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# “ Role of Induced and Natural Imbibition in Frac Fluid Transport and Fate in Gas Shales ” Alan P. Byrnes Chief Petrophysicst

Chesapeake Energy Corporation 6100 N. Western Avenue ı Oklahoma City, OK 76118 ı 405 -935 -8000

AskChesapeake@chk.com ı chk.com ı NYSE: CHK Technical Workshops for Hydraulic Fracturing Study

Fate & Transport  March 28- 29, 2011 US EPA Conference Center One Potomac Yard (South Building) 2777 S. Crystal Drive Arlington, VA 22202 Room S-4370 and 4380
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# Overview

• Hydraulic fracture (HF) models & production decay analysis support estimates of propped HF surface areas of 12 *10 6 

### sq ft and created area of 24- 60 *10 6 

### sq ft. • Frac fluid 30 + 10% recovered/70 + 10% leaks off into the fracture face • Elevated frac fluid saturations within 2 – 6 inches of the frac face. • High capillary pressures in shales 

### • High frac-face Sw is not in equilibrium and capillary forces act to imbibe the fluid into the reservoir away from the frac face • Frac fluids imbibed into the formation are effectively locked in place by capillary pressure forces of hundreds to thousands of pounds per square inch (psi) both during the life of the well production and for geologic periods of time after reservoir depletion 23 

# CHK’s Operating Areas

Low- risk, U.S. onshore asset base; Not exposed to economic, geopolitical or technological risks internationally or in the Gulf of Mexico

# Fate and Transport Issues

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## • Basic Parameters

– Time: Near-term, Long -term

– Location: Reservoir, Wellbore, Surface

– Substance: Gas, Liquid(s) Time Location Substance Time Location Substance Near-term Surface Gas Long -term Surface Gas Near-term Surface Liquid Long -term Surface Liquid Near-term Wellbore Gas Long -term Wellbore Gas Near-term Wellbore Liquid Long -term Wellbore Liquid Near-term Reservoir Gas Long -term Reservoir Gas Near-term Reservoir Liquid Long -term Reservoir Liquid 

## • This talk will focus on near- and long -term fate and transport of liquids in the reservoir (and wellbore)

# Fracture Fluids & Proppant

• Frac Job Material Volumetrics

– Vary with operator, formation properties

– volumetrics shown are for a “large” job 

## • Proppant

– 5 ± 2 *10 6 

### lbs (~30 ± 12 *10 3 

### ft 3 

### )

– Mesh 100/40 - 70/20 -40 

## • Frac Fluid

– 120 ± 20 *10 3 

### bbls (675 ± 100 *10 3 

### ft 3 

### )

– “Slickwater ” dominantly

– 3 - 11 chemical additives (all:1,000 - 6,000 ppmv ) • Friction reducer, biocide, KCl subsitute , Fe chelator • Scale inhibitor, surfactant, non - emulsifier • Gel, crosslinker

, breaker, corrosion inhibitor • All additives remain in Fluid except FR, Gel & XL 

## • Chesapeake Green Frac TM 

### • Depth ( 1,500 ft, 1.5 sd ) • Barnett 7,400 ft • Fayetteville 4,000 ft • Haynesville 11,400 ft • Marcellus 6,400 ft • Target Reservoir Thickness • 200 100 ft 5 (part per million volume)

# Fracture Stimulated Rock Volume

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## • Stimulated Rock Volume(SRV) geometry define by: • Microseismic • Frac material volumetrics • Frac modeling • Production Decline Analysis • Parameters Involved • Vertical stress profile • Regional and local principal stress anisotropy • Orientation of one/more natural fracture sets • Rock elastic properties • Fracture toughness • Frac fluid properties • Frac pump rates/pressures • Times between injection period • Proximity to frac barriers, nearby wells • Reservoir rock properties • Porosity • Permeability • Relative permeabilities • Initial water saturations • Capillary pressure properties • Pore throat size distribution

# Fracture Architectures

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### (modified from Fisher et al, 2002 ) 

### • Example of range of fracture architectures for a single initiation site • These would occur at each perf cluster and so would be reproduced ~50-70 times along the wellbore

# Production Decline Analysis and Flow Simulation

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### • Production Decline Analysis (PDA) & Numerical Flow 

### Simulation Solve for A√ k • Inputing core analysis k solve for A • A = 12 *10 6 

### ft 2 

### • L = 4,700 ft • Fracs = 66 (70 - ft spacing) • H=200 ft • W=400 ft • 2 sides of frac 

### • This surface area required for flow rates observed in wells • 66 pairs of football fields • Flow into both faces Simple flow simulation showing initial intrafrac flow followed by interwell flow

# Created vs Effective: Proppant Distribution

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### • Fracture Models • MFRAC/MSHALE (Meyer & Assoc.) • Volumetrics support 12 *10 6 

### ft 2 

### for effective propped frac surface area • Effective propped fracture 20% - 50% total fracture • Models differ but surface area into which frac fluids are injected is approximately the same for all three architectures.

(DFN Figures courtesy of Meyer & Assocs . MSHALE)

# Frac Surface Area – Induced Imbibition

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## • 12 *10 6 

## ft 2 

## Propped Effective • Estimated Effective/Total • 20%-50 % → • Total Frac Surface • 24-60 *10 6 

## ft 2 

## • 120,000 bbls (670,000 ft 3 

## ) of frac fluid pumped • Assuming uniformly injected • Variable = f

(t) • Porosity f = 0.06 • Saturation depth ≈ 2 - 6 inches q( t ) = 4 

# ∫ C/( t

- t o

## ) 0.5 

## d A q( t ) = fluid loss rate at time t A( t ) = fracture area of one face C = total leakoff coefficient t o 

### = time of fracture area creation

A(t) 0 

## • Simple 1D Leakoff Model

# Porosity & Kerogen Properties

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## ftotal 

## = f intergranular 

## + f intrakerogen 

### Py I Cc QF kerogen Laminated argillaceous to calcareous mudstone to silty mudstone


### Q

• Porosities vary by play and within reservoir intervals • 3 - 10% • General value 6%

# Pore Throat Diameter vs. Permeability

• Permeability for all lithology rocks is principally controlled by pore throat size (the “chokes” in the flow path) • For Mudstones of present commercial interest (50 nD < k < 2,000 nD ) corresponding D pt are 0.01 m m < D pt < 0.2 m m • “Typical” pore throat size distribution ranges from 10 - 20X so for 500 nD rock 0.004 m m < D t < 0.09 m m 12 (after Byrnes, 1997, 2005)



# { Human hair

# Threshold Entry Pressures

13 • Threshold entry capillary pressures (Pte) for lithic sandstones (blue squares) and representative gas shales (open triangles ). • Pte were measured using air- Hg and converted to equivalent reservoir CH4 - Brine pressures. • Data for shale show continuity with trend for sandstones and siltstones. Relationship can be expressed: • Pte = 8.6 ki - 0.424 (modified from Byrnes 2009)

# Gas Shale vs Low - k Sandstone Capillary Pressure

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### • Theshold entry pressure ( P te 

### ) increase with decreasing permeability • Gas shales exhibit higher threshold entry pressures consistent with texture and permeability • Capillary pressure distribution is 

### approximately 10X - 20X from P te

K i =0.001 mD K i =0.0001 mD

# Shale Capillary Pressure Properties

15 • 0.002 mD > ki > 0.00005 mD • 120 psi < P te < 600 psi • Pc increases with decreasing water saturation. • Capillary pressures (Pc) required to achieve or maintain the brine saturations in the present - day reservoirs (0.2 < Sw < 0.5) do not exist in all reservoirs today. K i =0.0001 mD K i =0.001 mD

• Capillary pressure properties of present day reservoir do not necessarily represent conditions at time of desaturation • reservoir exhibited better properties at time of gas generation allowing desaturation at lower Pc • Present Reservoir • Nonequilibrium and undersaturated • Equilibrium but has mixed or intermediate wettability. • Natural imbibition of water to Sw >0.75 for gas shale cores tested (black circles) • requires reservoir is sufficiently water wet to imbibe water with change in capillary pressure conditions • Imbibition curves, based on low - k sandstone, show general path of imbibition Pc curve

# Shale Capillary Pressure Properties

16 • After frac for 2 - 6 inches into the formation from the frac face Sw is~100% • Reservoir Sw ~30% • Capillary pressure difference between these two Sw states is 100’s - 1,000’s of psi K i =0.0001 mD K i =0.001 mD

• Capillary pressure difference between the reservoir and the frac face causes frac fluids to move to reservoir – natural imbibition • System is driven by Pc to uniform saturation state • to achieve uniform Sw the high Sw in frac -face region must imbibe • Rate of movement; q(t) = f ( kew , Sw, Pc, f ) Reservoir Pc Frac Face Pc 

# } Δ Pc

# Fate of Frac Fluids

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### • Initial production produces 30 10% of frac fluid • Remaining 70 10% of fluid leaks off into formation
• If well is shut in natural imbibition works unhindered
• If well is placed on production immediately then viscous forces and low near- frac face pressures slow or halt natural imbibition • As near- frac face region gas pressures drop the lower Pc condition “locks” in the Sw state and fluids are held in place
• With complete pressure depletion of the well the low Pc condition of the reservoir traps all fluid in place • In pressure depleted state the reservoir is undersaturated and over geologic time acts to imbibe water18 

# Conclusions

• Hydraulic fracture modeling and fracture surface area calculations determined from pressure decay analysis and reservoir numerical flow simulation support. estimates of created hydraulic fracture surface areas of 24-60 *10 6 sq ft. • 30 + 10% of the frac fluids are recovered. • 70 + 10% leaks off into the fracture face resulting in elevated frac fluid saturations within ~2 – 6 inches of the frac face. • High frac-face Sw is not in equilibrium and capillary forces act to imbibe the fluid into the reservoir away from the frac face • Frac fluids imbibed into the formation are effectively locked in place by capillary pressure forces of hundreds to thousands of pounds per square inch (psi) both during the life of the well production and for geologic periods of time after reservoir depletion. • Further research is needed and is ongoing as to the exact shape of the imbibition capillary pressure curves and imbibition water relative permeability curves to fully quantify the imbibition process and timing.19 

# “ Thank You – Questions?”

Alan P. Byrnes Chief Petrophysicst

Chesapeake Energy Corporation 6100 N. Western Avenue ı Oklahoma City, OK 76118 ı 405 -935 -8000

AskChesapeake@chk.com ı chk.com ı NYSE: CHK 19