3. U.S. gas and oil production: recent history
and forecast
Ref: EIA (2013)
Gas production Crude oil production
3
4. 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
5. 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
6. Effects of well shut-in on shale gas production
6
Water and gas production of a Marcellus gas shale well
from Cheng (2012)
7. 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
8. 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
9. 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
10. 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
11. 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
12. 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
13. 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
14. Numerical Results
• Effects of well shut-in on shale gas production
• Effects of waterflooding-induced stress on
microfracture creation
14
17. Model initialization
Injecting 5,000 bbl of 1,000 ppm salinity-water
17
Water saturation in fractures, fraction Water salinity in fractures, ppm
18. 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. 19
Base case
Well shut-in decreases water flow rate and load water recovery
Water flow rate Load water recovery
21. 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. 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. 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. 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. 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.
26. Part II: Effects of waterflooding-
induced stress on microfracture
creation
26
33. 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. 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
35. 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
36. 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
37. 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
38. 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
38
