Fracturing for Sand Control
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Transcript of Fracturing for Sand Control
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Fracturing for Sand Control: HowFracturing for Sand Control: How Hydraulic Fracturing has Changed
S d C t lSand Control
Raymond TibblesSchlumberger Oilfield Services
Society of Petroleum EngineersSociety of Petroleum Engineers Distinguished Lecturer Programwww.spe.org/dl
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Sand Control Goal
The big three goals of Sand Control The big three goals of Sand Control Stop/minimize production of formation solids
M i i d ti t / i i i i Maximize production rate/ minimizing impairmentMaintain performance over well life Maintain performance over well life
Has fracturing improved our ability to d li d th l A d it tidelivered these goals. And can it continue to do so in the future?
3
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Main SC Completion Typesp yp Non Frac
Cased Hole Gravel Pack (CHGP) Open Hole Gravel Pack (OHGP)
St d Al S (SAS) Stand Alone Screen (SAS) Formation Consolidation
F t i Fracturing Screenless Frac Pack
Hi h R t W t P k (HRWP) High Rate Water Pack (HRWP) Frac Pack
F f ll d b E d bl S Frac followed by Expandable Screen4
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Screenless Frac Pack Completions
Indirect Vertical Fracture
Indirect Vertical Fracture +
Optimized Perforating and Fracturing
Intelligent Perforating
W or WO Resin Consolidation
Weak Layer
Competent
Weak
Weak
ProppedFractureLayer
ProppedFracture
Competent
Competent
Weak
Fracture
CompetentLayer
Jauf Reservoir Saudi Arabia
Piltun-AsstokhskySakhalin
Main Pass 41 SPE 107440
SPE 73724Sakhalin
SPE 68638 Yegua FormationSPE 962895
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HRWP Completions
Application
Wells where height growth is a concern
Sandstone
growth is a concern
Equipment for frac pack is not availablepack is not available
Multiple pad/slurry stages create short fractures.
6
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Frac Pack Completions
Application: Most if not all cased hole completions
Single Stage of fracturing g g gfluid (pad) followed by multiple slurry stages ( d ) ith Sandstone(ramped prop conc.) with tip screenout design.
Key design requirement is a wide highly conductive f tfracture.
7
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Does Exceeding Frac Pressure gMake a Difference?
8
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Fracturing Improves Reliabilityg p y
89
e
0
)
567
e
l
l
L
i
f
e
a
r
x
1
0
234
r
e
s
/
W
e
e
s
/
y
e
a
01
F
a
i
l
u
r
(
f
a
i
l
u
r
e
(
Data courtesy of George King (June 2003)9
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Fracturing Improves Productionactu g p o es oduct o120%
Frac packReference # Wells
IPTC 11166 4SPE 103779 8
80%
100%
a
b
i
l
i
t
y
pGravel PackHRWP
SPE 110359 2SPE 111455 1SPE 30093 17SPE 30115 7SPE 30470 36SPE 31475 17SPE 36423 12
40%
60%
v
e
P
r
o
b
SPE 36423 12SPE 36459 8SPE 38592 10SPE 39478 10SPE 63107 4SPE 68753 25SPE 73722 35
0%
20%
40%
m
u
l
a
t
i
v
SPE 73722 35SPE 77434 6SPE 78322 4SPE 84259 10SPE 86530 1SPE 87199 31SPE 96307 7
0%0% 50% 100% 150% 200%C
u
m
Flow Efficiency
SPE 96307 7Grand Total 255
10
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5000 bopdChance to getChance to get 3000 bopd?p
24.8% max 6600 bopd
50.2% max of 8400 bopd
1137.3% max of 6600 bopd
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Causes of Low Productivity in G l P kGravel Packs
Low gravel permeability in the perforation Low gravel permeability in the perforation tunnels.
Crushed zone; Crushed zone; Gravel/sand mixing;
P t f ti fl id l ill Post-perforating fluid loss pills Fines migration over time
12
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Reality of Packed PerforationsIdeal Perforations The Cold Hard Truth
AABC
AB
C
Region A Region B Region CRegion A Region B Region C
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Fines Migration in a Gravel Pack(data supplied by NS Operator)(data supplied by NS Operator)
1478
81012
567
n
/
p
s
i
)
468
234
S
k
i
n
P
I
(
b
l
p
d
PI (bl d/ i)
024
012 PI (blpd/psi)
Skin Factor
0 200 400 600Time (days)
50% of the PI is lost in the first year.(26 lb/ft gravel) 14
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What Does Fracturing Do To Help?g p
Ensures that the critical area of theEnsures that the critical area of the perforation tunnel is full of clean gravel free of formation sand or debris Highfree of formation sand or debris High perm gravel in perfs
I th i t t Increases the reservoir contact area.
Decreases fluid velocity in the reservoir yReduced tendency for fines migration
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Fracturing Puts More Gravel Th h P f tiThrough Perforations
G ll t d i d t l f Generally accepted industry value for gravel packing perforations: 25 lb/ft of
f tiperforations.
One NS Operator HRWP Avg: 112 lb/ft p gof perforations.
S NS O t F P k A 516 Same NS Operator Frac Pack Avg: 516 lb/ft of perforations
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Fracturing Increases Reservoir ContactContact
Gravel Pack 3 ft Half 30 ft HalfLength Frac Length Frac
200 ft2 11000 ft21100 ft2200 ft2 11000 ft21100 ft282% ReductionIn Sand Face
98% ReductionIn Sand Face
H = 92 feetRw = 8.5 inch
Velocity Velocity
Perf diameter = 0.83 inchShot density = 21 spf 17
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More Area Means No Fines Migration0.00050
t
/
s
e
c
)
GP
0.00030
0.00040
e
l
o
c
i
t
y
(
f
t HRWP
Frac Pack
Fines
0 00010
0.00020
F
l
u
i
d
V
e
0.00000
0.00010
0 2000 4000 6000 8000 10000
F
o
r
m
0 2000 4000 6000 8000 10000Flow Rate (blpd)
Every formation has a different critical fines movement Every formation has a different critical fines movement velocity. This is one case where it was 0.00029 ft/sec 18
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Impact of Gravel Volume( il ll i l bh i )(oil well case in a low bhp reservoir)
0.35
i
/
f
t
)
HRWP
0 2
0.25
0.3
I
(
b
l
p
d
/
p
s HRWP
Frac Pack
Frac & Pack
0.1
0.15
0.2
m
a
l
i
z
e
d
P Linear (Frac Pack)
0
0.05
N
o
r
m
For this e ample there appears to be a link
0.0 500.0 1000.0 1500.0 2000.0
lbs gravel placed/ft of perforations
For this example there appears to be a link between gravel mass and Normalized PI. This is
not always the case. 19
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Better Understanding is Improving Results(SPE 71658 Morales et al)
Near wellbore temperature cool down from injection of pre-frac and frac-pack fluids.
280300
10000
120001st Calib 2nd Calib
200220240260
(
O
F
)
6000
8000
10000
BHP
Acid
140160180200
B
H
T
2000
4000
6000 (psi)190oF
120140
1900 2000 2100 2200 23000
Time (min)20
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Temperature cool down inside the fracture(after Sinclair)
1
(after Sinclair)
0.8
190%i
Dr i
T TTT T=
0.4
0.6
T
D
70%
50% 30%10%
0.2
0.420%
5%0
0 0.2 0.4 0.6 0.8 1
X/LX/L
21
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New Techniques Fluid SelectionC l D B d Fl id Cool-Down Based Fluid Selection Improved success
rate of achieving Tip 220240260280300
O
F
)
8000
10000
12000
BHAcid
1st Calib 2nd Calib
rate of achieving Tip Screenout (TSO)
Allows optimization of polymer and 140
160180200220
B
H
T
(
O
2000
4000
6000
HP
(psi)
190oF
p ybreaker loading 120
1900 2000 2100 2200 2300
Time (min)
0
Bottom hole temperature profile during treatment Fluid Designed at 190O F
40506070
M
M
C
F
D
)
Conventional
Cool Down Technique
0102030
R
a
t
e
(
M
*Tubing Limited22
A1 A2 A3 A4 B1 B2 B3*Well
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Facing Up To The Challenges? Unwanted adjacent water and gas Brown fields/depleted reservoirs High permeability formations Thicker zones ( > 500 ft) w/ Multi-lobesThicker zones ( 500 ft) w/ Multi lobes Emerging area deep water. UltraDeep water UltraDeep water
DeeperAb f t b i Absence of stress barriers
Higher Pressure Higher Temperature Higher Temperature
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Is Fracturing Out of Zone Really a Problem?
Soft rocks and standard design limits height growth.
Low Youngs Modulus
TSO inhibits growth TSO inhibits growth
Low efficiency frac fluids.
Proper precautions minimize even Proper precautions minimize even severe risk. (SPE 73776 Guichard et al )(SPE 73776 Guichard et al.)
SPE 85259 deals with one of the t diffi ltmost difficult cases.
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Height Control in Unfavorable Case
Perforate the whole zone
Limit the perforation whole zone
Frac out of zone
pheight and control the fracture height
SPE 959878 ft shale with water belowS f Tracer LogSmall frac pad Small slurry stageFracture did not break through the shale
Tracer Log
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Fracs Deliver in Brown Fields
Well Data Treatment Data Casing: 5 inch Deviation: 33 deg
KH 5100 d ft
Fluid: 30 lb borate xlink Gravel: 16/20 LWC
Pl d 1243 lb /ft KH: 5100 md-ft Depth:7550 ft
BHST: 200 F
Placed: 1243 lbs/ft Results
P d d i ESP BHST: 200 F Perforation:
Density: 24 spf
Produced via ESP Post FP PI/Pre FP PI: 1.04 Post FP Skin: -0 5Post FP Skin: 0.5
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High Permeability Concerns
SPE39475: limit frac packsp
Oil Kf < 900 md Gas Kf < 150 md. OH GP for the highest rate wells g
SPE 111455: Frac Packs are the best solution for high permeability formationsolution for high permeability formation if the wellbore is properly aligned with the fracturethe fracture.
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Cased Hole Frac-PacksCased Hole Frac Packs
Openhole Horizontalor
Openhole Frac-Packor
Openhole GP Above pFrac Pressure?
Oilfield Review Summer 2001 (BP Chevron EniAgip M-ITransmisibility (kh) 1000 mD-ft
Oilfield Review, Summer 2001 (BP, Chevron, EniAgip, M I,Repsol-YPF, Schlumberger, Shell, Stone Energy, Texaco)
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High Rate Limitionsg Pressure Loss in Perforation tunnel (Forchheimer)
2130.888 9.1 10L Q QP L
KA A = +
Where:A = Perf Cross-Sectional Area (Ft2)B = Inertia Coefficient (Ft-1)
90 10 0
P = Differential Pressure (psi)K = Permeability (Darcies)L = Length Of Perforation (ft) = Viscosity (Centipoise) = Viscosity (Centipoise)Q = Flow Rate (B/D) = Density Of Fluid (lb/Ft3)
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High Rate Gas Skin (SPE 68753)400
Avg Damage Skin (Deviation and Partial completion 250
300350400
e
S
k
i
n
Sd HRWP
Sd FP
( pskins removed)
All CasesFP 18
50100150200
D
a
m
a
g
e
FP = 18 HRWP = 55*
Less than 1 Darcy
00 1000 2000 3000 4000 5000
Permeability (mD)1
e
f
f
Less than 1 Darcy FP = 18 HRWP = 31*
0.1
1
n
t
S
k
i
n
C
o
e
C
F
D
)
HRWP = 31
*Neglected 800 Skin 0.0010.01
t
e
D
e
p
e
n
d
e
(
1
/
M
S
C
D HRWP
D Frac Pack
0.00010 1000 2000 3000 4000 5000
R
a
t
Permeability (mD)30
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Frac Packs Can Deliver High Production Rate CompletionsProduction Rate Completions
Gas SPE106854 BP Trinidad and Tobago:
FP 75-150 MM/day (100 600 mD) OH GP: 72 320 MM/day (100 1700 mD) OH GP: 72 320 MM/day (100 1700 mD)
Oil SPE 78322 Total Angola:g
FP 15,000 25,000 bopd (800-2700 mD) SPE 84415 ConocoPhillips USA:
FP two wells 22 400 bopd/well FP two wells 22,400 bopd/well FP Non documented GOM 40,000 bopd SPE 48977 BP North Sea:
OH Horizontal 30,000 bopd 31
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Other Options in Emerging Deep WaterWater
Rig Based Fracturing Dependent on available deck space Inhibits many rig operations Limited rates and volumes
Supply Boat Based FracturingSupply Boat Based Fracturing Limited Rates and Volume but more flexibility Minimum impact on rig operations Minimum impact on rig operations
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Modular Supply Vessel Operation(900m2 deck area)(900m2 deck area)
650,000 lbm of proppant10 000 i MWP
200,000 gals batch mixed gel stored below deck 10,000 psi MWP
40 BPM max rate 9,000 HHP
stored below deck Connected to Rig via 4 10,000 psi
Coflexip hose c/w EQD on TR12 Reel
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Lower Tertiary - Miocene and Paleogene
Water Depth 4 10,000 ft
> 1500 ft
TVD 15,000 ft 33, 000 ft
> 1500 ft
BHP 13 ppg 15.2 ppg
BHT 160 OF 310 F 34
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Challenges and Solutions Temperature: No problem we have fluids
to handle 400+ degrees F.
High Pressure:
20000 psi treating equipment - does the market justify the cost?
High density frac fluids to help but there are limits. SPE 116007 reported surface pressure D
V2fLp 2=
limits. SPE 116007 reported surface pressure reductions from 22 to 39% with an average surface pressure reduction of 34%
T t d P Still t li
DL
Temperature and Pressure: Still struggling to provide a high density fluid that can work at 325+ F
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Facing Up To The Challenges? Unwanted adjacent water and gas
Bro n fields/depleted reser oirs Brown fields/depleted reservoirs
High permeability formation
Gas Oil
Emerging Area Deep Water
UltraDeep Water Playsp y
Deeper Higher PressureHigher Pressure Higher Temperature
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Conclusions Sand Control fracturing completions have clearly
shown increased productivity in many different environments.
Many of the challenges to using fracturing have already been overcomebeen overcome Unwanted water/gas
High permeability formationsHigh permeability formations
Application in developing areas
Some challenges still require work or may not be g yapplicable Ultra high permeability (especially in gas wells)
High pressure especially in combination with temperature above 325 F
37
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Society of Petroleum Engineers Distinguished Lecturer Programwww.spe.org/dl 39