
Unconventionals – The Global Potential
Shale
Tight Gas/Tight Oil
Coalbed Methane

Subsurface insight accelerates reservoir understanding and recovery.
Fiber Optics
DownHole Microseismic
Customized chemistry helps improve well economics and increase production.
Improve Fluid Mobility and Reduce Fracture Face Damage
Stimulate Microfracture to Support Production Contribution
Fracturing with Produced Fluids, High TDS Without Formation Damage or Production
Decline
Surface efficiency can save costs and reduce environmental impact.
Frac of the Future
New Pump Generation
Proppant Modular System
Well Head Connection Unit
Technology Focus

Subsurface Insight
Fiber Optics & Down Hole Microseismic

Fracture Initiation
(Fiber Optic)
Near-wellbore Fluid Distribution (Acoustic and Temp)
Cluster Efficiency (fracture fluid entry points)
Completion Effectiveness
Important input for calibration/optimization Frac Model
Fracture Mapping
(DH Microseismic)
Hydraulic fracture geometry (long and high), azimuth
Evaluate fracture coverage
Determine whether there is induced complexity
Provide well placement information
Subsurface Insigh

Solve the most fiscally critical challenges:
Well Spacing
Well Placement
Fracture Spacing
Subsurface Insight

Custom Chemistry
Improve Fluid Mobility and Reduce Fracture
Face Damage

Improve Fluid Mobility and Reduce Fracture Face Damage
SURFACTANT SCREENING - OIL SURFACTANT SCREENING - GAS CLAY CONTROL SCREENING
Specialized laboratory testing
using formation fluids,
formation cuttings and
fracturing fluids
Performance-driven chemistry
Can aid in the recovery of
treatment fluids and early
breakthrough of oil

Tradition Approach
Emulsion and compatibility test
Standard or recommended concentration (rule of thumb)
New Focus on Evaluation
Selection process (screening)
Integrate formation and fracture fluid components
Optimize concentrations
Improve fluid mobility and Hydrocarbon recovery
Fluid Mobility

Work Methodology: is a process to select the optimum surfactant on a well by well basis
by taking into account reservoir characteristics and stimulation fluid design.
Surfactant Selection Process (Oil)
Ion Concentration (mg/L)
Chloride 28,361
Bicarbonates 746
Sulfate 11,925
Iron 12
Service evaluates variables that can
affect surfactant performance, such as
mineralogy, formation water, and
fracturing fluid
Results that reflect the combination of
surface and interfacial phenomena of
fluid flow through a porous media fracture
model

Formation Mobility
Modifiers (FMM)
Microemlsions (MEs)
Mircoemulsions
Are Thermodynamically stable blend of
biodegradable solvent, surfactant, co-solvent and
water. Modify contact angle and decrease capillary
pressure.
Weak Emulsifying Surfactant
Create revere oil-in-water emulsion to solubilize oil
and reduce interfacial tension between oil and water,
allowing for increase mobility of oil molecules to be
produced through small pore throat sizes.
Formation Mobility Modifiers
Complex solvent blends (nanofluid, microemulsion,
wetting agents nonemulsifiers). Minimize adsorption,
reduce IFT, improved fluid mobility, increased fluid
displacement.
Weak Emulsifying Surfactants (WES)
** SPE 179000
** SPE 154242
** SPE 131107
New Types of Surfactants

Tonkawa Sandstone,
Anadarko Basin, Oklahoma
Horizontal Well - (tight-oil).
Objective: remove formation
damage, improve fluid
recovery and long-term
production
Laboratory Test for surfactant
screening and custom
chemistry:
Fine migration
Clay swelling
Hydrocarbon mobility
Case History - Surfactant Selection Process (Oil)
SPE-173379 - From the laboratory to the Field: Successful Multistage Horizontal Fracturing
Design and Implementation in Tight Sandstones In the Anadarko Basin
Surfactant#10 – Surface Active Agent
Surfactant#7 - Weak Emulsifying Surfactant
Surfactant#4 and 5 - Microemulsions

Test and Introduction in Argentina (Surfactant Selection Process)
WES
MEs
WES
MEs

Tradition Approach
Fluid sensitivity (fresh water)
»Mainly Clay swelling – Capillary suction time Test
Standard or recommended concentration (rule of thumb)
New Focus on Evaluation
Dual approach
»Swelling Stability Test & Mechanical Stability Test
Selection process (screening) integrating formation and fracture fluid
components - Optimize concentrations
Reduce swelling problems, minimize fracture-face softening, fine
migration, mechanical destabilization;
Avoid loss of fracture conductivity
Fracture Face Damage
Swelling
Fines
5 hrs

Formation Mineralogy Methodology
Inadequate clay control can lead
to fracture face instability and
diminished conductivity
Optimized clay control treatments
help stabilize the fracture face for
improved conductivity
Fracture face instability without
proper clay control can cause
diminishment of effective frac
lengths over time.
Proper clay control can impart fracture
face stability, increasing effective flowing
fracture network and maintaining the
created fracture conductivity over time.
Provides detailed information on
formation mineralogy
Customized treatment
recommendations for well by well
focused clay control technologies
Performance-based, optimized
treatment and dosage
recommendations by clay control
selection process

Formation Materials
Cleaned
Source Water
Swelling Stability Metrics
(CST)
Mechanical Stability Metrics
(MST)
Swelling Instability
Mechanical
Instability
Formation Characterization
Concentration
Clay Control Selection Process
Outputs
Inputs

Custom Chemistry
Stimulate Microfractures to Support
Production Contribution

Microproppant
Particles magnified 200x
Increase Conductivity Through the Microfractures Stimulated
Most of shale rock matrix remain untouched by open
natural fractures and induced microfractures, i.e., >
80%.
Induced secondary fractures only contact a very small
fraction of the natural fractures.
More than 90% of the hydrocarbons remain intact in
the rock matrix.
Lack of physical means to contact rock
Limited contact surface area to the microfractures
Enhances conductivity and production by placing fine
particulates into secondary microfractures too small to
be propped by conventional frac sand

** SPE-185121
Microfractures Stimulation Concept

Avg Cum Gas Production - (210 days) Avg Cum Condensate Production - (210 days)
GAS PRODUCTION
210 days. 20% to 30% increment with MP
106 days. 30.8% increment with MP
CONDENSATE PRODUCTION
210 days. 30 to 36% increment with MP
106 days. 63.5% increment with MP
Case History - Microfractures Stimulated and Propped
SPE-174060 - Application of Micro-Proppant to Enhance Well Production in Unconventional
Reservoirs – Laboratory and Field Results

Custom Chemistry
Fracturing with Produced Fluids, Brines,
High TDS Without Formation Damage or
Production Decline

Life Cycle Water – Hydraulic Fracture

High-performance hydraulic fracturing fluid system that
enables operators to use 100% produced or flowback water.
Minimizes waste stream and costs for producers
Reduces trucking and water volume disposal
Ensures maximum well productivity with
recycle fluids
Fluid formulate with salt concentrations greater than 300,000
ppm TDS
Decade Technological Changes
1940 Oil and viscosified oil frac
1950 Viscosified water
1960 Crosslinked fluids
1970 Foamed fluids
1980 Improved breakers
1990 Reduced polymer fluids
2000 Reduced residue fluids
2010 Guar-free, green fluids
2012 High-TDS crosslinked fluids
Fracturing Fluid formulate with “No Traditional Water”

100% CleanWave System TreatedTest: 140°F – TDS: 280,000 mg/l
Ions Conc. (ppm)
Boron 21.9
Calcium 28,877
Magnesium 4,287
Strontium 1,690
Test: 200°F – TDS: 299,000 mg/l
Ions Conc. (ppm)
Boron 263
Calcium 33,445
Magnesium 1,869
Strontium 2,728
Fracturing Fluid formulate with 100% Produced Water
Fracture Fluid – 100% Flowback Water
Metal-Crosslinked Derivatized Guar-base
Wide temperature range 100-275°F
Instant and delayed crosslinking
Clean
Low residue and High regained conductivity
High regained core conductivity
Efficient
Excellent proppant transport and suspension
SPE-163824 – Developmet and Use of High-TDS Recycled Produced Water for Crosslinked-Gel-Based Hydraulic Fracturing.

Designed to combat cost of fresh water in Middle East
Challenges with using sea water at high temperature
High TDS, Cations affect the rheological stability
dramatically
High Sulfate content risks scale formation
Fluid rheological stability and fluid clean up property
are inversely related
Pretreatment of seawater to remove “problem” ions
»Sulfate: >4000 ppm reduced to 20 ppm
»Calcium: 675 ppm reduced to 100 ppm
»Magnesium: 1900 ppm reduced to 75 ppm
Use of Seawater for Unconventional Tight Gas Hydraulic Fracturing
(remote fresh water)

0
100
200
300
400
0
300
600
900
1200
0 10 20 30 40 50 60 70 80 90 100
Temp
Viscosity(cp);100s-1
Time (min)
Shear Scan 350°F – 45# Gel Loading
0
100
200
300
400
0
300
600
900
1200
1500
0 10 20 30 40 50 60 70 80 90 100
Temp
Viscosity(cp);100s-1
Time (min)
Shear Scan 300°F – 40# Gel Loading
Seawater Hydraulic Fracturing Fluid Ability to Carry Proppant
0
10
20
30
40
50
60
70
80
90
100
300 °F 330 °F 350 °F
Regained Core Permeability, %
0
10
20
30
40
50
60
70
80
90
100
300 °F 330 °F 350 °F
Retained Propp Pack Conductivity, %
Fluid Cleanup
Excellent clean up
Minimal formation damage
Good fluid leak off control
Viscosity Profile
Fluid Stability

Technical References: SPE-151819, SPE-174118, SPE-174119
Tailored Customized Fracture Fluid development for Operators

Traditional FR
High TDS FR
Dissolved CaCl2 decreases friction reduction (FR)
performance and affects:
Immediate friction reduction
Long-term friction reduction
Temperature at 150°F
High TDS FR without breaker has similar to better
regain perm compared to a traditional friction
reducer with breaker. Recommended practice is
always use breaker with friction reducers
“Clean” and “cost-effective” technology
High TDS Friction Reducer
SPE-165641. Recycling Water: Case Studies in Designing Fracturing Fluids Using Flowback,
Produced, and Nontraditional Water Sources

Tipo de Agua Flowback s/tratar Flowback s/tratar Flowback s/tratar Flowback s/tratar Flowback s/tratar
% Flowback 100% 100% 100% 100% 100%
TDS (ppm) 121300 121300 121300 121300 121300
Ca (ppm) 17600 17600 17600 17600 17600
Tipo y Conc FR sin FR Tradicional (2.0 gpt) VFR-10 (0.15 gpt) VFR-10 (0.25 gpt) VFR-10 (0.50 gpt)
Hydration Time (min) Flowback Water NoTreated
Time (min)
Test and Introduction in Argentina (High TDS FR)
Test performed at Neuquén laboratory.
FR introduced and implemented for Operators as YPF, TCPETROL, SHELL, PAE
More than 150 treatments

Surface Efficiency
Frac of the Future

New Pump Unit Generation
Higher Reliability
Extended Fracturing Times
Dual fuel systems
Leverage Natural Gas for
High-Horsepower Pumping
Proppant Modular Systems
Efficient proppant
management system
Wellhead Connection Unit
Simplify the Rig-up
Improving Operational Efficiency
Frac of the Future (FoF)

Advanced, unconventional frac pump
equipped with improved fluid end
technology
New pump – 14x life improvement
XHD™ fluid end – 1.7x life improvement
Reduced equipment footprint
Less capital on location
Reduced NPT
Reduced maintenance
New Pump with XHDTM Fluid End Technology
New Pump Unit Generation - Higher Reliability, Reduced NPT and Maintenance
Support Unconventional Extended Fracturing Times

Ability to substitute up to 70% of natural gas for diesel
Works with LNG, CNG, and conditioned field gas
No change in unit performance during gas
substitution
Increase NG consumption
Reduce diesel hot fueling
Dual-Fuel Operations
Dual Fuel Systems - Leverage Natural Gas for High-Horsepower Pumping
Reducing Fuel Transport and Manufacturing
New Pump Generation - Powered by Natural Gas

Proppant Modular Systems - Efficient proppant management system
Step change in proppant management
Elimination of dust and Reduced footprint
Reduced truck congestion
Reduction of failure points
Labor reduction on location

Well Head Connection Unit - Simplify the Rig-up and Provide Easier Operations
Single-line rig-up to the wellhead
Rated for 100 bpm @ 10,000 and 15,000 psi
Shortened cycle times
Reduced nonproductive time (NPT)
Improved service quality
Reduced HSE exposure
Eliminates up to 75% iron connections
Well Head Connection Unit - Operation
Currently Connection Systems – multi well PAD

Hydraulic Fracturing trends in Argentina and
Vaca Muerta Horizontal Wells

Argentina – Hydraulic Fracturing Trends
Year 2006 2008 2010 2010/12 2014/15 2016/17
Reservoir Conventional Tight Gas Tight Gas Shale Shale Shale
Formation
Comodoro
Rivadavia
Mulichinco
Lajas & Punta
Rosada
Vaca Muerta Vaca Muerta Vaca Muerta
Basin Golfo San Jorge Neuquén Neuquén Neuquén Neuquén Neuquén
Type of Well and
Stages
Vertical (6) Vertical (2) Vertical (12) Vertical (5) Horizontal (15) PAD-4 Hztal (75)
Total Proppant p/well
(lb)
15,000 560,000 2,160,000 2,750,000 7,950,000 36,000,000
Total Fluid p/well
(gal)
72,000 320,000 1,620,000 1,250,000 4,425000 24,120,000
Avg HHP p/F.Stage 1,544 4,412 10,417 12,132 13,931 15,956
Goflo San Jorge
Conventional
Mulichincho - Neuquén
Tight Gas
Vaca Muerta - Neuqúen
Shale (vertical)
Vaca Muerta - Neuquén
Shale
(PAD-Horizontal)

Horizontal Wells Evolution
Vaca Muerta Horizontal Wells
2012 to 2017
7 Operators
50 Wells > 750 Frac Stages
Completion Design
Stimulation Design (Hydraulic Fracture)
Fluid Systems
Proppant

Vaca Muerta Horizontal Wells - Completion
Frac Stage Length (m) Avg Cluster Spacing (m)
Frac Stages per WellHorizontal Section per Well (m)
650 m 1500 m 6 Stages 20 Stages
Avg 55 m
2 Clusters
(25m)
5 Clusters
(15m)

Vaca Muerta Horizontal Wells – Fracture Design (Proppant)
Total Proppant per Well (lb) Vs. White Sand (%) Total Proppant per Well (lb) Vs. Fine Proppant (%) (70/140 + 40/70)
Total Proppant per Well (lb) Vs. Max MeshTotal Proppant per Well (lb) Vs. N°Mesh
4 Mesh 2 Mesh 20/40
30/50
40/70
20% WS 75% WS 25% fine 65% fine

Vaca Muerta Horizontal Wells – Fracture Design (Fluids)
Total Fluid per Well (gal) Vs. Type of Surfactant Total Fluid per Well (gal) Vs. Proppant Concentration (lb/gal)
Total Fluid per Well (gal) Vs. Low Viscosity Fluid (%) (SW+LG)Total Fluid per Well (gal) Vs. Type of Design
Hybrid Design
(SW+LG+XL)
40% LowVisc
Avg 70% LowVisc
ME
WES
NO
NO
Avg 0.9lb/gal
Avg 1.4lb/gal
Avg 2.2lb/gal

Technologies applied
Surfactant and Clay Control Selection process
Current evaluations for conventional, tight and
shale wells
Microemulsion Surfactant
Mostly used in tight gas and a some shale gas
wells
Weak Emulsifying Surfactant
Recent application in tight and shale wells
High TDS Friction Reducer
In tight gas as clean system
In shale wells for flowback water
Tailored Fracture Fluids
Developed for produced water and fresh water
with high level of sulfate
Next Step
Microfractures Stimulation (Microproppant)
Proppant Modular System
Well Head Connection Unit
Summary

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Juan Carlos Bonapace
Argentina Technology Manager
Production Enhancement
juancarlos.bonapace@halliburton.com
www.halliburton.com/
Personal Contact

Technological Advances in Hydraulic Fracturing

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