EPA Hydraulic Fracturing Technical Workshop
Well Construction and Operations
Evaluating Hydraulic Fracture
Propagation in a Shallow Sandstone
Interval, South Texas
Presented by
Dave Cramer / March 10, 2011
Background
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This is a case study of a water flooded oil reservoir in South Texas.
The productive interval is a tight, multilayer, Cretaceous-age sandstone with true
vertical depth ranging from 1200-1700 ft.
Over 1000 production and water injection wells have been completed in the
area over past 50 years.
Hydraulic fracturing is normally employed to stimulate well productivity in the
study area. A standard treatment design features the use of viscous 25 lb/1000
guar borate fracturing fluid and 12/20 mesh proppant injected at a high rate
(e.g., 40 bbl/min.)
Although diagnostic fracture injection testing (DFIT) analysis indicates that the
minimum principle stress is horizontal, tiltmeter mapping, tracer surveys, an
offset-well corehole project and treating pressure analysis indicate that most of
the fracture propagation is horizontal (normal to the overburden stress) and that
the vertical fracture component (normal to the minimum horizontal stress) is
contained within the pay interval.
Because of the limited vertical hydraulic fracture propagation, limited entry or
multi-stage treatment methods are employed to establish hydraulic fractures in
each of the productive reservoir sand compartments.
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Geologic Overview
ƒ The formation is composed of sandstones and shales.
ƒ The sandstone units are a series of deltaic deposits
reworked by marine processes.
ƒ Characteristics of the productive sandstone interval:
• reservoir depth ranges from 1200 – 1700 feet TVD
• average porosity: 20%
• average permeability: 4 md
• oil gravity: 39 API
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Log Suite
36-72
Scale : 1 : 240
DEPTH (1230.FT - 1330.FT)
DB : Chittim (2)
Depth
6.
6.
IN:CALI (in)
BS (IN)
DEPTH
(FT)
TVD
(FT)
Litho
16. 0.
16. 1.
1.
VCL (Dec)
PHIE (Dec)
BVW (Dec)
Resistivity
1. 0.2
0. 0.2
0. 0.2
0.2
0.2
0.2
0.2
RXOI (OHM.M)
AT10 (OHM.M)
AT20 (OHM.M)
AT30 (OHM.M)
AT60 (OHM.M)
AT90 (OHM.M)
IN:RT (ohm.m)
Porosity
20. 1.65
20. 0.6
20. 0.
20.
20.
20.
RHO8 (G/CM3)
NPOR (FT3/FT3)
PEF8 (0)
SonicScanner
2.65 300.
0. 150.
10. 150.
300.
FIN:DTS (uSec/ft)
FIN:DTC (uSec/ft)
DTCO (US/F)
DTSM (US/F)
02/13/2008 22:57
Poisson Ratio
100. 0.1
HR:PR_DYN ()
50.
Bulk Modulus
0.5 0.
0.
HR:BMK_DYN ()
HR:SMG_DYN ()
Young Modulus
5. 0.
5.
HR:YME_DYN (Mpsi)
Strss Gradients
5. 0.5
0.5
50.
0.5
100.
0.5
FIN:TZSG (Psi/Ft)
FIN:PPGI (psi/Ft)
SH1 (psi/ft)
SH2 (psi/ft)
1.5
1.5
1.5
1.5
Flow barriers
20.
1250
Zone
1300
Log analysis provides estimates of reservoir properties
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Diagnostic Fracture Injection Test (DFIT)
Rate and Pressure Data
N.J. Chittim 37-30R DFIT
rate (BPM)
1500
500
1000
3.0
Bottomhole Pressure
1.0
2.0
rate (BPM)
ISIP=1429 psi (1.10 psi/ft)
calc bhp (psi)
2000
Injection Rate
2500
calc bhp (psi)
4.0
5.0
Breakdown at 2900 psi
Note: overburden pressure gradient = 1.02 psi/ft
0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 90.0 100.0
Time (min)
Low volume fracture injection tests can be analyzed to provide
estimates of in-situ stress and reservoir transmissibility (kh/u)
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DFIT G-dp/dG Plot
Probable horizontal fracture closure (1.02 psi/ft)
Vertical fracture closure at trend-line
break-over = 1094 psi (0.84 psi/ft.)
91 hours of shut in time
Vertical fracture closure is a proxy for minimum horizontal stress (S3)
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Poroelastic Equation for Estimating In-Situ
Horizontal Stress
⎡ ν
⎤
σ h= ⎢
(σ v − α v Pr )⎥ + α h Pr + σ t
⎣1 −ν
⎦
Where,
σv = overburden stress, psi = 1331 psi (1.02 psi/ft; bulk density log)
ν = Poisson’s ratio = 0.31 (from dipole sonic log computation)
αv = vertical Biot’s parameter = 1.0
αh = horizontal Biot’s parameter = 1.0
Pr = reservoir pore pressure, 718 psi (0.55 psi/ft; DFIT)
σt = external (tectonic) stress, psi = 0 psi (assumed)
σh = minimum horizontal stress, psi = 1047 psi (predicted from above)
σh = minimum horizontal stress, psi = 1094 psi (observed from DFIT)
There is reasonable agreement with predicted and measured in-situ stress
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Bottomhole Treating Pressure Behavior
FG
Initial WHP
900
2.0
800
1.8
700
1.6
1.4
600
1.2
500
1.0
400
0.8
300
0.6
200
0.4
100
0.2
0
Apr -08
overburden (vertical) stress ~ 1.02 psi/ft
Jun-08
Jul-08
Se p-08
Oct-08
Dec-08
Fe b-09
Mar-09
Variability in initial reservoir pressure is
due to injection/ withdrawal imbalances
within the field.
May-09
0.0
Apr-08
Jun-08
Jul-08
Sep-08
Oct-08
Dec-08
Feb-09
Mar-09
May-09
Regardless of initial pore pressure, hydraulic
fracturing pressure (FG) is regulated by the
overburden stress.
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Post-Treatment Multi Test Hole Study
From SPE paper 1571 (1961)
An extensive horizontal fracture was “excavated”
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Surface Tiltmeter Deformation Visualization
horizontal fracture
(domed or conical feature)
vertical fracture
(trough feature)
dipping fracture
(asymmetrical
trough feature)
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Tilt Vector Diagram & Surface Deformation
Visualization, Example from Study Area
0.0078 in
Not to scale:
10,000,000:1 horizontal
to vertical ratio
65
00
ft
Surface displacement during the treatment
was equal to the thickness of 2 sheets of paper
Tiltmeter mapping results show the classic signature of a horizontally-dominant
hydraulic fracture system. Horizontal fracture component is 78-90%
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Hydraulic Fractures Open Normal to the
Least Principal Stress
S1
S2
S3
But it’s a little more complicated than this in shallow reservoirs
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T-Shaped Fractures
This routinely happens when the difference between horizontal and vertical
principal stresses is small, as is the case with shallow reservoirs
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Five Zone Limited Entry Treatment: Well A
5 lb
1-4 lb
pad
Top of sand
Horizontal
fracture
Top of vertical component
Horizontal
fractures
Horizontal
fracture
Horizontal
Fracture?
Bottom of vertical component
Top of fractured interval is capped by a horizontal fracture
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Three Zone Limited Entry Treatment: Well B
5 lb
1-4 lb
pad
Top of sand
Horizontal
fracture
No apparent vertical component
Horizontal
fracture
Horizontal
fracture
Dominant horizontal fracture signature
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Recompletion Tracer Log: Well C
Top of sand
New perfs
Top of vertical component
Horizontal
fracture
Horizontal
fracture
Horizontal
fracture
Original perf set
Bottom of vertical component
Hydraulically fracturing via the new perf set increased oil production
by 10 fold. This response is indicative of the lack of vertical connectivity
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from the previously fractured original perf set.
Two Zones with Ball Sealer Diversion: Well D
Top of sand
Top of vertical component
Horizontal
fractures
Horizontal
fracture
Horizontal
fracture
Bottom of vertical component
Top of fractured interval is capped by a horizontal fracture
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Five Zone Limited Entry Treatment: Well E
Top of sand
5 lb
1-4 lb
pad
Top of vertical component
Horizontal
fracture
Horizontal
fractures
Horizontal
fracture
Bottom of vertical component
Top of fractured interval is capped by a horizontal fracture
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Treatment Pressure History Evaluation: Well E
Injection rate
Actual pressure
Modeled pressure
ISIP = 1.07 psi/ft
Proppant
concentration
Actual results matched computer modeled results indicating good control of the process
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Hydraulic Fracture Modeling Results: Well E
Width vs radial position for each horizontal fracture
Limited
Entry
Hydraulic Width
frac #1
at end ofModeling
injection
Treatment
frac #2
Vertical Fracture Component:
assumed to be negligible
frac #3
frac #4
frac #5
frac #6
Propped width after fracture closure
Horizontal Radius (ft)
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Summary
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Conditions are favorable for propagating horizontal fractures in shallow
reservoirs.
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Fracture geometry can be estimated from the treatment pressure response.
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Horizontal fractures propagate radially and require decreasing net pressure to grow.
Vertical fractures eventually propagate elliptically (length-to-height aspect ratio of greater
than one) and require increasing net pressure to grow.
Vertical fracture growth is contained within the pay sand.
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There is a small difference between the overburden (vertical) and minimum horizontal
principal stresses.
The net pressure required to extend a vertical fracture is in excess of the horizontal-tovertical stress difference.
Core hole, tiltmeter, tracer survey and treating pressure analysis indicate that horizontal
fracturing is the dominant mode of fracture propagation even though the minimum in-situ
stress is not vertical.
Methods are employed to control the hydraulic fracturing process.
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There is a strong financial incentive to contain fracture propagation within the target
sandstone intervals.
Treatment designs are modeled and evaluated with computer-based processes.
Limited entry or selective multi-stage frac treatments are necessary to achieve fracture
propagation in all the sub-intervals in the study area.
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