EPA HF Workshop

Flow of Gas and Water in Hydraulically Fractured Shale Gas Reservoirs

March 28-29, 2011 / Arlington, Virginia

Zhong He – Technical Advisor
Outline

● Controlling factors for fluid flow

● Permeability of Marcellus shale

● Hydraulic fracturing

● Pressure sinks and pressure distribution

● Fate of frac water

● Concluding remarks

2
Controlling Factors for Fluid Flow

• Hydraulic conduit and pressure gradient

3

A

Pressure gradient, , psi/ft

Permeability – a measure of flow capacity 

Darcy’s Law

L

p p

A

k

q

a b

q

p
Permeability of Marcellus Shale

4

kv<<kh kv = + 0.01 x kh

Marcellus

Limestone 

Shale

Shale

Limestone 

Marcellus Shale

Depth, ft 5,500 ~ 8,500

Matrix Porosity (%) 2 ~ 12

Matrix Permeability (nanodarcy) 100 ~ 450

Pore Size (nanometer) 10s ~ 100s

Shale typically serves as a cap rock to prevent escape of fluids 5,500 ~ 8,500 ft
Hydraulic Fracturing

5

Limestone 

Shale

Shale

Limestone 

Depth 



Stress 

Stress Profiles

Fracture height growth is confined by 

stress barriers and formation leak-off etc. 5,500 ~ 8,500 ft

,k

,k

,k

Leak-off

,k
Microseismic Data from Marcellus Shale Treatments

6

Fracturing of the Marcellus cannot impact groundwater
Hydraulic Fracturing

7

Created Fracture Length > Propped Fracture Length 500 ft 250 ft

During treatment After treatment

Areal View

Some of induced fractures may become isolated after treatment
Pressure Sinks During Production

8

Gas flow fractures wellbore

-50 -30 -10 1 0 3 0 5 0

Distance from fracture

Pressure

t1

t2

t3
Pressure Distributions

9

Low High

During Production During Shut-in

Pressure is always lower in stimulated zone than the surrounding formations
Minimum Gas Flow from Outside Stimulated Area

10

Effective Drainage Area:

2800ft by 700 ft ≈ 45 acre

Less than 20% 

pressure depletion

After 50 years production

0

5,000

10,000

15,000

20,000

25,000

30,000

0 2 0 4 0 6 0 8 0 100 120 140 160 Gas rate, Mscf/D

Production time, days

Observed rate

Model rate

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

0 20 40 60 8 0 100 120 140 160 Bottomehole Pressure, psia

Production time, days

Observed BHP

Model BHP

Gas Rate Matching

BHP Matching

Matching BU pressure

Matching Gas Rate
Fate of Frac Water

● Where does frac water go ?

1. Flowed back from fractures during production 20 – 40 %

2. Imbibed into the matrix pore space

o Swincreases 10~50%

o Minimal Krw

o Much more viscous than gas

o Practically immobile (stays in reservoir forever)

3. Trapped in disconnected fractures
Flow of Frac Water

● Mainly occurs within propped fractures

● Multiple phase flow

● Water rate quickly declines and become stabilized

0

0.2

0.4

0.6

0.8

1

0 0.2 0.4 0.6 0.8 1 Relative Permeability

Water Saturation

Krg Krw

w

w

rw

w

g

g

rg

g

A p

k k

q

A p

k k

q
Fate of Frac Water

● Where does frac water go ?

1. Flowed back from fractures during production 20 – 40 %

2. Imbibed into the matrix pore space

o Swincreases 10~50%

o Minimal Krw

o Much more viscous than gas

o Practically immobile (stays in reservoir 

forever)

3. Trapped in disconnected fractures

pcpgSwpwSw

Pw

Pg

SPE 89866
Concluding Remarks

● Pressure gradients drive the flow of gas and water

o Gas must move into fractures, then to wellbore

o Water mainly flows within fractures into wellbore

● Physical principles preclude migration of gas and water away from 

the stimulated zone

● A portion of frac water is produced up the wellbore back to surface

o Wellbore isolated from surrounding rock by steel casing strings and cement

● Majority of frac water is held by shale formation

and becomes immobile