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Using Complex nano Fluids (CnF®) to Optimize Hydraulic Fracturing Performance
Glenn Penny, Ph.D., Director of Technology
MENA and Asia
Providing Quality and Service to the Global Oilfield
16th U.S.-China Oil & Gas Industry Forum
September 27-29, 2016
THE MESSAGE TODAY • Hydraulic fracturing of unconventional
resources has been successful but requires large volumes of water and proppant
• The addition of Flotek’s CnF® has resulted in 50 to 100% higher production rates in these treatments
• Optimizing the design and adding CnF® makes it possible to pump less water and proppant and get as much or more production
Providing Quality and Service to the Global Energy Sector 16th U.S.-China Oil & Gas Industry Forum
• Foot print is large • Water is limited • fracturing a typical
horizontal well requires • 3-5 million gallons (10 –
20000 m3) of water • Massive amounts of
proppant required • high pressure, high rate,
long hours of pumping
Challenges in China
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• Social impact in – Many wells are in
agricultural and residential areas
– Flowed back water and gas management can be a big issue
Challenges in China
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What can be done?
• Technologies available to limit use of water – LPG frac – Explosives – radial drilling – Foam, CO2, N2, energized fluid
system
• How can we reduce the size and improve results? – Optimize frac size and
additives – Water recycle and
management
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Radial Drilling\Jetting
Shale “Waterfrac Volumes ” seismic work shows the fracture network length grows with volume. Average is 24,000 bbl or 1 million gal per frac with 10 to 12 fracs
0
5000
10000
15000
20000
25000
30000
35000
40000
45000
0 2000 4000 6000 8000 10000 12000 14000 16000 18000 20000 Fluid Volume, bbl
Frac
ture
Net
wor
k Le
ngth
, ft
Shale Fracturing performance is controlled by Stimulated Reservoir Volume This stimulated area must be propped open and cleaned up to be effective
Making proppant and fluid selection very important
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Proppant types available
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Proppant Permeability vs size and closure at 250 F. Perm ranges from100 Darcies for Ceramic to as low as 1 Darcy for 100 mesh at 10,000 psi
Providing Quality and Service to the Global Energy Sector 16th U.S.-China Oil & Gas Industry Forum
Factors Influencing Proppant Performance??
• Proppant Permeability vs type size and closure • Influence of embedment, pressure cycling and multiphase non-
Darcy Flow • Frac fluid Damage • Capillary Pressure in the proppant pack vs proppant type and
size, closure and surfactant type and concentration • Position of the lateral within the pack: Impact of fracture flow
orientation on relative perm of pack • Impact of gelling agents, surfactant type and concentration on
the relative permeability profile vs proppant type and size and orientation: Rel perm of the pack correlates with production
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Complex nano Fluid (CnF®) Improves relative perm of the formation and proppant pack
• Applications • Drilling: Drilling Fluid
Cleanup • Fracturing, Acidizing • Remediation • IOR/EOR
13
CnF® technology combines surfactants and solvent in a nanoscopic structure
Can add other components to
the nano droplet – Shale Stabilizers – Demulsifiers – Foamers, asphaltene
paraffin solvents inhibitors
10-20 nm droplet Heads out tails in the solvent
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14
Advantages of CnF over common Surfactants
1. CnF liquid liquid interface means the surfactant is less likely to adsorb on the invaded matrix. This means more surfactant is available at the oil/water or gas water interface as the treating fluid enters the reservoir
2. This allows invaded fluid to be displaced at half of the pressure increasing rel perm to gas
σLL
σLG
σSL
CnF®
nanodroplets
0
10
20
30
40
50
60
70
80
0 2 4 6 8
Pore Volumes
Surfa
ce T
ensi
on (d
ynes
/cm
)
2% FS
NP
AE
ME
ME+2%FS
CnF+AE
CnF+ FS
AE=AlcoholEthoxylate FS=Fluorsurfactant NP=nonylphenol Ethoxylate
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Common Surfactants Penetrate about half way due
to adsorption
CnF® Additives Penetrate to tip of
invaded area
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Advantages of CnF® • 2. The pressure to remove the
treating fluid is reduced by as much as a factor of 4 over common surfactants by maintaining low surface tension and a contact angle of 60 degrees This allows recovery of more treating fluid and produces a higher relative permeability to hydrocarbon
• Common surfactant look 1000 psi to initiate flow. CnF initiated flow at 100 psi and has 2 to 3 times the relative perm at 2000 psi pressure drop
16
Capillary Pressure Reductionwith CnFTM
3000
1500
750
309
200
1375
688
344
142
92
688
344
172
71
46
10
100
1000
10000
0.001 0.01 0.1Permeability (mDs)
Cap
illar
y Pr
essu
re E
nd E
ffect
(PSI
)
No SurfactantConventional SurfactantComplex nano-FluidTM
0%
50%
100%
0 100 500 1000 1500 2000 2500 3000 3500 4000 4500
Pressure Drop (PSI)
Reg
aine
d R
elat
ive
Gas
Per
m (%
)
Regained Permeabilitywith 2 gpt CnFTM
Regained Permeability with
2 gpt Conventional Surfactant
Absolute Gas Permeability = 0.001 mDs
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Relative Perm to Gas: Average of up and down column flow tests vs Conductivity: CnF 2X common Surfactant
19
0
0.05
0.1
0.15
0.2
0.25
0.3
0.35
0.4
0.45
0 500 1000 1500 2000 2500 3000
Rel P
erm
to g
as K
rg
Conductivity mD-ft normalized to 2 lb/ft2
water Conv Surf CnF
70/140 30/50 20/40 20/40 sand sand sand Ceramic
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Average
20 20 20 20 20 20 20 20
Field Performance Comparisons Cumulative Production depends on: • Reservoir Quality (Permeability*Area) • Fluid Properties • Pressure Drawdown • Reservoir Geometry
Effective Fracture Length depends on: • Reservoir Quality • Fluid Properties
Incremental Value Darcy’s Law 1856
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21 21 21 21 21
Normalized using RPI®
Shift due to damage
Slope ~ kh or psuedo-potential; steeper slope is worse reservoir quality Intercept ~ connectivity; higher level is lower frac connectivity or Xf
Reciprocal Productivity Index
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22 22 22 22 22 22
0.001
0.010
0.100
1.000
10.000
0% 25% 50% 75% 100%
Cumulative Frequency (% less than)
Fully
Nrm
d 30
Day
Eqv
Rec
over
y(m
cf E
qv/K
#)
CnF P50 Nrmd 30D Cum Eqv = 0.985 mcf Eqv/K# (167 wells)non-CnF P50 Nrmd 30D Cum Eqv = 0.591 mcf Eqv/K# (202 wells)
Probability Data Sets are Different = 99.999987%
With CnF Up to 40% less proppant
to get same 30 Day Eqv Recovery
22 Introduction to CnFTM Technology
Composite 3- Basin Study
23 23 23
Comparison of proppant type with and without CnF®
250750
12502250
non-CnF
CnF$0
$250
$500
$750
$1,000
Nor
med
30
D G
as E
qv G
ross
Val
ue($
/K#
Prop
@ $
4/m
cfeq
)
Stressed Proppant Conductivity (mDs*Ft)
Comparative Gross Value of
Proppant Conductivity versus Complex nano-Fluid Usage
non-CnFCnF
Penny – SPE 152119
Providing Quality and Service to the Global Energy Sector 16th U.S.-China Oil & Gas Industry Forum
Conclusions • Lab data shows using a CnF® allows surface tension to remain low at the
leading edge of the fluid, thus lowering the pressure to remove the fluid • Relative perm to gas and oil is improved up to a factor of 2 over common
surfactants • Production of 240 wells was normalized based on reservoir quality,
drawdown and treatment stages and sizes. Production and effective fracture length shows a clear dependence on the conductivity of the proppant placed in low permeability shale reservoirs
• There is several folds benefit between 100 mesh and 20/40 or better when complex nano-fluid is employed at 0.15% or greater
• Overall it is possible to achieve the same production using 40 to 50% less water and proppant as long as a complex nano fluid is employed to insure formation and pack cleanup.
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