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SPE Distinguished Lecturer Series2001 - 2002
The ABC’s of Improving Productionfrom Hydraulically Fractured Wells
C. Mark PearsonCARBO Ceramics Inc.
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SPE DISTINGUISHED LECTURER SERIESis funded principally
through a grant of the
SPE FOUNDATION
The Society gratefully acknowledgesthose companies that support the program
by allowing their professionalsto participate as Lecturers.
And special thanks to The American Institute of Mining, Metallurgical,and Petroleum Engineers (AIME) and individual SPE sections for their
contribution to the program.
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Acknowledgements
• Carbo Ceramics Inc.• Colleagues - Gulf Oil, ARCO Oil & Gas,
ARCO Alaska, Colorado School of Mines• Mike Vincent and Pat Handren• My wife Joanie and children Chris, Julie
and Jack.
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Outline• Fluid Flow in Porous Media• Lab Testing of Proppants
• “Darcy Flow” - viscous, laminar• “Inertial Flow” - non-Darcy conditions• “True Flow” - multiphase and non-Darcy
• Field Case Studies• Conclusions
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“The First Reservoir Engineer”
• The Inspector General of Bridges andRoads
• France, 1856• What size filter is required to satisfy the
drinking water needs of the city of Dijon?• ……..
Henry Darcy
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Darcy’s Experiment
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Darcy’s Data
Dis
char
ge, L
iters
per
Min
ute
Drop in Head Across Sand (Meters of Water)
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Darcy’s Equation
∆ P/L = µ v / k Applicable only with low fluid velocity
Typically valid for matrix flowdistant from the wellbore
re-arrange
LhhKQ )( 12 −∗=
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Forchheimer - 1901
• Recognized that fluid flow through porousmedia is a function of the square of thevelocity.
∆ P/L = µ v / k
Applicable at realistic fracture flowrates
+ β ρ v2
Typically required for fracture modeling andfor radial flow in prolific non-stimulated wells
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Flow Convergence in the Fracture
Width = 0.25 inches
Cross Sectional Area = width x height = ~ 1 ft 2
Surface Area of Reservoir exposed to one Frac Wing islength x height x 2 sides = ~ 20,000 ft
2
Velocity in the fracture is20,000 times higher than
in the formation!!!
Height = 50 ft
Length = 200 ft
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Predicting Capacity of a Fracture
Well Flowrate
Pres
sure
Dro
p in
Fra
ctur
e
Laminar Flow
Forecast Pressure Drop
True Pressure Drop
∆ P/L = µ v / k
∆ P/L = µ v / k + β ρ v2
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Other Historical Studies• C. M. White -1929
- flowed liquids through coiled pipes, and found fluidinertia became important at Reynold’s numbersbelow 100.
• Ergun -1952- theoretical and experimental data confirm that the
pressure drop through beds of granular solids arethe sum of the viscous and kinetic energy losses.
- Ergun equation is commonplace in calculations ofheat and mass transfer to and from moving fluids.
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• Claude Cooke - 1973 (SPE 4119)- measured beta factors under stress for a variety
of sand proppants- verified that Beta factor is fluid independent- recognized that fracture conductivity limits the
production of wells- case studies for wells making 1 to 10 MMSCFD
showed that non-Darcy pressure drop can be 3to 19 times higher than predicted with Darcy’sLaw
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Outline• Fluid Flow in Porous Media• Lab Testing of Proppants
• “Darcy Flow” - viscous, laminar• “Inertial Flow” - non-Darcy conditions• “True Flow” - multiphase and non-Darcy
• Field Case Studies• Conclusions
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Ports for Measuring Differential Pressure Temperature Port
Disassembled API Proppant Cell
Proppant Bed
Sandstone CoresFlow ThroughProppant Bed
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Long Term Conductivity Cells
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Example Proppant Conductivity CurveModified API RP-61 Procedure
0
2000
4000
6000
8000
10000
12000
2000 4000 6000 8000 10000 12000Closure Pressure (psi)
Con
duct
ivity
(md-
ft) LWCRCSSand
Test Conditions: 2 lb/sq ft, 250°F, zero gel damage, YM = 5e6 psi, SLFrac 2001
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Comparison of Viscous andInertial Flow Effects - Dry Gas Well
0
10
20
30
40
0 1 2 3 4 5 6 7 8 9 10
Well Flowrate, MMSCFD
Pres
sure
Dro
p in
Fra
ctur
e, p
si/ft Laminar Flow (viscous forces)
Forecast Pressure Drop
Non-Darcy Flow (inertial forces)
Total Pressure Drop (measured)
Conditions: 20/40 Jordan Sand, 4000 psi stress, 50% gel damage, 50 ft frac height, 0.20 inch width, 1000 psi BHFP, SLFrac 2001
API Testing inlaminar flow
This componentcontrolled by β
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Beta Factor
• A material property that can be experimentallymeasured for each proppant size and type.
• Essentially a measure of the tortuosity of theflowpath in the proppant pack.
• Beta can be reduced by:– High Initial Permeability (high perm equates to less
tortuous flow path).– Tight Size Distribution (uniform pore size, and high
porosity minimizes expansion/contraction losses).– High proppant sphericity (angularity is bad).– Smooth Proppant Surface
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Forchheimer Equation
• ∆ P/L = µ v / k + β ρ v2
• It may be linearized and rewritten as:
Y= 1 / k0 + β Xwhere: Y = ∆p/(Lµv) and X = (ρv/µ) and
k0 is the absolute permeability
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Example Forchheimer Plot
0.00
0.05
0.10
0.15
0.20
0 50 100 150 200
Y =
1/k
SandRCSLWC
Test Conditions: 2 lb/sq ft, 6000 psi, 250°F, zero gel damage, YM = 5e6 psi, SLFrac 2001
X = (ρv/µ)
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Multiphase Flow Effects• Multiphase flow should be considered in most
wells.
• Even 1 or 2 bpd of condensate or water has asubstantial impact on effective conductivity andproduction rate.
• BHFP and pressure in fracture body is typicallybelow bubble point.
• Primary Causes: saturation changes, relativepermeability effects, and increased complexity ofnon-Darcy flow regime (phase interaction).
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Multiphase Flow in Proppant Packs
Source: Stim-Lab Proppant Consortium, Feb. 2001. 2.8 lb/sq ft CarboLite at 4000 psi stress, 550 Darcyreference perm. Multiplier is incremental to total pressure drop under non-Darcy conditions with dry gas.
Equivalent rates from 50’ frac height at 2000 psi BHFP.
Increased Pressure Drop due to Mobile Liquid in Proppant Packs
-
10
20
30
40
50
60
0% 5% 10% 15%Fractional Flow of Liquid
Mul
tiplie
r of T
otal
Pres
sure
Dro
p
0.75 MMCFD0.25 MMCFDTrend
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Impact of Multiphase Non-Darcy Flow20/40 Proppants at 2 lb/sq ft, 6500 psi and 225 F
(Penny & Jin - SPE 30494)
10
100
1000
10000Ef
fect
ive
Con
duct
ivity
(md-
ft)
API "Darcy Flow" Viscous Flow
Conditions
"Inertial Flow"With Non-Darcy
Effects
"True Flow" Multiphase andNon-Darcy Flow
Jordan SandResin Coated SandLight Weight Ceramic
Non-Darcy Test Conditions: 1 MMSCFD, 50 ft. frac height, 3000 psi BHFP, w/ and w/o 10 bwpd.
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0
1000
2000
3000
4000Ef
fect
ive
Con
duct
ivity
(md-
ft)
API "Darcy Flow" Viscous Flow
Conditions
"Inertial Flow"With Non-Darcy
Effects
"True Flow" Multiphase andNon-Darcy Flow
Jordan SandResin Coated SandLight Weight Ceramic
Impact of Multiphase Non-Darcy Flow20/40 Proppants at 2 lb/sq ft, 6500 psi and 225 F
(Penny & Jin - SPE 30494)
Non-Darcy Test Conditions: 1 MMSCFD, 50 ft. frac height, 3000 psi BHFP, w/ and w/o 10 bwpd.
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The Real World:How do we apply this information?
• Recognize that multiphase and non-Darcy flow effectsdramatically reduce the effective conductivity of fractures.
• Additional conductivity reductions due to embedment and geldamage often result in actual fracture conductivities rangingfrom 1% to 5% of published reference values!
• Most fracture design tools disregard these effects.
• Adjustments must be made to the fracture design andproduction models to optimize the economic potential of thefracture treatment.
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Outline• Fluid Flow in Porous Media• Lab Testing of Proppants
• “Darcy Flow” - viscous, laminar• “Inertial Flow” - non-Darcy conditions• “True Flow” - multiphase and non-Darcy
• Field Case Studies• Conclusions
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Kuparuk River Field, Alaska
Case Study #1SPE 20707 & 24857
North Slope
Kuparuk
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Kuparuk River Field, AlaskaSPE 20707 & 24857
• 20 to 100 md in lower A Sand• Fine sandstone with shale, quartz &
ankerite cementation• ~30 feet of pay at ~6000 ft TVD• Stress on proppant = 3400 psi
Traditional thought was that these wells shouldnot be fracture stimulated.
Unique data quality and quantity. Over 880 fracs,and over 200 refracs with multiple build up tests.
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Evolution of Fracture Design - Kuparuk
• Initially, small “skin fracs” were pumped to frac past drillingdamage.
• Average Flow Efficiency of 164% and s = - 1.6• No benefit found to pumping larger job sizes without
increase in fracture conductivity• Strong benefits achieved with:
– higher permeability (lower Beta factor) proppants– the elimination of solid FLA’s; 100-mesh sand and silica flour– Improved fluids and Tip Screen Out (TSO) designs
• Five years of continual “learning” resulted in a doubling ofproduction rates despite minimal benefit predicted with aDarcy flow model.
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Kuparuk Proppant Parameters For Proppants at 2 lb/sq ft
0
3000
6000
9000
12000
15000
API
Ref
eren
ce C
ondu
ctiv
ity (m
d-ft)
20/40Sand
20/40LWC
16/20LWC
12/18LWC
0.00000
0.00025
0.00050
0.00075
0.00100
Bet
a (a
tm -s
ec^2
/gra
m)
20/40Sand
20/40LWC
16/20LWC
12/18LWC
SLFrac 2.21, 3400 psi stress, 150°F, 2.5e6 Modulus, 20% Gel Damage, 2 lb/sq ft
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0
5000
10000
15000
Effe
ctiv
e C
ondu
ctiv
ity (m
d-ft)
API "Darcy Flow" ViscousFlow Conditions
"True Flow" Multiphaseand Non-Darcy Flow
20/40 Sand20/40 LWC16/20 LWC12/18 LWC
Impact of Multiphase Non-Darcy FlowKuparuk Formation
SLFrac 2.21, 3400 psi stress, 150°F, 2.5e6 Modulus, 20% Gel Damage, 2 lb/sq ft
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Kuparuk Refrac RatesSPE 24857
0
10
20
30
40
50
60
70
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 37
Time Since Refrac (months)
BOPD
/ Net
Foo
t of A
San
d Pa
y
Phase I - GD 20/40 Sand (9 wells)Phase II - GD/GW 20/40 LWC (27 wells) Phase III - GD/GW 16/20 LWC (97 wells)Phase IV - GW 12/18 LWC (52 wells)
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Evolution of Kuparuk Frac DesignRelationship of Effective Conductivity to Rate
0
1000
2000
3000
4000
5000
6000
2 lb/sq ft Ottawa 5 lb/sq ft 20/40LWC
5 lb/sq ft 16/20LWC
5 lb/sq ft 12/18LWC
Effe
ctiv
e C
ondu
ctiv
ity, m
d-ft
500
600
700
800
900
1000
1100
Initi
al R
ate,
bop
dPr
edic
ted
incl
udin
g no
n-Da
rcy
and
Mul
tipha
se E
ffect
s
Effective ConductivityRate
Data: 3400 psi stress, 20% gel damage, YM of 2.5 mmpsi, 30 ft pay, 30 API oil at 650 scf/bbl, SLFrac 2.21
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Kuparuk Well 2F-08SPE 24857
0
500
1000
1500
2000
2500
3000
3500
4000
May-84 May-86 May-88 May-90 May-92 May-94 May-96 May-98 May-00
Date
Prod
uctio
n fr
om A
San
d (b
fpd)
Original Fracture (20/40 Sand)Refrac #1 (20/40 sand)Refrac #2 (16/20 LWC)
Incremental Oil Exceeds1,000,000
barrels
IncrementalOil exceeds
650,000 barrels
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Kuparuk Well 2F-11SPE 24857
0
200
400
600
800
1000
1200
1400
May-84 May-86 May-88 May-90 May-92 May-94 May-96 May-98 May-00
Date
Prod
uctio
n fr
om A
San
d (b
fpd)
Original Fracture (20/40 Sand)Refrac #1 (20/40 sand)Refrac #2 (16/20 LWC)
IncrementalOil Exceeds1,000,000barrels
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Birch Creek Unit,Green River Basin - WY
Case Study #2 - SPE 67299
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Green River Basin, WyomingGreen River Basin, Wyoming• Green River Basin
wells consist of astacked layer ofreservoirs with 30 to120 feet of productiveinterval.
• It is typical that theFrontier interval willbe commingled withthe deeper BearRiver to get acommercial well.
• Green River Basinwells consist of astacked layer ofreservoirs with 30 to120 feet of productiveinterval.
• It is typical that theFrontier interval willbe commingled withthe deeper BearRiver to get acommercial well.
Well BIRCH CREEK UNIT #119Well ID 49-035-21263Field BIRCH CREEKCounty SUBLETTEState/Province WYOMINGCountry
Correlation
GR
0 200GAPI
SP
-300 -100MV
CALI
6 16IN
Depth Resistivity
ResD(HDRS)
0 100OHMM
ResM(HMRS)
0 100OHMM
ResS(DFL)
0 100OHMM
Porosity
PHIN(NPHI)
0.4 0DECP
PHID(DPHI)
0.4 0DECP
Gas
6400
6500
6600
6700
6800
6900
7000
7100
7200
7300
7400
7500
7600
7700
7800
Well BIRCH CREEK UNIT #119Well ID 49-035-21263Field BIRCH CREEKCounty SUBLETTEState/Province WYOMINGCountry
Correlation
GR
0 200GAPI
SP
-300 -100MV
CALI
6 16IN
Depth Resistivity
ResD(HDRS)
0 100OHMM
ResM(HMRS)
0 100OHMM
ResS(DFL)
0 100OHMM
Porosity
PHIN(NPHI)
0.4 0DECP
PHID(DPHI)
0.4 0DECP
Gas
6400
6500
6600
6700
6800
6900
7000
7100
7200
7300
7400
7500
7600
7700
7800
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Frontier Formation,Wyoming
• Permeability - .05 md
• Depth ~ 7800 ft
• Stress on Proppant ~ 5500 psi
• Reservoir Pressure - 2390 psi
• Net pay - 30 feet
• Fracture Geometry - 160’ X 500’ X .65 #/sq ft
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Wyoming - Green River BasinInitial Production Rates vs Time
2.45
6.50
2.03
3.89
6.30
2.03
0.85
2.00
0.10
1.00
10.00
Jan-
76
Jan-
80
Jan-
84
Jan-
88
Jan-
92
Jan-
96
Jan-
00
Year
Initi
al P
rodu
ctio
n R
ate
(MSC
FD)
Chevron Frontier Wells, WyomingSPE 67299
Effective Declinefor Sand Fracs
Phase 1105k # sand
Phase 2 - increasedsand volumes six-fold
Phase 3235k# sand
Phase 4 - replace sand with270k# ISP
Phase 5 - back to sandas a “cost-saving”
measure, 270-400 k#Phase 6 -
last drilling &sell field ?
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Frontier Formation Proppant Parameters SPE 67299
0
500
1000
1500
2000
API
Ref
eren
ce C
ondu
ctiv
ity (m
d-ft)
JordanSand
ResinCoatedSand
LightWeight
Ceramic
0.000
0.003
0.006
0.009
0.012
Bet
a (a
tm -s
ec^2
/gra
m)
JordanSand
ResinCoatedSand
LightWeight
Ceramic
SLFrac July ‘98, 5460 psi stress, 150°F, 3.5e6 Modulus, 50% Gel Damage, 0.65#/sq ft
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0
250
500
750
1000Ef
fect
ive
Con
duct
ivity
(md-
ft)
API "Darcy Flow"Viscous Flow
Conditions
"Inertial Flow"With Non-Darcy
Effects
"True Flow"Multiphase andNon-Darcy Flow
Jordan SandResin Coated SandLight Weight Ceramic
Impact of Multiphase Non-Darcy FlowFrontier Formation - SPE 67299
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0.00
0.25
0.50
0.75
1.00
1.25G
as R
ate
(MM
SCFD
)
API "Darcy Flow"Viscous Flow
Conditions
"Inertial Flow"With Non-Darcy
Effects
"True Flow"Multiphase andNon-Darcy Flow
Jordan SandResin Coated SandLight Weight Ceramic
Frontier Formation Predicted Rates104,000 lbs proppant, 0.65 lb/sq ft, 7750 ft, 0.75 psi/ft, 500 ft, 2 blpd
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0%
50%
100%
150%
200%
250%
166 BR 166 F 167 BR 167 F 168 BR 168 F 168 FF 174 BR 174 F 174 FF 181 BR 181 F
Well Number / Formation
Pred
icte
d Ra
te /
Actu
al R
ate
(%)
Predicted Vs. Actual IP Ratesfor Darcy and Non-Darcy Models
100% represents perfect prediction of initial rates
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0%
50%
100%
150%
200%
250%
166 BR 166 F 167 BR 167 F 168 BR 168 F 168 FF 174 BR 174 F 174 FF 181 BR 181 F
Well Number / Formation
Pred
icte
d R
ate
/ Act
ual R
ate
(%)
Darcy ModelNon-Darcy Model
Predicted Vs. Actual IP Ratesfor Darcy and Non-Darcy Models
Ave Error for DarcyModel = +52%
Ave Error for Non-DarcyModel = +6%
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Wyoming - Green River BasinInitial Production Rates vs Time
2.45
6.50
2.03
3.89
6.30
2.03
0.85
2.00
2.65
0.10
1.00
10.00
Jan-
76
Jan-
80
Jan-
84
Jan-
88
Jan-
92
Jan-
96
Jan-
00
Year
Initi
al P
rodu
ctio
n R
ate
(MSC
FD)
Chevron Frontier Wells, WyomingSPE 67299
Effective Declinefor Sand Fracs
Phase 1105k # sand
Phase 2 - increasedsand volumes six-fold
Phase 3235k# sand
Phase 4 - replace sand with270k# ISP
Phase 5 - back to sandas a “cost-saving”
measure, 270-400 k#
Phase 6 324k# LWC
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Subsequent Development
• Field has not been divested• An additional 11 wells were drilled
in 2000• LWC fracs had an average IP of
2.34 MMscfd• Eight wells being drilled in 2001
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SPE Papers Documenting Benefit ofIncreased Conductivity
• 44 Companies (primary author’s affiliation)– Shell, Esso, Amoco, CARBO Ceramics, Schlumberger, BEB, Mitchell Energy, Forrest, Imperial,
Sun E&P, Standard Oil, BP, Chevron, ARCO, Holditch, Gidley, Pennzoil, Koninklijke, FracTech,MIT, Mobil, Vastar, Falcon, Petrobras, Vietsovpetro, BJ, Stim-Lab, PetroFina, SimTech, Univ ofOK, Corpoven, IES, Pinnacle, Halliburton, CJSC Tura, Tejas Gas, UPR, Langfang, Norton, Texaco,Pertamina, US DOE, Tex A&M
•Over 70 SPE papers since 1973
28 RegionsGermany, North Sea, Australia,Colombia, Europe, Indonesia,Vietnam, West Africa, Norway,
Malaysia, Venezuela, Siberia, Angola,China, Oman, Brazil, Wyoming,Texas, Iowa, Illinois, Colorado,
Alaska, Appalachian, Oklahoma,Ohio, Gulf of Mexico, Louisiana, New
Mexico
Oil wells, gas wells, lean and rich condensate
Well Rates Well Depths1 to 25,000 bopd <3000 to 20,000 feet
0.25-100 MMSCFD
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Outline• Fluid Flow in Porous Media• Lab Testing of Proppants
• “Darcy Flow” - viscous, laminar• “Inertial Flow” - non-Darcy conditions• “True Flow” - multiphase and non-Darcy
• Field Case Studies• Conclusions
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H.K. van Poollen - 1957
“In the past few years much considerationhas been given to the evaluation of theeffect of hydraulic fracturing on theproductivity of wells…….
….... Only little consideration has beengiven to the characteristics, and in particularthe flow capacity, of the fracture itself andits effect on well production”
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• Production rates from hydraulically fracturedwells in a given reservoir are principallydetermined by the pressure drop in thefracture:- In gas wells this is dominated by the non-Darcy flow term (βρv2) and multiphase effects.- For oil wells this is dominated by multiphase flow effects.
• Most completion engineers do not includethese effects in their fracture design. Thisresults in lower post-fracture production rates.
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The ABC’s of Improving Productionfrom Hydraulically Fractured Wells
API proppant conductivity tests were designedfor use as a reference
“do not use these values for treatment design”
Beta factor of the proppant is the criticalcomponent for evaluating the necessaryfracture conductivity
Cash flow improvement
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SPE Distinguished Lecturer Series2001 - 2002
The ABC’s of Improving Productionfrom Hydraulically Fractured Wells
C. Mark PearsonCARBO Ceramics Inc.