the abc’s of improving production from hydraulically fractured … · 2020. 6. 17. · sp-300...

SPE Distinguished Lecturer Series2001 - 2002

The ABC’s of Improving Productionfrom Hydraulically Fractured Wells

C. Mark PearsonCARBO Ceramics Inc.

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.

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.

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

“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

Darcy’s Experiment

Darcy’s Data

Dis

char

ge, L

iters

per

Min

ute

Drop in Head Across Sand (Meters of Water)

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 −∗=

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

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

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

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.

• 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

Ports for Measuring Differential Pressure Temperature Port

Disassembled API Proppant Cell

Proppant Bed

Sandstone CoresFlow ThroughProppant Bed

Long Term Conductivity Cells

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

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

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

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

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)

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).

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

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.

0

1000

2000

3000

4000Ef

fect

ive

Con

duct

ivity

(md-

ft)

API "Darcy Flow" Viscous Flow

Conditions


Effects

"True Flow" Multiphase andNon-Darcy Flow


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.

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.

Kuparuk River Field, Alaska

Case Study #1SPE 20707 & 24857

North Slope

Kuparuk

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.

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.

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

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

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)

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

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

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

Birch Creek Unit,Green River Basin - WY

Case Study #2 - SPE 67299

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

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

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 ?

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

0

250

500

750

1000Ef

fect

ive

Con

duct

ivity

(md-

ft)

API "Darcy Flow"Viscous Flow

Conditions


Effects

"True Flow"Multiphase andNon-Darcy Flow


Impact of Multiphase Non-Darcy FlowFrontier Formation - SPE 67299

0.00

0.25

0.50

0.75

1.00

1.25G

as R

ate

(MM

SCFD

)

API "Darcy Flow"Viscous Flow

Conditions


Effects

"True Flow"Multiphase andNon-Darcy Flow


Frontier Formation Predicted Rates104,000 lbs proppant, 0.65 lb/sq ft, 7750 ft, 0.75 psi/ft, 500 ft, 2 blpd

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

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%

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

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

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

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”

• 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.


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

SPE Distinguished Lecturer Series2001 - 2002


C. Mark PearsonCARBO Ceramics Inc.

the abc’s of improving production from hydraulically fractured … · 2020. 6. 17. · sp-300...

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