1 Five things you didn’t want to know about hydraulic fractures Mike Vincent [email protected]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
This document is posted to help you gain knowledge. Please leave a comment to let me know what you think about it! Share it to your friends and learn new things together.
Transcript
1
Five things you didn’t want to know about hydraulic fractures
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
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 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
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
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,
– 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