A coupled flow and geomechanics model

for enhanced oil and gas recovery in

shale formations

Perapon Fakcharoenphol

Ph.D. thesis presentation

Outline

• Introduction

• Mathematical models

• Numerical studies

• Conclusions

• Recommendations

2

U.S. gas and oil production: recent history

and forecast

Ref: EIA (2013)

Gas production Crude oil production

3

Shale reservoir characteristics

• Low permeability (nD and µD)

• Low porosity and small pore size (nm to µm)

• Dominant transport mechanisms:

Gas: Darcy flow, Knudsen flow, desorption, molecular diffusion

Oil: Darcy flow

• High heterogeneity

Composition: kerogen, clay, quartz, calcite, etc.

Porosity types: inter-crystalline, inter-granular, and intra-kerogen

Fractures: microfractures and macrofractures

4

Production from shale formations

• Complex production characteristics

• Require horizontal well drilling and hydraulic

fracturing

• Low hydrocarbon recovery (EIA, 2013):

Gas recovery factor 20% - 30%

Oil recovery factor 3% - 7%

5

Effects of well shut-in on shale gas production

6

Water and gas production of a Marcellus gas shale well

from Cheng (2012)

Waterflood oil production potential:

Pilot test in Bakken Viewfield From: Wood and Milne (2011)

7

Well configuration for pilot no. 1 Oil production and water injection

Objective and scope of work

• Objective

Explore the possibility to devise methods to enhance gas and oil recovery in shale formations

• Scope of work

Develop numerical models to investigate:

� Increase in gas flow rate after long shut-in periods in some production wells

� Waterflood oil recovery potential in the greater Bakken formations

8

Mathematical models

• Flow in organic-rich shale

Investigate the effect of gravity, capillarity and osmotic forces

on phase re-distribution during well shut-in

• Flow and geomechanics in anisotropic rock

Determine the nature of the induced stress, caused by

waterflooding, which causes micro-fracturing

9

Flow in organic-rich shale

10

Ion-milled SEM of a Barnett

sample (Passey et al., 2011)

Triple-porosity modelSchematic of pore and fluid

distribution in shale

Flow model for organic-rich shale gas

11

• Governing equations:

Mass balance for water, gas, and salt

• Features:

Triple-porosity: Fractures, organic and inorganic pores

Gas storage: Free gas and absorbed gas on organic matrix

• Transport mechanisms:

Global(f-f): Darcy flow, gravity, capillarity

Local (f-m, m-m): Darcy flow, molecular diffusion (salt only), gravity, capillarity, and osmotic pressure

Geomechanic model for anisotropic rocks

• Governing equations:

Mass balance for water and oil

Energy balance

Force balance

• Features:

Single porosity: Fractures are modeled by explicit grids

Stress-strain relation: Non-linear and orthotropic materials

Rock failure analysis

• Transport mechanism

Darcy flow, gravity, capillarity 12

Model validation

• Flow model for organic-rich shale

• Single-phase flow in a hydraulically fractured well

(Gringarten, 1974)

• Osmotic pressure measurement (Al-Bazali et al., 2006)

• Geomechanic model for anisotropic rocks

• 1-D consolidation (Jaeger et al., 2007)

• 1-D thermal contraction (Jaeger et al., 2007)

• 2-D compaction for transversely isotropic porous media

(Abousleiman et al., 1996)

13

Numerical Results

• Effects of well shut-in on shale gas production

• Effects of waterflooding-induced stress on

microfracture creation

14

Part I: Effects of well shut-in on shale

gas production

15

Model setup

Base case input parameters

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Properties Fractures Inorganic matrix Organic matrix

Porosity (-) 0.002 0.054 0.03

Permeability (mD) 0.01 0.0001 0.0001

Wettability - Mixed-wet Oil-wet

Osmotic efficiency (-) - 0.1 0.1

Salinity (ppm) 150,000 150,000 150,000

Maximum adsorption (scf/ton)

Langmuir coefficient (1/psi)

- - 2000

0.00044

Model initialization

Injecting 5,000 bbl of 1,000 ppm salinity-water

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Water saturation in fractures, fraction Water salinity in fractures, ppm

18

Base case

Gas flow rate

Cum. gas

0-day shut-in

7-day shut-in

15-day shut-in

30-day shut-in

Water saturation in fractures, fraction

Well shut-in increases gas flow rate

19

Base case

Well shut-in decreases water flow rate and load water recovery

Water flow rate Load water recovery

20

Base case

Produced water salinity profile is similar to field observation

Produced water salinity, ppm

21

Case 1: Wettability effect (without osmotic)

Base case:

Mixed-wet rockWater-wet rock Oil-wet rock

Water saturation in fractures, fraction

Capillary pressure helps imbibe the fracturing fluid filtrate into matrix

22

Case 1: Wettability effect (without osmotic)

Gas flow rate

15-day shut-in

Load water recovery

15-day shut-in

Capillary pressure helps increase gas flow rate and decrease

load water recovery after well shut-in

23

Case 2: Wettability with osmotic pressure

Water-wet rock

15-day shut-in

Oil-wet rock

15-day shut-in

Osmotic pressure helps increase gas flow rate in both

water- and oil-wet rocks

24

Case 3: Osmotic efficiency effect

Gas flow rate

15-day shut-in

Load water recovery

15-day shut-in

(base case)

(base case)

Osmotic pressure helps increase gas flow if osmotic

pressure efficiency is larger than 1%

25

Part I discussions:

• Well shut-in can increase gas flow rate if (1) inorganic

matrix is water-wet or mixed-wet, and (2) osmotic

pressure efficiency is larger than 1% .

• Well shut-in increases gas flow rate for about a month

without a significant cumulative production gain.

• Osmotic pressure promotes filtrate mass transfer between

fractures and matrix not only in the water-wet but also in

the oil-wet rocks.

• Gravity has minimal effect on the filtrate imbibition during

the well shut-in because shale matrix are very tight.

Part II: Effects of waterflooding-

induced stress on microfracture

creation

26

Model setup

27

Input parameters

28

' ' '

1 3 3N N Nm Sσ σ σ= + +

' ' '

1 3 31

N N NHB mσ σ σ= − − +

Hoek-Brown failure criterion:

Failure indicator:

Positive HB indicates rock failure

Failure criterion

29

30

Pressure and water saturation

31

Temperature and stress change

32

Failure indicator

33

• Pressure- and temperature-induced stress during

waterflooding could reactivate existing natural fractures or

create new microfractures

• These microfractures increases the interface area

between fractures and matrix

• These positive effects could take place farther away from

the immediate vicinity of hydraulic fractures.

Part II Discussions

34

Low-salinity cold-water injection could be used as an

enhance recovery method. The resulting enhanced

recovery mechanisms include:

• Increase fracture-matrix interface area due to

microfracturing

• Promote oil-water and oil-gas counter-current

flow due to capillarity and osmoticity

Part I and II: Enhanced oil and gas

production in shale formations

Overall conclusions

• Two mathematical models, fluid-flow in organic-rich

shale, and flow and geomechanics in anisotropic

rock, were developed:

• The models were validated against analytical

solutions and laboratory measurement.

• Two numerical studies were conducted to investigate

the underlying assumptions.

• The study results indicate the possibility of devising

an enhanced oil and gas recovery scheme in shale

formations to use low-salinity water injection.35

Recommendations

Measure:

• Relative permeability

• Capillary pressure

• Osmotic pressure

Further investigate using low-salinity cold-water injection as an enhanced recovery method in shales:

• Temperature-induced microfractures, similar to Siratovich et al. (2011) experiments but using shale samples

• Spontaneous imbibition with different water salinity

• Core flooding using fractured shale samples with low-salinity water

36

Recommendations (continued)

Extend the presented models to include:

• Geomechanics calculations for fractured rocks using (1) continuum

concept for natural fractures and (2) discrete fractures for hydraulic

fractures

• Shale matrix refinement to capture capillary end effect and transient

flow in shale matrix

37

Acknowledgements

• My advisors: Dr. Wu and Dr. Kazemi

• Dr. Winterfeld, Dr. Ozkan, Dr. Tutuncu, Dr. Griffiths, Dr. Yin, Dr. Miskimins, Dr. Curtis, and Dr. Rutqvist

• My classmates

• Denise Winn-Bower

• EMG for financial support

• MCERS, UNGI, FAST, and foundation CMG

• My wife Dr. Sarinya

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Q&A