How Hydraulic Fracturing has Changed Sand Control - Society of ...

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Fracturing for Sand Control: How
Hydraulic Fracturing has Changed
Sand Control
Raymond Tibbles
Schlumberger Oilfield Services
Society of Petroleum Engineers
Distinguished Lecturer Program
www.spe.org/dl
2

Sand Control Goal
• The big three goals of Sand Control
– Stop/minimize production of formation solids
– Maximize i production rate/ minimizing
i i i
impairment
– Maintain performance over well life
• Has fracturing improved our ability to
delivered d these goals. And can it continue
to do so in the future?
3

Main SC Completion Types
• Non Frac
– Cased Hole Gravel Pack (CHGP)
– Open Hole Gravel Pack (OHGP)
– Stand Alone Screen (SAS)
– Formation Consolidation
• Fracturing
– Screenless Frac Pack
– High Rate Water Pack (HRWP)
– Frac Pack
– Frac followed by Expandable Screen
4

Screenless Frac Pack Completions
Indirect Vertical
Fracture
Indirect Vertical
Fracture +
Intelligent
Perforating
Weak
Optimized Perforating
and Fracturing
W or WO Resin
Consolidation
Competent
Propped
Fracture
Weak
Layer
Competent
Layer
Propped
Fracture
Weak
Weak
Competent
Competent
Piltun-Asstokhsky
Sakhalin
SPE 68638
Jauf Reservoir
Saudi Arabia
SPE 73724
Main Pass 41
SPE 107440
Yegua Formation
SPE 96289 5

HRWP Completions
• Application
– Wells where height
growth is a concern
– Equipment for frac
pack is not available
• Multiple pad/slurry
stages create short
fractures.
Sandstone
6

Frac Pack Completions
• Application: Most if not all
cased hole completions
• Single Stage of fracturing
fluid (pad) followed by
multiple slurry stages
(ramped prop conc.) with
Sandstone
tip screenout design.
• Key design requirement is
a wide highly conductive
fracture.
7

Does Exceeding Frac Pressure
Make a Difference?
8

Fracturing Improves Reliability
9
9
8
7
6
5
4
3
2
1
0
Failures/Well Life
(failure
es/year x 100)
Data courtesy of George King (June 2003)

Fracturing Improves Production
o
ability
Cum mulativ ve Prob
120%
100%
80%
60%
Frac pack
Gravel Pack
HRWP
40%
20%
0%
0% 50% 100% 150% 200%
Flow Efficiency
Reference # Wells
IPTC 11166 4
SPE 103779 8
SPE 110359 2
SPE 111455 1
SPE 30093 17
SPE 30115 7
SPE 30470 36
SPE 31475 17
SPE 36423 12
SPE 36459 8
SPE 38592 10
SPE 39478 10
SPE 63107 4
SPE 68753 25
SPE 73722 35
SPE 77434 6
SPE 78322 4
SPE 84259 10
SPE 86530 1
SPE 87199 31
SPE 96307 7
Grand Total 255
10

5000 bopd
Chance to get
3000 bopd?
24.8% max 6600 bopd
50.2% max of 8400 bopd
37.3% max of 6600 bopd
11

Causes of Low Productivity in
Gravel Packs
• Low gravel permeability in the perforation
tunnels.
– Crushed zone;
– Gravel/sand mixing;
– Post-perforating ti fluid loss pills
• Fines migration over time
12

Reality of Packed Perforations
Ideal Perforations
The Cold Hard Truth
A
B
C
A
B C
Region A Region B Region C
13
Region A Region B Region C

Fines Migration in a Gravel Pack
(data supplied by NS Operator)
/psi)
PI (blpd
8
14
7
6
5
4
3
2 PI (blpd/psi)
1
Skin Factor
0
0 200 400 600
12
10
8
6
4
2
0
Skin
Time (days)
50% of the PI is lost in the first year.
(26 lb/ft gravel) 14

What Does Fracturing Do To Help?
• Ensures that the critical area of the
perforation tunnel is full of clean gravel
free of formation sand or debris High
perm gravel in perfs
• Increases the reservoir contact t area.
– Decreases fluid velocity in the reservoir
Reduced tendency for fines migration
15

Fracturing Puts More Gravel
Through h Perforations
• Generally accepted industry value for
gravel packing perforations: 25 lb/ft of
perforations.
• One NS Operator HRWP Avg: 112 lb/ft
of perforations.
• Same NS Operator Frac Pack Avg: 516
lb/ft of perforations
16

Fracturing Increases Reservoir
Contact
Gravel Pack 3 ft Half 30 ft Half
Length Frac Length Frac
200 ft 2 1100 ft 2
11000 ft 2
82% Reduction
In Sand Face
98% Reduction
In Sand Face
H = 92 feet
Velocity
Velocity
Rw = 8.5 inch
Perf diameter = 0.83 inch
Shot density = 21 spf 17

More Area Means No Fines Migration
Form Fluid Ve elocity (ft t/sec)
0.00050
0.00040
0.00030
0.00020
0.0001000010
0.00000
GP
HRWP
Frac Pack
Fines
0 2000 4000 6000 8000 10000
Flow 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

Impact of Gravel Volume
(oil well case in a low bhp reservoir)
I (blpd/ps i/ft)
Norm malized P
0.35
0.3
0.25
02 0.2
0.15
0.1
0.05
0
HRWP
Frac Pack
Frac & Pack
Linear (Frac Pack)
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

Better Understanding is Improving Results
(SPE 71658 Morales et al)
• Near wellbore temperature cool down from
injection of pre-frac and frac-pack fluids.
( OF )
BHT
300
280
260
240
220
200
180
160
140
120
Acid
1 st Calib 2 nd Calib
190 o F
12000
10000
8000
6000
4000
2000
0
BHP
(psi)
1900 2000 2100 2200 2300
Time (min)
20

Temperature cool down inside the fracture
(after Sinclair)
TD
1
0.8
0.6
0.4
0.2
0
T
D
=
T
T
r
−T
i
−T
i
90%
70%
50% 30%
20%
10%
5%
0 0.2 0.4 0.6 0.8 1
X/L
21

New Techniques – Fluid Selection
• Cool-Down Based Fluid
Selection
– Improved success
rate of achieving Tip
Screenout (TSO)
– Allows optimization
p y
breaker loading
300
280
260
240
rate of achieving Tip 220
BHT ( OF )
200
180
160
of polymer and 140
Acid
1 st Calib
190 o F
2 nd Calib
120
0
1900 2000 2100 2200 2300
Time (min)
12000
10000
8000
6000
4000
2000
BH HP (psi)
Rate (M MMCFD)
70
60
50
40
30
20
10
0
*Tubing Limited
Conventional
Cool Down Technique
A1 A2 A3 A4 B1 B2 B3*
Well
Bottom hole temperature profile during treatment –
Fluid Designed at 190 O F
22

Facing Up To The Challenges?
• Unwanted adjacent water and gas
• Brown fields/depleted reservoirs
• High permeability formations
• Thicker zones ( > 500 ft) w/ Multi-lobes
lobes
• Emerging area deep water.
• UltraDeep water
– Deeper
– Absence of stress barriers
– Higher Pressure
– Higher Temperature
23

Is Fracturing Out of Zone Really a Problem?
• Soft rocks and standard design
limits height growth.
– Low Young’s Modulus
– TSO inhibits growth
– Low efficiency frac fluids.
• Proper precautions minimize even
severe risk.
(SPE 73776 Guichard et al.)
• SPE 85259 deals with one of the
most difficult cases.
24

Height Control in Unfavorable Case
Perforate the
whole zone
Frac out of
zone
Limit the
perforation
height and
control the
fracture height
SPE 95987
8 ft shale with water below
Small frac pad
Small slurry stage
Fracture did not break through the shale
S f Tracer Log
25

Fracs Deliver in Brown Fields
• Well Data
– Casing: 5 inch
– Deviation: 33 deg
– KH: 5100 md-ft
– Depth:7550 ft
– BHST: 200 F
– Perforation:
• Density: 24 spf
• Treatment Data
– Fluid: 30 lb borate xlink
– Gravel: 16/20 LWC
– Placed: 1243 lbs/ft
• Results
– Produced d via ESP
– Post FP PI/Pre FP PI: 1.04
– Post FP Skin: -0.5
26

High Permeability Concerns
• SPE39475: limit frac packs
– Oil Kf < 900 md
– Gas Kf < 150 md.
– OH GP for the highest rate wells
• SPE 111455: Frac Packs are the best
solution for high permeability formation
if the wellbore is properly aligned with
the fracture.
27

Cased Hole Frac-Packs
Openhole Horizontal
or
Openhole Frac-Pack
or
Openhole GP Above
Frac Pressure?
Transmisibility (kh) 1000 mD-ft
Oilfield Review, Summer 2001 (BP, Chevron, EniAgip, M-I,
Repsol-YPF, Schlumberger, Shell, Stone Energy, Texaco)
28

High Rate Limitions
– Pressure Loss in Perforation tunnel (Forchheimer)
0.888 L μ
13
Δ P= Q + 9.1×
10 βLρ ⎡Q⎤
KA
⎢
⎣A⎥
⎦
Where:
A = Perf Cross-Sectional Area (Ft2)
B = Inertia Coefficient (Ft-1)
∆
∆P = Differential Pressure (psi)
K = Permeability (Darcies)
L = Length Of Perforation (ft)
μ = Viscosity (Centipoise)
Q = Flow Rate (B/D)
ρ = Density Of Fluid (lb/Ft3)
2
90º 10º 0º

High Rate Gas Skin (SPE 68753)
• Avg Damage Skin
Damage
Skin
400
350
300
(Deviation and Partial completion 250
skins removed)
200
– All Cases
• FP = 18
• HRWP = 55*
– Less than 1 Darcy
•FP = 18
• HRWP = 31*
Rat te Depende nt Skin Coe eff
(1/MSC CFD)
150
100
*Neglected 800 Skin 0.001
50
0
1
0.1
0.01
0.0001
Sd HRWP
Sd FP
0 1000 2000 3000 4000 5000
Permeability (mD)
D HRWP
D Frac Pack
0 1000 2000 3000 4000 30 5000
Permeability (mD)

Frac Packs Can Deliver High
Production Rate Completions
• Gas
– SPE106854 BP Trinidad and Tobago:
• Oil
• FP 75-150 MM/day (100 – 600 mD)
• OH GP: 72 – 320 MM/day (100 – 1700 mD)
– SPE 78322 Total Angola:
• FP 15,000 – 25,000 bopd (800-2700 mD)
– SPE 84415 ConocoPhillips USA:
• 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

Other Options in Emerging Deep
• Rig Based Fracturing
Water
– Dependent on available deck space
– Inhibits many rig operations
– Limited rates and volumes
• Supply Boat Based Fracturing
– Limited Rates and Volume but more flexibility
– Minimum impact on rig operations
32

Modular Supply Vessel Operation
(900m2 deck area)
• 650,000 lbm of proppant
• 10,000000 psi MWP
• 40 BPM max rate
• 9,000 HHP
• 200,000 gals batch mixed gel
stored below deck
• Connected to Rig via 4” 10,000 psi
Coflexip hose c/w EQD on TR12
Reel
33

Lower Tertiary - Miocene and Paleogene
Water Depth 4 – 10,000 ft
> 1500 ft
TVD 15,000 ft – 33, 000 ft
BHP 13 ppg – 15.2 ppg
BHT 160 OF – 310 ºF
34

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
reductions from 22 to 39% with an average
surface pressure reduction of 34%
Δp
L
=
2fρV
D
2
• Temperature and Pressure: Still struggling
to provide a high density fluid that can
work at 325+ ºF
35

Facing Up To The Challenges?
• Unwanted adjacent water and gas
• Brown fields/depleted reservoirs
• High permeability formation
–Gas
–Oil
• Emerging Area Deep Water
• UltraDeep Water Plays
– Deeper
– Higher Pressure
– Higher Temperature
36

Conclusions
• Sand Control fracturing completions have clearly
shown increased productivity in many different
environments.
• Many of the challenges to using fracturing have already
been overcome
– Unwanted water/gas
– High permeability formations
– Application in developing areas
• Some challenges still require work or may not be
applicable
– Ultra high permeability (especially in gas wells)
– High pressure especially in combination with temperature
above 325 F
37

Questions?
38

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