tuesday 21 may 2013 - keynote - mike vincent
DESCRIPTION
pTRANSCRIPT
1
Five things you didn’t want to know about hydraulic fractures
Mike Vincent
Fracwell
LLC
Microseismic image: SPE 119636
• Why we need to frac
• The bad news
– 5 things you didn’t want to know
• The good news
– Compensating for some of these problems can significantly improve production and profitability!
Outline
2
1. Fluid Flow Assumptions
– Can I use Darcy’s Law & published conductivity data?
2. Are fracs durable?
3. Can I simulate a reservoir as a homogeneous layer?
4. Can I model a frac as a simple vertical plane?
5. Will I reach a unique match with careful analyses?
5 Things To Investigate
Why Fracture Stimulate?
Top View
Side View
Unstimulated Wells:
Require high reservoir permeability for sufficient
hydrocarbon flow
Hydraulic Fractures:
Accumulate hydrocarbons over enormous area, achieving economic flowrates from low
permeability formations
Figures not to scale!
3
Reservoir Contact
Multi-Lateral – 15,000 ft of drilled length in 5 laterals
<24,000 ft2 of reservoir contact
Overhead, map view of 5 laterals
drilled from one wellhead.
• Propped fractures touch more rock than multi-lateral wells
• It is more cost-effective to touch rock with a fracture than with a drill bit
Tiny Frac - 20,000 lbs of proppant
Fracture Stimulated Completion: 200 ft half-length, 50 ft height
2 wings * 2 faces * 200 ft * 50 ft = 40,000 ft2 3700m2 of contact
One small transverse frac = 40,000 ft2 3700m2 of contact
Bakken = 6,000,000 ft2 560,000m2 of contact
Barnett style complex network >10,000,000 ft2 >1,000,000m2 of contact
Transversely Fractured Horizontal Wells let you Repeat this!
4
Technology Progression
0.0001
0.001
0.01
0.1
1
10
0
1
10
100
1,000
10,000
100,000
1,000,000
Perforated Vertical
Openhole Vertical
Openhole Horizontal
Biwing Fracture
Multiple Transverse Fractures
Re
se
rvo
ir P
erm
mD
Re
se
rvo
ir C
on
tac
t m
2
Reservoir Contact
Economic Gas Reservoir Perm
Economic Oil Reservoir Perm
Increasing our reservoir contact by 1,000,000 fold
has allowed pursuit of reservoirs with thousands of times lower perm
In low perm reservoirs, fractures are often
the most critical component of our
completion
However, they are the most poorly optimized element!
5
• Adequate reservoir contact (frac length)
• Adequate flow capacity (conductivity)
Two basic design goals
for fracture treatment
• Fracs
– Simple (bi-wing), planar, vertical, hydraulically continuous, highly conductive, durable
• Reservoir
– Homogenous reservoirs (or simplified layering)
• Fluid Flow
– Simple fluid flow regimes
Convenient Assumptions
6
SPE 128612
Do we envision fracs correctly?
15
We picture fracs as perfect vertical planes without restriction to hydrocarbon flow
Fracs are very narrow ribbons, massively long!
Frac length frequently
thousands of times greater than
the wellbore diameter
500
1500
7000
182
1137
5715
72
672
3481
24
225
1243
549
479
1.4
14144
0.67
130
0.3 496
0
1000
2000
3000
4000
5000
6000
7000
Eff
ecti
ve C
on
du
cti
vit
y (
md
-ft)
(D-m
)
API Test Modified 50-
Hour Test
"Inertial
Flow" with
Non-Darcy
Effects
Lower
Achieved
Width (1
lb/sq ft)
Multiphase
Flow
50% Gel
Damage
Fines
Migration /
Plugging
Cyclic
Stress
Chinese Sand
Jordan Sand
CarboLITE
Realistic Conductivity Reductions 20/40 proppants at 6000 psi
0.3
0.6
0.9
1.2
2.1
1.5
1.8
0.0001 D-m
0.001 D-m
0.029 D-m
Conditions: YM=5e6 psi, 50% gel damage, 250°F, 1 lb/ft2, 6000 psi, 250 mcfd, 1000 psi bhfp, 20 ft pay, 10 blpd
YM=34e3 MPa, 50% gel damage, 121°C, 5 kg/m2, 41 MPa, 7000 m3/d, 7 MPa bhfp, 6 m pay, 1.6 m3l/d
References: ST Sand: SPE 14133, 16415, CL: Carbo typical, LT: Stim-Lab PredK 2002, SPE 24008, 3298, 7573, 11634, CARBO Tech Rpt 99-062, Run #6542, StimLab July 2000, SPE 16912, 19091, 22850, 106301, 84306
Effective conductivities can be less than 1% of API test values
99.9% reduction
99.7% reduction
98.6% reduction
16
7
Does Conductivity Degrade?
McDaniel , SPE 15067
All published lab data show proppants continue to crush, compact, rearrange over
time and lose conductivity.
SPE 12616, 14133, 15067, 110451,128612, 134330, 136757, Hahn, Drilling Vol 47, No 6,
April 1986
Some proppants are more durable than others. But none are “constant”
Why don’t engineers recognize this?
This degradation has nothing to do with
“diagenesis”. Occurs dry, wet, mineral oil, N2
gas, between Teflon, steel, sandstone or shale
Even if fracs are perfect, wide fracs with optimal
proppant placement throughout…
Pressure losses are 50 to 1000 times higher
than we estimated!!
Now… What if the fracs are not perfect planes?
What does this mean?
8
Pollard (2005) Northeast Ship Rock Dike, New Mexico24
Relatively simple, extremely wide fracture
Extends 9500 feet at surface, average width
exceeding 7 feet!
We have created hydraulic fracs 2200 ft half-length but less than 0.1 inches wide
Pollard (2005) Northeast Ship Rock Dike25
Outcrop actually comprised of >30 discrete
echelon segments separated by intact host rock
Even this dike appeared “discontinuous” in outcrop.
Are you certain your frac is continuous?
9
Is Fracture Complexity Good or Bad?
Simple Fracture Complex Fracture
Very Complex Fracture Network
Pro:
Complex fracs increase the reservoir contact (beneficial in nano-
Darcy shales?)
Con:
Complex fracs complicate the flow path,
and provide less cumulative conductivity
than simple, wider fractures [SPE
115769,119143,144702]
SPE 7744126
NEVADA TEST SITE - HYDRAULIC FRACTURE MINEBACK
Observations of Fracture Complexity
Physical evidence of fractures nearly always
complex
10
Multiple
Fractures• Initiation At Perforations
– Multiple Perforations
Provide Multiple Entry
Points For Fracture
Initiation
– Five Separate
Fractures Are Visible
In These Fractures
Initiated From
Horizontal Wellbore
– 12 Perforations Total
• 6 Top & Bottom
I would have modeled/predicted a single frac with much
higher conductivity than 5 narrow fracs added together
[This actually is a bad outcome!]
NEVADA TEST SITEHYDRAULIC FRACTURE
MINEBACK
Multiple Strands in a Propped Fracture
(Vertical Well)
These fractures are narrow, you are looking at an angle to the exposed frac face
11
Mesaverde MWX test, SPE 22876
Physical evidence of fractures nearly always
complex
Multiple Strands in a Propped Fracture(Vertical Well)
� 7100 ft TVD [2160m]
� 32 Fracture Strands Over 4 Ft Interval
� HPG gel residue on all surfaces
� Gel glued some core together (>6 yrs elapsed post-frac!)
� All observed frac sand (20/40 RCS) pulverized <200 mesh
� A second fractured zone with 8 vertical fractures in 3 ft interval observed 60 feet away (horizontally)30
Is complexity solely attributed to “rock fabric”?
Many other examples! [TerraTek, Baker, Weijers, CSM FAST consortium]
Unconsolidated 200 mesh sand, 35 lb XLG,Flow � SPE 63233
Chudnovsky, Univ of Ill, Chicago
32
12
Physical evidence of fractures nearly always complex
NEVADA TEST SITEHYDRAULIC FRACTURE
MINEBACK
Fracture Complexity in Vertical direction
Laminated on every scale?
34
Figure 2 – On every scale, formations may have laminations that hinder vertical permeability and fracture penetration. Shown are thin laminations in the Middle Bakken [LeFever 2005], layering in the Woodford [outcrop photo courtesy of
Halliburton], and large scale laminations in the Niobrara [outcrop and seismic images courtesy of Noble]
SPE 146376
13
Woodford Shale Outcrop
Will frac complexity change my understanding of required frac design?
Narrower aperture plus significantly higher stress in
horizontal steps?
Failure to breach all laminae?
Will I lose this connection due to
crushing of proppant in horizontal step?
Our understanding of frac barriers and kv should
influence everything from lateral depth to frac fluid type, to implementation
Fractures Intersecting Stacked Laterals
Modified from Archie Taylor SPE ATW – Aug 4 2010 36
23 ft thick Lower Bakken Shale
Frac’ed Three Forks well ~1MM lb proppant in 10 stages
1 yr later drilled overlying well in Middle Bakken; Kv<0.000,000,01D (<0.01 µD)
kv/kh~0.00025 even after fracing!
Lateral separation 250 feet at
toe/heel, crossing in middle
Inability to create an effective, durable fracture 30 feet tall?!
Drill redundant well in each interval since frac has inadequate vertical penetration/conductivity?!
Bakken – Three Forks
14
Continuity Loss
Necessitates vertical downspacing?
“Array Fracturing” or “Vertical Downspacing” Image from CLR Investor Presentation, Continental, 201237
A number of operators are investigating “vertical downspacing” in the Bakken petroleum system. Similar efforts underway in Niobrara, Woodford, Montney and Permian
formations.
Is it possible that some number of these expensive wells could be unnecessary if fractures were redesigned?
Uniform Packing Arrangement?
Is this ribbon laterally
extensive and continuous
for hundreds of meters as
we model?
40
Pinch out, proppant
pillars, irregular
distribution?
A simulator may predict
this is sufficient!
15
With what certainty can we explain this production?
SPE 106151 Fig 13 – Production can be matched with a variety of fracture and reservoir parameters41
0
200
400
600
800
1000
1200
1400
1600
1800
2000
0 100 200 300 400 500 600
Production Days
Sta
ge
Pro
du
ction
(m
cfd
)
0
20
40
60
80
100
120
140
160
180
200
Cu
mu
lative
Pro
du
ction
(M
Mscf)
Actual Production Data
Nice match to measured microseismic, eh?
SPE 106151 Fig 13 – Production can be matched with a variety of fracture and reservoir parameters42
0
200
400
600
800
1000
1200
1400
1600
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0 100 200 300 400 500 600
Production Days
Sta
ge
Pro
du
ction
(m
cfd
)
0
20
40
60
80
100
120
140
160
180
200
Cu
mu
lative
Pro
du
ction
(M
Mscf)
Actual production data
Long Frac, Low Conductivity 500' Xf, 20 md-ft, 0.5 uD perm, 23 Acres 4:1 aspect ratio
16
Is this more accurate? Tied to core perm
SPE 106151 Fig 13 – Production can be matched with a variety of fracture and reservoir parameters43
0
200
400
600
800
1000
1200
1400
1600
1800
2000
0 100 200 300 400 500 600
Production Days
Sta
ge
Pro
du
ction
(m
cfd
)
0
20
40
60
80
100
120
140
160
180
200
Cu
mu
lative
Pro
du
ction
(M
Mscf)
Actual production data
Long Frac, Low Conductivity
Medium Frac, Low Conductivity
500' Xf, 20 md-ft, 0.5 uD perm, 23 Acres 4:1 aspect ratio
100' Xf, 20 md-ft, 5 uD perm, 11 Acres 4:1 aspect ratio
Can I reinforce my misconceptions?
SPE 106151 Fig 13 – Production can be matched with a variety of fracture and reservoir parameters44
0
200
400
600
800
1000
1200
1400
1600
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2000
0 100 200 300 400 500 600
Production Days
Sta
ge
Pro
du
ction
(m
cfd
)
0
20
40
60
80
100
120
140
160
180
200
Cu
mu
lative
Pro
du
ction
(M
Mscf)
Actual production data
Long Frac, Low Conductivity
Medium Frac, Low Conductivity
Short Frac, High Conductivity, Reservoir Boundaries
500' Xf, 20 md-ft, 0.5 uD perm, 23 Acres 4:1 aspect ratio
100' Xf, 20 md-ft, 5 uD perm, 11 Acres 4:1 aspect ratio
50' Xf, 6000 md-ft, 10 uD perm, 7 Acres 4:1 aspect ratio
• History matching of production is surprisingly non-unique.
• Too many “knobs” available to tweak
• We can always blame it on the geology
Even if I “know” it is a simple planar frac, I cannot prove whether it was inadequate reservoir quality, or
inadequate completion with a single well
17
1. Complex Flow Regimes
– 100x higher pressure losses
2. Conductivity Degrades
3. Heterogeneous Reservoirs
– Dependant on fracs to connect reserves
4. Complex Frac Geometry
– Require commensurate increase in conductivity
5. Non-unique interpretations
5 Things You Didn’t Want to Know
Removing the Uncertainty
• If we require a production match of two different frac designs, we remove many degrees of freedom
– lock in all the “reservoir knobs”!
– Attempt to explain the production results from initial frac AND refrac
• 143 published trials in SPE 134330
• 100 Bakken refracs 136757
– Require simultaneous match of two different frac designs in same reservoir!
• 200+ trials in SPE 11914346
18
Field Studies Documenting Production Impact
with Increased Fracture Conductivity>200 published studies identified,
authored by >150 companies
SPE 119143 tabulates over 200 field studies
Oil wells, gas wells, lean and rich condensateCarbonate, Sandstone, Shale, and Coal
Well Rates Well Depths
1 to 25,000 bopd 100 to 20,000 feet0.25-100 MMSCFD
47
Production Benefit
• In >200 published studies and hundreds of unpublished proppant selection studies,
• Operators frequently report greater benefit than expected using:– Higher proppant concentrations (if crosslinked)
– More aggressive ramps, smaller pads– Screen outs (if sufficiently strong proppant)
– Larger diameter proppant– Stronger proppant– Higher quality proppant– More uniformly shaped & sized proppant
• Frac conductivity appears to be much more important than our models or intuition predict!
A tabulation of 200 papers in SPE 11914349
19
We are 99.9% certain the Pinedale Anticline
was constrained by proppant quality
Effect of Proppant Selection upon Production
0
100
200
300
400
500
600
700
800
900
LL3
LL2
LL1
MV5
MV4
MV3
MV2
MV1
MV0
Avera
ge
Reservoir Sub-Interval (Lower Lance and Mesa Verde)
Pro
duction R
ate
100 d
ays p
ost-
frac (
mcfd
)
Versaprop
CarboProp
ISP-BS
ISP 20/40
Averages based on 95 stages ISP-BS and 54 stages ISP 20/40
SPE 106151 and 108991
70% increase in productivity achieved with
a more uniformly
sized proppant!
Can we learn from refracs?
Pagano, 2006
– Gas Condensate wells in DJ Basin – up to 5 restimulations
20
Increase Conductivity in Refracs?Dozens of examples in literature
Shaefer, 2006 – 17 years later,
tight gas
0
500
1000
1500
2000
2500
3000
3500
Jan-90 Jan-91 Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01
Gas R
ate
, M
CF
D
0
50
100
150
200
250
300
350
400
450
500
Wate
r R
ate
, B
WP
D
Gas
Water
Initial Frac in
1989:
48,000 lb 40/70
sand + 466,000
lb 12/20 sand
May 1999 Frac:
300,000 lb 20/40
LWC
May 1995 Frac:
5,000 lb 100 mesh
+ 24,000 lb 20/40
Sand
Vincent, 2002 – 9 years later,
CBM
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
Pro
du
cti
on
fro
m F
rac
ture
(b
fpd
) Original Fracture (20/40 Sand)
Phase I refrac (20/40 Sand)
Phase III refrac (16/20 LWC)
Incremental Oil Exceeds
1,000,000
barrels
Incremental
Oil exceeds650,000 barrels
First Refrac
Second Refrac
Pospisil, 1992 – 6 years later,
20 mD oil
0
500
1000
1500
2000
2500
Sta
biliz
ed
Ra
te (
MS
CF
D)
Pre Frac 10,000 gal
3% acid +
10,000 lb
glass beads
80,000 gal +
100,000 lb
20/40 sand
75,000 gal +
120,000 lb
20/40 ISP
Ennis, 1989 – sequential
refracs, tight gas
020406080100120 Well A Well B Well C Well D Well EProduction Rate (tonnes/day) .. Initial FracRefracDedurin, 2008, Volga-Urals
oil
52
If this is not compelling…
Is there additional irrefutable
evidence that our fracs are not
as effective as we thought?
21
Offset wells (orange)
perfed at same depth
loaded with frac fluid
After unloading fluid,
several offset wells
permanently stimulated
by treatment!
Fractures Intersecting Offset Wellbores
-3000
-2500
-2000
-1500
-1000
-500
0
500
1000
1500
-1000 -500 0 500 1000 1500 2000 2500 3000
West-East (ft)
So
uth
-No
rth
(ft
)
Observation
Well
Barnett Shale
SPE 7744154
Evidence frac’ed into offset wells (at same depth)
Microseismic mapping
Slurry to surface
Increased watercut
Solid radioactive tracer (logging)
Noise in offset monitor well
Documented inTight sandstone (Piceance, Jonah, Cotton
Valley, Codell)High perm sandstone (Prudhoe)
Shale (Barnett, Marcellus, Muskwa, EF)
Dolomite (Middle Bakken)Chalk (Dan)
Often EUR, “pulse tests” “interference tests” fail to indicate sustained hydraulic
connectivity!
-2000
-1800
-1600
-1400
-1200
-1000
-800
-600
-400
-200
0
200
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-3300
-3100
-2900
-2700
-2500
-2300
-2100
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-1700
-1500
-1300
-1100
-900
-700
-500
-300
-100
100
300
500
700
900
1100
1300
1500
West-East (ft)
So
uth
-No
rth
(ft
)
1st Stage 2nd Stage
= First Stage Perf Clusters
= 2nd Stage Initial Perf Clusters
= Revised 2nd Stage Perf Clusters
Observation Well
Treatment Well
3000’ x 2900’
Two Stage Cemented Barnett Shale Lateral
SPE 90051
9 million square feet >200 acres
22
How far do we drain? Barnett Infill Drilling
Source: Brian Posehn, EnCana, CSUG April 28, 2009
When operators have infill drilled on
385’ avg
spacing
Infill wells “steal” 6% of parent
EUR
Infill wells produce 80% of
parent EUR
• Sometimes adjacent wells are improved by bashing!
Fractures Intersecting Bakken Laterals
Enerplus SPE 139774 – Jan 2011
Well spacing ~1250 ft. Communication at 2500 ft
30/50 MgLite, 8 BASS stages @150klbs
Borate XL fluid to 5-6 ppg at tail
23
Horn River, BC – SPE 140654
Horn River, BC Microseismic Map
We can “bash” offset laterals at 5000 ft spacing with frac water.
Sometimes we miss laterals in between.
This map is not assurance that we have drained all the hydrocarbons in the well
vicinity!!!
Source: esgsolutions.com
24
How far do we drain? Ante Creek, Montney Oil
Source: ARC Investor Presentation Nov 2012
16 years later encountering near-virgin pressure.
Demonstrates that initial wells were insufficient
to recover all available reserves.
Is this due solely to reservoir
discontinuity? Well locations?
Frac insufficiency?
Marcellus Fractures Intersecting Offset Laterals
Mayerhofer SPE 145463 – Nov 2011
Marcellus - Slickwater
Microseismic, DFITS, downhole pressure
gauges, PTA, chemical tracers, production
interference
950 ft spacing. 1H treated 5 weeks after 2H
Cemented, 7 stage PnP
Slickwater 100 mesh, 40/70 and 30/50 sand
~6000 ft TVD
Pressure communication in 6 of 7 stages
Chem tracers from 2,3,5,6,7 recovered in 2H
When one well is shut in, the other well
increases in rate by ~20% demonstrating
some degree of connection, but clearly imperfect after 6 months. Large pressure losses inside the
fractures. Can we fix this?
25
• SPE 140463 – Edwards, Weisser, Jackson, Marcotte– All diagnostics (microseismic, chemical tracers, surface pressure
gauges, etc) indicate fracturing treatments interact.
– Well-to-well connection while the reservoir is dilated with frac fluid.
– Microseismic suggests lengths >1000 ft
– Production analysis estimates ~150 ft effective half length after 6 months
– However, wells drilled on 500 ft spacing are similar in productivity to those on 1000 ft spacing, suggesting they are not competing for reserves
Marcellus – Wells on 500 ft spacing do not
appear to share reserves
Any new opportunities to learn
something on a single well?
26
Horizontal Well - Production Log
0
5
10
15
20
15 14 13 12 11 10 9 8 7 6 5 4 3 2
Pe
rce
nt
Co
ntr
ibu
tio
n
Stage Number toeheel
Stages 2,7,13 screened out, average contribution = 13.5%Stage 1 could not be accessed, Stages 3 and 4 were unpropped
Average contribution others (omitting 3&4 unpropped)= 6.3%Stage 10, frac fluid volume reduced by 25% (more aggressive)
Intentional Screenouts?
• Probable advantages to screenouts• Wider frac (more net pressure)
• Better connection to wellbore
• Treatment diversion into other perforation clusters
• Reduced proppant flowback
• A screened-out fracture may be “immune” to subsequent overdisplacement when pumping plug/dropping ball
• May be “immune” to subsequent refrac injection?
• Perhaps advantage is simply avoiding overflush?
• Disadvantages to screenouts• Standby time and cost to cleanout/flowback
• Higher pressures may induce more gel damage
• Stress on equipment and tubulars during treatment
• Higher stress must be borne by proppant
• Never screenout wells with ULWP or deformable proppant
• May crush cleats in CBM, delicate formations
• High net pressure may induce unwanted height growth, sacrificing propped length
27
• Most statistically valid field trial published in industry– Pinedale Anticline, tight gas ~5 microDarcy, vertical wells
• Between 2 and 15% of the stages screenout depending on depth/stress/proppant type
• 5 stages screened out with sand or RCS– Only 1 provided acceptable Q100 rates.
– 4 were extremely disappointing
• Stages that screened out on ceramic were very productive– Every ISP screenout was 1st or 2nd most productive stage in well
– Effective frac lengths: 10 of 11 ceramic screenouts in upper 50%. 11th
was in upper 55%...
• Screenouts are NOT beneficial in all situations. Careful evaluation is needed.
SPE 106151
1) Incredible reservoir contact provided by hydraulic fractures
2) Bad News: At least 5 reasons fracs are not optimized
– Fluid flow is complicated
– Conductivity degrades. Many fractures collapse or heal
– Heterogeneous reservoirs depend on frac continuity
– Frac geometry is tortuous, often with poor connection between the frac and wellbore
– Typical interpretations are NOT unique
3) Great News: Fracs are not optimized
– Reservoirs are often capable of tremendous increases in productivity with improved frac design
Summary 1 of 2
28
Take home messages to optimize frac productivity
– All these “complexities” compromise flow capacity
– You need much more conductivity than you think!
– Be wary of modeling, intuition, or conventional wisdom
– Experiment and validate
– Keep searching for a better completion. We are NOT optimized!
– Focus on fracture EFFECTIVENESS, not dimensions
– Horizontal wells provide some unique data gathering opportunities!
Summary 2 of 2
Available Seminars
• Conventional versus Unconventional Reservoirs • Myths and Misunderstandings that hinder Frac Optimization • Detailed Rock Mechanics, Fluid Rheology, and Propagation Theory • Physics of Fluid Flow • Frac Sand mining and QC, Ceramic manufacturing and QC • Proppant Types, Characteristics – Understanding the differences between sand, resin and
ceramic • Conductivity Testing • Non-Darcy Flow • Multiphase Flow • Understanding Proppant Crush Testing - Are hot/wet crush tests superior? • Other Issues - Embedment, Stress Cyclic, Elevated Temperature • Determining Realistic Proppant Conductivity • Field Results – 200 summarized on SPE 119143; ~30 in PowerPoint • PTA / Well Testing considerations / Effective Frac Lengths • Fines Migration & Plugging • Significance of Proppant Density, Frac width, sieve distribution upon proppant value • Gel Cleanup
– Lab studies and field examples documenting load recovery • Proppant Flowback and Erosive Potential of sand, ceramic, and resin-coated proppants • Frac Pack concepts and field studies • Zero Stress applications – Flow in wellbore annuli or packed perforations • Frac Optimization
– CBM frac optimization – Fracturing Carbonates – Where do unpropped fractures work?
• Horizontal Wells – Comparisons with Vertical Fractured Completions • Specific Field Results (Pinedale, Kuparuk, Cardium, Wamsutter, Birch Creek, Siberia,
Cotton Valley, Vicksburg, Haynesville Lime, UP + Ranger, others) • Bakken Horizontal Wells – Importance of Frac Intersection with Wellbore • Performance under Severe Conditions (Steam, Acid) + Diagenesis • Waterfracs/Slickwater Fracturing • Frac Geometry – What do Fracs Really look like? What errors are we making? • 100 mesh sand – pros & cons • Refracturing
Mike Vincent
Insight Consulting
303 568 0695