let’s put engineering back into fracture stimulation! · pdf fileneil stegent, p.e....
TRANSCRIPT
Neil Stegent, P.E.
Pinnacle – a Halliburton Service
1
Let’s put Engineering back into
Fracture Stimulation!
Oklahoma Geological Society – Shales Moving Forward
Norman, Oklahoma; 21 July 2011
The Company President asking his staff .........
....... How are we going to “Frac” this well?
What are the other Operators doing on their wells?
How much is it going to cost?
HOW MUCH!!!!!
Why’s it cost so much?
Do we really need to do all that stuff?
What stuff can we leave out?
Do you think it will work if we don’t do all that stuff?
Who’s going to figure it out if it doesn’t work?
Fig. 10 - Log kh vs. 6 Month Oil Cumulative
R2 = 0.6994
0
20
40
60
80
100
120
- 5,000 10,000 15,000 20,000 25,000
6 Month Oil Cumulative, BO
Lo
g D
eriv
ed
In
-Sit
u P
erm
ea
bil
ity
-Th
ick
ne
ss
, m
d-f
t
Trendline
Engineered
Completions
Un-Engineered
Completions
Well Response @ 12 Months - Greater Than 300oF
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0 1,000,000 2,000,000 3,000,000 4,000,000 5,000,000 6,000,000
12-Month Cumulative Production (MCF)
Cu
mu
lati
ve F
req
uen
cy (
%)
Other
HES
• Horsepower
• Fluid
• Proppant
Schedule:
1) Perforate
2) Pump
3) Repeat
kX
wKFcd
f
f
Fig. 10 - Frac Finding Costs for Project Wells
$-
$0.10
$0.20
$0.30
$0.40
$0.50
$0.60
$0.70
$0.80
1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31
Well List
Fra
c F
ind
ing
Co
sts
, $/E
UR
mcf Pre-Reservoir Description Usage
Average = $0.21 STD Dev = $0.18
Post-Reservoir Description Usage
Average = $0.10 STD Dev = $0.05
4
Eagle Ford Shale - Background
Oil
Dry Gas
Gulf of Mexico
• Depth Range: 4,000’ – 14,000’
• BHT Range: 150°F - 350°F
• Pres Grad. Range: 0.55 – 0.85 psi/ft
• Can produce Dry gas @ 8000’ and
High Liquids @ 13,000’ , Oil @ 5000’
5
180’ 120’
SPE 136183
Mineralogy
Characterization
Brittleness
Index
TOC and
Kerogen
Rock
Properties
Raw Data
Eagle Ford Shale - Petrophysics
6
Frac Design in Horizontal: Run Sensitivities
• Injection Rate
• Fluid Volumes
• Fluid Viscosity
• Prop Volume
• Prop Concentration
• Prop Mesh Size
• Others
Near Wellbore Restriction (tortuosity)Issues with Proppant Placement
• Transverse fracture initiation in perf cluster that is to long c
...can create multiple fractures (SPE 19720).
• Multiple fractures can create tortuosity (SPE 35194).
• Limit perf interval to 4 times the ID of the casing (SPE 86992)
• Use Acid Soluble Cement in Horizontal (SPE 137441)
Image from SPE 19720 by El Rabaa, 1998
and SPE 102616 by Soliman, 2006
Impact of Perforation on the Formation:
Perforation Damage - Crushed, Compacted, “Onion-Skin” Zone
Perforation TunnelCement
Blue-DyedFracture
Onion-Skin
Un-fracturedHalo around
compaction zone
Pipe
Work by Norm Warpinski, 1983
Formation
Compaction
Zone (Halo)
9
Frac Design Considerations
SPE 136183
20/4030/50
40/70
700 m400 m300 m
Embedment Core TestsEagle Ford Shale
0.35 – 0.77 mm @ 10,000 psi
SPE 136801
SPE 135502
40/80 MeshLightweight Ceramic
Haynesville Core Sample
10
200 cp
50 cp
Bauxite
80 md-ft
RCP
25 md-ftSand
5 md-ft
Non-Emulsifiers needed for Oil
Proppant Conductivity
Multi-phase flow“Hybrid” Frac Fluid
kX
KwF
f
ffcd 50
0.001md *ft 500
ft-md 25
Frac Design Considerations
950 cp
35# Polymer
Loading
Dimensionless Conductivity (Fcd)
11
Frac Design Considerations: Basic Definitions (SPE 136183)
Water Frac or Slick Water Frac:
• Frac fluid is very low viscosity
• Chemicals or gelling agents are used for friction reduction, not prop transport
• Velocity (not viscosity) used to place proppant
• Injection rates tend to be high
• Typically have alternating stages of proppant followed by fluid “sweeps”
Conventional Frac:
• Frac fluid is high viscosity (from foams to crosslinked fluids)
• Chemicals used to generate viscosity for proppant transport
• Viscosity (not velocity) used to place proppant
• Injection rates can vary greatly (not depending on velocity to place prop).
• Typically have “pad” fluid followed by continuous proppant-laden fluid.
Hybrid Frac:
• Anything in-between a water frac and a conventional frac.
• Typically, a hybrid frac is a combination of the two.
• They tend to begin with a low-viscosity fluid (at a high rate)
• May have alternating proppant volumes with fluid “sweeps”
• Tail-in (sometimes at a lower injection rate) with proppant high-viscosity fluid.
• Large part of job may be crosslinked or just Tail-in fluid may be crosslinked.
12
Production Comparison: Slick Water vs. Hybrid/Conventional
1
10
100
1,000
10,000
0
50
100
150
200
250
300
0 50 100 150 200 250 300 350 400 450
Pre
ss
ure
Ra
te
Days on Production
Rate vs Time
Oil Rate [bopd] Gas Rate [mcfpd]
Water Rate [bwpd] FTP [psi]
Migura A#1
1st year production150,000 bbls oil 1st year
518,000 mscf (0.5 bcf)
(Hybrid Frac/Conventional )
1st year production5,500 bbls oil 1st year
16,900 mscf (0.017 bcf)
(Slick Water Frac)
1
10
100
1,000
10,000
0
50
100
150
200
250
300
0 50 100 150 200 250 300 350 400 450
Pre
ss
ureR
ate
Days on Production
Rate vs Time
Oil Rate [bopd] Gas Rate [mcfpd]
Water Rate [bwpd] FTP [psi]
Migura A#1
1
10
100
1,000
10,000
0
500
1,000
1,500
2,000
2,500
3,000
3,500
4,000
0 50 100 150 200 250 300 350 400 450
Ra
te
Days on Production
Rate vs Time
Oil Rate [bopd] Gas Rate [mcfpd]
Water Rate [bwpd] FTP [psi]
Krause Unit 1 #1
Pre
ssu
re
FTP
GasOil
7000 psi,
3 MMscfd,
1000 bopd
400 psi,
0.15 MMscfd,
25 bopd
Choke Sizes: 10-20 first 140 days
13
Frac Mapping:
700’4,000’
4,700’
Target
Austin Chalk
Upper EF
Lower EF
Buda
Pilo
t ho
le
Good Zonal
Coverage
Rosetta Resources – Gates Leases
Well Planning
Lateral Placement
Good Well Direction
Good Well Spacing
Monitor
Well
SRV – Stimulated
Reservoir Volume
14
Frac Mapping for Frac Model Calibration:
Top
View
Side
ViewFrac Match with
Microseismic Events
Initial
Frac Design
Divide 6-160 S2
SC
on
c (
PP
G)
- B
HC
on
c (
PP
G)
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
10
.0
SR
ate
(B
PM
)
10
.02
0.0
30
.04
0.0
50
.06
0.0
70
.08
0.0
90
.01
00
.0
WH
TP
(p
si)
- B
HT
P_
C (
psi)
10
00
20
00
30
00
40
00
50
00
60
00
70
00
80
00
90
00
10
00
0
Time (min)10.0 20.0 30.0 40.0 50.0 60.0
15
Post Frac Hydrocarbon Flow Profiling
Information provided by TracerCo
A hydrophobic tracer is added to each frac stage.
Each of the hydrophobic tracers dissolves within reservoir hydrocarbons.
Surface flowback samples are analyzed for the different tracers.
Analysis verification of stage flow and its relative contribution to production.
16
Post Frac Hydrocarbon Flow
0
5
10
15
20
25
Stage 1 Stage 2 Stage 3 Stage 4 Stage 5 Stage 6 Stage 7 Stage 8 Stage 9 Stage 10 Stage 11 Stage 12 Stage 13 Stage 14 Stage 15 Stage 16
Rela
tive %
of
Pro
du
cti
on
Flo
w
Stage Production Flow
Initial Production
Production af ter Choke Chg
Production during Frac Monitor Well
After Frac Production
Production af ter restart
No T
racer
Pum
ped
No T
racer
Pum
ped
17
Production Analysis - 1/Rate vs. Cum Prod
The slope is proportional to the system perm and fracture length
A constant slope indicates “stabilized” fracture conductivity (after clean-up)
First trend: must have a non-negative intercept Intercept is a qualitative measurement of conductivity of the fracture network
Zero intercept = infinite conductivity Positive intercept = finite conductivity
Second trend: influenced by boundaries Either drainage boundaries or interference between fractures
SPE 139981 & 142382
Normalized by Length
of Lateral Stimulated
Wattenbarger Method
Dr Jeff Callard,
University of Oklahoma
2500 ft Lateral with
11 frac stages
300, 000 lbs per stage
5000 ft Lateral with
14 frac stages
300,000 lbs per stage
18
The Company President asking his staff .........
....... How are we going to “Frac” this well?
What are the other Operators doing on their wells?
How much is it going to cost?
HOW MUCH!!!!!
Why’s it cost so much?
Do we really need to do all that stuff?
What stuff can we leave out?
Do you think it will work if we don’t do all that stuff?
Who’s going to figure it out if it doesn’t work?
You Are! And you can because you have Data!
