Proppant Selection

In Unconventional

Reservoirs

Terry Palisch

Director of Petroleum Engineering

November 8, 2012

Terry Palisch

Director of Petroleum Engineering

Outline

• Introduction

– Proppants

• Proppant Selection Drivers

– Importance of Conductivity

• Field Examples

– Unconventional Reservoirs

• Summary

Two primary papers are the basis for this talk….

=> SPE 106301 & 160206

“Cracking the Code” in UCRs

• The Challenge of Tight / Unconventional Reservoirs

Extremely low permeability formations

• Key technologies driving UCR development

Drilling and Completion advancements in HZ wells

HZ Operations - Perfs, plugs, completion designs

Multistage hydraulic fracturing

Do we understand our fractures as well as we

understand our completions?

Why is this Important?

• Wellbore Specifications

– Wellhead, casing, tubing, packers, etc

– Specify grade, pressure service/rating, fluid service, etc

• Fracture Stimulation

– What are you specifying for your proppant?

• i.e. proppant type and size, testing requirements, etc.

Hydrocarbons

Frac

Wellbore Sales Meter

The Proppant Conductivity Pyramid

Medium strength

Irregular size and shape Tier 2 - Medium Conductivity

Resin Coated Sand

Low strength

Irregular size and shape

Naturally Occurring Product

Tier 3 - Low Conductivity

Sand

Tier 1 - High Conductivity

Ceramic

High strength (minimizes crush)

Uniform size and shape (maximizes frac porosity and permeability)

Thermal resistant (durable, minimizes degradation)

Engineered, Manufactured Product

Highest Conductivity Highest Production, EUR, IRR

99% of all proppants used today fit

somewhere in this pyramid

Proppant Selection…can seem difficult

List not complete. Some names are registered trademarks, some historical

Lightweight

Ceramic Int. Density

Ceramic

High Density

Ceramic

CARBOLite

ECONOProp

HYDROProp

ValueProp

NapLite

MGLight

ForeProp

Sand

CARBOProp

ISP, InterProp

SinterLite

VersaProp

BoroProp

CARBOHSP

Sintered Bauxite

SinterBall

UltraProp

Ottawa, Jordan

Badger

Hickory, Brady

Colorado Silica

Arizona

White/Brown

“River” sand

With Resins:

PR = pre-cured CR =

curable

LC = low cost

DC = dual coat

AcFrac CR, PR, Black,

CARBOBond,

Tempered/Super TF

OptiProp, PowerProp

Super HS, Prime Plus

XRTGold

CARBOBond

Ceramax E

MagnaProp

Dynaprop

Ceramax P

HyperProp

CARBOBond

Ceramax V

Other

LiteProp 105, 125,

175

CARBOTag

CARBONRT

ScaleProp

Oxball, Oxfrac

Bauxlite

Proppant Selection Drivers in Shale Plays

• Availability

Availability Challenges

• “Bring us what you have” – Since 2004, global proppant utilization has increased 15-fold, and is

currently estimated at 60-70 billion lbs per year

– Demand has outstripped the pace of expansion in all Tiers

• Ceramic Plants, Resin Coating Plants, Sand Mines

– Driven proppant costs up

• Proppant Quality Can Suffer When Demand is High – SPE 84304, 101821, 119242

Quality Control & Assurance

Resin Coated Sand - Substrate Quality - Resin/Coating Technology

Uncoated Sand - Strength, Shape - Sieve Distribution - Influx of “River” Sand

Ceramics - Tight/Broad Sieve - Raw Material Quality - Process Controls - Shape/Strength - Supply Chain QA

High Quality LWC

Low

Quality

IDC

Low Quality

River Sand

Availability Challenges

• Challenges to Logistics / Distribution – Larger volumes per well / pad drilling

– Tremendous rig counts in a basin (200+)

• It is estimated that the Eagle Ford alone is using 10-15 billion lbs proppant annually

Proppant Selection Drivers in Shale Plays

• Availability

• Fluid system

Fluid System Impacts

• Fluid Selection

– Slickwater systems => 40/70 (& 100 Mesh)

– Crosslinked (Hybrid) Fluids => 30/50, 20/40 and larger

– Conductivity needs, rock fabric, cost, etc.

– Various proppant types and sizes necessary to tailor to each individual application (SPE 115766)

0

5

10

15

20

25

30

0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 4.00

20/40 Proppant

30/50 Proppant

40/70 Proppant

ASG, g/cc

Se

ttli

ng

Rate

High

Strength

Intermediate

Strength

Lightweight/

RCS/Sand

40/70 LWC/RCS/Sand

2.0

1.25

Proppant Selection Drivers in Shale Plays

• Availability

• Fluid system

• Conductivity requirements

Fracture Conductivity

cf = kf * wf

kf

wf

How wide is the road and

how good is the pavement?

How much Conductivity do I need?

cf = kf * wf

kf

wf

Dimensionless Fracture Conductivity (FCD) is a

measure of the contrast between the flow capacity

of the fracture and the formation

kf * wf FCD =

kform * xf

kform

xf

Common Misperceptions

Misunderstanding the need for conductivity “My reservoir has very low permeability….so I don’t

need much conductivity”

“Proppant A is ‘good enough’ at ___ conditions…….”

kf * wf

kform * xf

FCD =

However, the big issue is whether the Fracture

Conductivity is correctly estimated at realistic

(downhole) conditions.

Ports for Measuring

Differential Pressure

Temperature Port

Proppant Bed

Sandstone Cores

Flow Through

Proppant Bed

Reference: API RP 19C

• Ohio Sandstone

• 2 lb/ft2 Proppant Loading

• Stress maintained for 50 hours

• 150 or 250° F

• Extremely low water (2% KCl) velocity (2 ml/min)

How is Conductivity Measured?

ISO 13503-5 Conductivity Test

Pro’s & Con’s of Conductivity Testing

Reference: ISO 13503-5

Accounts for:

• Proppant Size

• Proppant Strength & Crush “Profile”

• “Wet” system

• Some temperature effects

• Some embedment

Does NOT Account for:

• Non-Darcy Flow

• Multiphase Flow

• Reduced Proppant Concentration

• Gel Damage

• Fines Migration/Cyclic Stress

• Others

Problem

To obtain a realistic proppant conductivity

for design, the API/ISO test results must be

reduced to account for:

1. Non-Darcy Flow

2. Multiphase Flow

3. Reduced Proppant Concentration

4. Gel Damage

5. Fines Migration / Cyclic Stress

6. Other

SPE 106301

ND Flow Through a Proppant Pack

ISOTest - 2 ml/min

100 bopd with 50% Sg

Or 120 MSCFD at 1500 psi BHFP

P/L = v / k + v2

Inertia Dominated

Multiphase Flow

• Relative permeability: Proppant saturated with liquid is less conducive to flowing gas

• Saturation changes: Liquid will tend to accumulate in the frac, occupying porosity that is now unavailable for gas flow

• Phase interaction: The fast-moving gas “wastes” energy accelerating the droplets of liquid. But the liquid often stops at each pore throat, only to be re-accelerated. Very inefficient flow regime!

Other Conductivity Reductions

• Lower Proppant Concentrations – Typically <1 lb/ft2

– Exacerbates ND/MP flow effects

• Gel Damage – Residual, Filter Cake, Tip Plugging

• Fines Migration – Fines of different proppant types

– Each proppant type handles fines differently

• Cyclic Stress – Each time the bottom hole flowing pressure

changes, the proppant pack rearranges and loses conductivity

• Durability – Fracture conductivity degrades over time

RCS

Courtesy Stim-Lab, Inc. Proppant Consortium

Sand

Ceramic

1540

5720

685

4310

225

1410

85

547

25 167 7 120

0

1000

2000

3000

4000

5000

6000

Eff

ec

tiv

e C

on

du

cti

vit

y (

md

-ft)

Lab Conditions High Velocity Multiple Fluids Less Proppant Gel Damage Fines/Cyclic

Stress

Jordan Sand

Lightweight Ceramic

Conductivity at Realistic Conditions

0.0001 D-m

0.029 D-m

Conditions: YM=5e6 psi,, 250°F, 1 lb/ft2, 6000 psi, 500 mcfd, 1000 psi bhfp, 50 ft H, 2 blpd

References: PredictK & SPE 106301

At baseline conditions, the Tier 1

proppant is 4x the Tier 3, but jumps

to over 15x at realistic conditions

99%

reduction

98%

reduction

0

20

40

60

80

100

120

140

Eff

ec

tiv

e C

on

du

cti

vit

y (

md

-ft)

Realistic Conditions

Jordan Sand

Lightweight Ceramic

Impact of Realistic Conditions

Conditions: YM=5e6 psi,, 250°F, 1 lb/ft2, 6000 psi, 500 mcfd, 1000 psi bhfp, 50 ft H, 2 blpd References: PredictK & SPE 106301

At baseline conditions the Tier 1

proppant performs 4x the Tier 3.

0

1000

2000

3000

4000

5000

6000

Co

nd

uc

tiv

ity

(m

d-f

t)

Lab Conditions

Jordan Sand

Lightweight Ceramic

At realistic conditions, the Tier 1

proppant performs 15x the Tier 3.

4x 15x

Additional Conductivity Considerations in UCRs

• Elevated Temperatures – Sand-based proppants lose conductivity at >200 F

– Ceramic proppants unaffected by temperature

– Eagle Ford, Haynesville, etc

0

0.2

0.4

0.6

0.8

1

0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000

150 deg F

200 degF

250 deg F

300 deg F

350 deg F

20/40 Premium White SandC

on

du

cti

vit

y C

orr

ecti

on

fro

m 1

50 d

eg

F,

facto

r

Additional Conductivity Considerations in UCRs

• Elevated Temperatures – Impact on natural proppants at >200 F

– Eagle Ford, Haynesville, etc

• Soft Formations – Increased proppant embedment

– Many shale plays

• Flow Convergence – Transverse fracs in horizontal wells

Tremendous pressure drop!

=> Higher conductivity imperative

The Reality

So in reality… The conductivity of our fractures is much lower than

we think

Most hydraulic fractures are “conductivity limited”

Modeling and field testing confirms that increasing the

fracture conductivity will increase production/EUR.

SPE 77675 & 134330

But…. Increasing conductivity typically increases the

investment

It is a Cost – Benefit decision

Proppant Selection Drivers in Shale Plays

• Availability

• Fluid system

• Conductivity requirements in these formations

• Cost vs Benefit – Economic Conductivity™

The Proppant Conductivity Pyramid

Medium strength

Irregular size and shape Tier 2 - Medium Conductivity

Resin Coated Sand

Low strength

Irregular size and shape

Naturally Occurring Product

Tier 3 - Low Conductivity

Sand

Tier 1 - High Conductivity

Ceramic

High strength (minimizes crush)

Uniform size and shape (maximizes frac porosity and permeability)

Thermal resistant (durable, minimizes degradation)

Engineered, Manufactured Product

Highest Conductivity Highest Production, EUR, IRR

Higher Conductivity = higher production

= higher investment

Proppant Selection is a Cost-Benefit decision

ECONOMIC CONDUCTIVITY PROCESS

Predict the fracture Conductivity at Realistic Conditions Some sophisticated Frac Models will do this

Run sensitivities to determine optimal Conductivity Provides the highest return on investment

Validate with field results Ensure field results support the modeling

Eagle Ford Shale Webb County operator

Evaluated Tier 1 vs Tier 3 proppants

Compared to internal wells, as well as offset operators

Proppant Selection Field Example #1

0

100

200

300

400

500

600

40/80 Tier 1 40/70 Tier 2 40/70 Tier 3

Bas

elin

e C

on

du

ctiv

ity,

mD

-ft Baseline Conductivity

Conductivity at Eagle Ford Conditions

SPE 155779

0

10

20

30

40

50

60

0

100

200

300

400

500

600

40/80 Tier 1 40/70 Tier 2 40/70 Tier 3

Re

alis

tic

Co

nd

uct

ivit

y, m

D-f

t

Bas

elin

e C

on

du

ctiv

ity,

mD

-ft

Baseline Conductivity

Realistic Conductivity

Eagle Ford Production Match/Modeling

SPE 138425

+100%

+50%

6 Month Cumulative BOE

Tier 3 Proppant Tier 1 Proppant

ECONOMIC CONDUCTIVITY™ - Eagle Ford Shale

SPE 155799

Primarily Tier 1

Primarily Tier 3

Production Impact of Conductivity

SPE 155799

Tier 1 Proppant

Tier 3 Proppant

Incremental Value - $1.5 MM

(payout in 9 months)

Well Completions Between Sand and Ceramic Proppant

Normalized to Number of Stages

Haynesville Shale Desoto/Caddo Parish by one operator

55 Wells – 20 utilized Tier 1 proppant, 35 utilized Tier 2

All drilled/completed similarly in similar time frame

Proppant Selection Field Example #2

32.15

32.20

32.25

32.30

32.35

32.40

32.45

-94.10 -94.05 -94.00 -93.95 -93.90 -93.85 -93.80 -93.75 -93.70

All Wells (at least 6 months production)Other Proppant

Premium Proppant

5 miles

32.15

32.20

32.25

32.30

32.35

32.40

32.45

-94.10 -94.05 -94.00 -93.95 -93.90 -93.85 -93.80 -93.75 -93.70

All Wells (at least 6 months production)Other Proppant

Premium Proppant

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 1,000,000 2,000,000 3,000,000 4,000,000

Cu

mu

lati

ve F

req

uen

cy

Cumulative Gas (MCF)

Cumulative Gas Production at Month 32

Tier 1

Tier 2

Actual Production after 2.5 years

Incremental 30% production

(0.5 BCF per well avg)

in ~2.5 Years

$1.8 million incremental PV

per well after 2.5 years, for a

$250k investment

Tier 1

Tier 2

$3.50/mcf

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

0 24 48 72 96 120 144 168 192 216 240

Cu

m G

as (

MC

F)

Months

Avg. Cumulative Gas Production

Cum Gas - Premium

Cum Gas - Other

Avg. Hyper Decline - Premium

Avg. Hyper Decline - Other

Decline Curve Analysis Projection

+35% (~1 BCF)

in 20 Years

Tier 1 Wells

Tier 1 Wells

Tier 2 Wells

Tier 2 Wells

(~0.5 BCF)

SPE 160206

Bakken Shale Mountrail County operator

Evaluated Tier 1 vs Tier 3 proppants

10 well internal field trial early in development program

Proppant Selection Field Example #3

Map of Trial Wells and Groupings

Offset (Sand) Wells

Ceramic Wells

1

2

3

4

5

6

7

3 milesSPE 160206

0

20000

40000

60000

80000

100000

120000

140000

160000

Group 1 Group 2 Group 3 Group 4 Group 5 Group 6 Group 7

Cu

m P

rod

uct

ion

at

22

mo

nth

s, B

OE

(bb

l)

22 Month Cumulative Production per Well Average

Tier 1 LW Ceramic Wells

Tier 3 Offset Wells

Bakken Trial – Conductivity Impact

Tier 3 Wells

Tier 1 Wells

0

10000

20000

30000

40000

50000

60000

70000

80000

90000

0 5 10 15 20

Cu

mu

lati

ve B

OE

per

wel

l (b

bl)

Months Produced

Average Cumulative Production

Tier 1 LW Ceramic Wells

Tier 3 Offset Sand Wells

+34%

A $300k investment in conductivity, has yielded a $1.5

million increase in value per well!

Bakken Trial – Conductivity Impact

13 well avg

10 well avg

Tier 3 Wells

Tier 1 Wells

Payout in ~3 months

CONDUCTIVITY Considerations in Various Plays

• Marcellus

– Transverse Fractures, Depth, Realistic Conductivity

• Utica

– Transverse Fractures, Depth, Oil / Multiple Fluids (similar to EF)

• Granite Wash – Transverse Fractures, Depth, High Gas Rate & Realistic

Conductivity

• Niobrara – Transverse Fractures, Oil / Multiple Fluids

• Most wells should see benefits to conductivity

– The only question is how much, and is it economic…

Key Take Away Messaging

• The HF process provides two things – reservoir contact and

conductive pathway.

– It is the critical (only) link between the reservoir and the wellbore

• Proppant is the conductivity pathway.

• Proppant Selection cannot be made based on depth, stress,

mean particle diameter or what the last engineer did.

– It must be designed specifically to the deliverability of a given well

• Hydraulic fractures are Conductivity Limited…period.

– The more you have, the more you make.

– One must estimate the conductivity of the fracture at realistic conditions

• Proppant Selection is a Cost vs Benefit decision

– You must determine the economic benefit of increasing the conductivity

via frac modeling and field validation

Summary

Availability (& cost) impacting proppant selection

Demand outstripping supply of quality proppant

Fluid selection and Conductivity should drive

proppant selection

Best completion practices require a realistic

estimate of conductivity

There is tremendous value at stake