Fracturing Basics
• Damage Bypass
• Stimulation
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J/Jo
Prod Improvement from Stimulations
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2
1
0
Acid
Breakdowns
Hydraulic
Fracturing
re/rw=625
re/rw=1250
re/rw=2500
re/rw=5,000
re/rw=10,000
1
10
100
1000
10000
Increased well radius/init well radius
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Optimizing Fracture Length by Reservoir Studies & Costs
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Efficient fracture half lengths for various
permeabilities.
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Fracture Gradient
• Ranges from about 0.5 psi/ft to over 1 psi/ft.
• Highly affected by regional and local stresses,
rock types, wellbore access to the reservoir,
deviation, plane of the perfs respective to the
frac direction, “tortuosity”, etc.
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Usually a low
viscosity fluid
Usually a
high
viscosity frac
fluid.
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Proppant Permeabilities
-12 / +20 mesh
-20 / +40 mesh
-40/ +60 mesh
-70/ +140 mesh
450+ darcies
120 darcies
60 darcies
0.6 darcies
These perms are without stress and are for clean
proppant packs.
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Proppant Conductivity
12/20 NW sand
16/20 Naplite
Resin coated 16/20 Naplite
Resin coated 16/20 Carbolite
Re-cycled 16/20 Naplite
Conductivity
4,500 md-ft
15,000 md-ft
15,000 md-ft
15,000 md-ft
3,500 md-ft
Conditions: Frac fluid is YF130LGD, Temp =
195 F, Closure Stress: 4000 psi (Valhall data)
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Fracturing as a Means of Sand Control
• Frac and Pack
• Screenless Fracs
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Perforating for Fracs
• Size - typically BH
• Orientation
– usually 60 degrees to 120 degrees
– 180 degree for screenless
• along frac direction?
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Proppant
• Type – conductivity is most important
– strength is less important
– fines invasion?
– Other forms of damage
• paraffin
• asphaltenes
• scales
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Fluids
• Non damaging
– look at clays
– look at water saturation
• Transport important
– must transport up to 16 ppga
• Efficiency critical
– building width is first step
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Formation Permeability Ranges
• Low perm (<1 to 50), length is important
• High perm - conductivity critical
– get past the damage
– how long? - few meters
– how tall - ??
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Maximizing Conductivity
• TSO Design (tip screen-out)
• maintaining conductivity
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Application
• Pad - design from minifrac
• Slurry (1 to 12 ppga)
• Flush
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Importance of Screenout
• Critical to make conductivity
– widths?
• normal frac = 0.1 to 0.3”
• TSO = 0.5 to >1”
• Screenout is usually seen as a pressure spike
near the end - can see it coming by watching
pressures
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Tip Screen Out (TSO) Fracturing
Screen area open to flow =6% to >10%
Perf area open 6 to 10%
Skin = -3 to 10
Advantages
stimulation
links across layers and low vertical k
highest reliability sand control method
good flow in moderate to higher kh
Disadvantages
usually most expensive
harder to design and apply
frac capacity vs. perm contrast critical
height growth uncertainty?
some proppant stability problem at depth
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Step 1 - Sequence of Pumping a Tip-Screenout (TSO) Frac
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Step 2- Start pad – no prop – breaks formation down & initiates fracture
What is happening? - fracture breakdown, width development, length growth, probably
height growth – AND – fluid loss from frac to the formation.
?
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Step 3 End of the pad – prop is coming – fracture width is created
What is happening? - moderate frac width sufficient to admit proppant, sufficient length
and height to create width – AND – fluid loss from frac to formation with some fluid loss
control.
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Step 4 – Start of first prop stage – usually about 2 lb/gal
What is happening? – Proppant is entering the
frac, and the pad, although diminished in
volume due to leakoff, is still increasing the
frac length and height (and width?). The
proppant is becoming more concentrated by
fluid leakoff as it travels down the fracture.
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Fluid lost to the formation from the fracture steadily increases the proppant concentration of
the slurry in the fracture.
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Step 5 – end of 2 lb/gal stage – start of 4 lb/gal stage
What is happening?
1 The small amount of pad remaining is at the
edges of the growing frac, but is being lost to fluid
leakoff;
2. The 2 lb/gal pad is losing liquid volume,
concentrating the proppant;
3. The 4 lb/gal pad has entered the fracture,
driving the other fluids in front of it and slowing
losing some of its volume to leakoff.
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The proppant steadily concentrates in the remaining fracture fluid as leakoff into the walls of the
fracture continues.
Proppant concentration may begin as low as 1 to 2 lb/gal and increase to 12 or more lb/gal at
the very end of the fracture treatment.
4 lb/gal
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Was 4 lb/gal,
now 6 lb/gal,
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Was 2, now 6
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Steps 6 and 7 – pumping stages of increased proppant concentration
What is happening?
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1.
Pumping sequential stages of 2, 4, 6,
8, and 12 lb/gal.
2.
The fluid leakoff is steadily increasing
the proppant concentration.
3.
When the proppant concentration at
the tip of the fracture approaches 16
lb/gal, the slurry is no longer
pumpable.
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Proppant concentration reaches a maximum at 16 lb/gal near the tip of at a highly permeably
section and the proppant screens out and the frac length stops growing.
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Last stage of proppant – continues until the job screens out
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Last Step – as pressure indicates that the tip screenout is forming, increase pressure at the
surface and force as much proppant as possible into the fracture. This creates extra width and
proppant loading at the wellbore – this means higher flow capacity.
Final proppant loading near the
wellbore may be 14 lb/ft2 or more.
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Observations – DW Frac Pack
• Frac Pack process very similar on every well
– Hard to evaluate ‘job quality’ from DIMS as data not
reported
• Average sand placed is 84% of sand pumped
– Without 2 lowest jobs average is 89%
• Frac Screenout reported on 9 wells
• Annular Pack Processes Variable
– 6 wells with 8 BPM final rate
– 4 wells with less than 2 BPM final rate
• 1 well reported 0.5 BPM to get annular pack
• Loss rate Post-Frac pack on 7 wells reported at less
than 25 BPH losses (13
reported losses, 7 did not)
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Gibson
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Fracturing Disasters
•
•
•
•
•
•
•
Too little proppant
damaged or poor quality proppant
reactive base fluids (formation damage)
too few/too small perfs
perf phasing way out of frac plane
over-flushing the treatment
fracturing out of zone
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Minifracs
• Calibration Treatment
– 10 to 20% of frac volume
– same frac fluid at frac rate
• To Evaluate
– leakoff
– height growth
– frac geometry
• Procedure
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Fracs in Horizontals and M-Ls
• Isolation is the key.
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Spacing on Fractures
• spacing related to drainage area
• permeability
• intersecting natural fractures
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Concerns
Spacing
Frac direction
Isolation
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