Technological Aadvances Hydraulic Fracture

© 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

Mechanic

al

Insta

bili

ty

Formation Characterization

Concentration

Clay Control Selection Process

Outputs

Inputs


Custom Chemistry

Stimulate Microfractures to Support Production Contribution


MicroproppantParticles 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

19© 2017 Halliburton. All rights reserved. ** 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 MP106 days. 30.8% increment with MP

CONDENSATE PRODUCTION

210 days. 30 to 36% increment with MP106 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)


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Seawater Hydraulic Fracturing Fluid Ability to Carry Proppant

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Regained Core Permeability, %

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Retained Propp Pack Conductivity, %

� Fluid Cleanup

� Excellent clean up

� Minimal formation damage

� Good fluid leak off control

� Viscosity Profile

� Fluid Stability

27© 2017 Halliburton. All rights reserved.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 betterregain perm compared to a traditional friction

reducer with breaker. Recommended practice isalways 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 NoTreatedTime (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 proppantmanagement 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

FormationComodoro Rivadavia

MulichincoLajas & Punta

RosadaVaca Muerta Vaca Muerta Vaca Muerta

Basin Golfo San Jorge Neuquén Neuquén Neuquén Neuquén Neuquén

Type of Well andStages

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 20/4030/50 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 BonapaceArgentina Technology Manager

Production Enhancement [email protected]

www.halliburton.com/

Personal Contact


Date post:	22-Jan-2018
Category:	Engineering
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Technological Aadvances Hydraulic Fracture

Engineering