Evaluating Hydraulic Fracture Propagation in a Shallow ......Evaluating Hydraulic Fracture...
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Evaluating Hydraulic Fracture Evaluating Hydraulic Fracture Propagation in a Shallow Sandstone Propagation in a Shallow Sandstone Interval, South Texas Interval, South Texas EPA Hydraulic Fracturing Technical Workshop Well Construction and Operations Presented by Dave Cramer / March 10, 2011
Transcript of Evaluating Hydraulic Fracture Propagation in a Shallow ......Evaluating Hydraulic Fracture...
Evaluating Hydraulic Fracture Evaluating Hydraulic Fracture Propagation in a Shallow Sandstone Propagation in a Shallow Sandstone
Interval, South TexasInterval, South Texas
EPA Hydraulic Fracturing Technical WorkshopWell Construction and Operations
Presented by Dave Cramer / March 10, 2011
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Background
•
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
The formation is composed of sandstones and shales.
The sandstone units are a series of deltaic deposits reworked by marine processes.
Characteristics of the productive sandstone interval:•
reservoir depth ranges from 1200 –
1700 feet TVD
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average porosity: 20%•
average permeability: 4 md
•
oil gravity: 39 API
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36-72Scale : 1 : 240DEPTH (1230.FT - 1330.FT) 02/13/2008 22:57DB : Chittim (2)
Depth
IN:CALI (in)6. 16.
BS (IN)6. 16.
DEPTH(FT)TVD(FT)
Litho
VCL (Dec)0. 1.
PHIE (Dec)1. 0.
BVW (Dec)1. 0.
Resistivity
RXOI (OHM.M)0.2 20.
AT10 (OHM.M)0.2 20.
AT20 (OHM.M)0.2 20.
AT30 (OHM.M)0.2 20.
AT60 (OHM.M)0.2 20.
AT90 (OHM.M)0.2 20.
IN:RT (ohm.m)0.2 20.
Porosity
RHO8 (G/CM3)1.65 2.65
NPOR (FT3/FT3)0.6 0.
PEF8 (0)0. 10.
SonicScanner
FIN:DTS (uSec/ft)300. 100.
FIN:DTC (uSec/ft)150. 50.
DTCO (US/F)150. 50.
DTSM (US/F)300. 100.
Poisson Ratio
HR:PR_DYN ()0.1 0.5
Bulk Modulus
HR:BMK_DYN ()0. 5.
HR:SMG_DYN ()0. 5.
Young Modulus
HR:YME_DYN (Mpsi)0. 5.
Strss Gradients
FIN:TZSG (Psi/Ft)0.5 1.5
FIN:PPGI (psi/Ft)0.5 1.5
SH1 (psi/f t)0.5 1.5
SH2 (psi/f t)0.5 1.5
1250
1300
1250
1300
Zone
Flow barriersFlow barriers
Log analysis provides estimates of reservoir properties
Log SuiteLog Suite
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Diagnostic Fracture Injection Test (DFIT) Rate and Pressure Data
N.J. Chittim 37-30R DFIT
calc
bhp
(psi
)
500
1000
1500
2000
2500
rate
(BPM
)
1.0
2.0
3.0
4.0
5.0
Time (min)0.0 10.0 20.0 30.0 40.0 50.0 60.0 70.0 80.0 90.0 100.0
rate (BPM)
calc bhp (psi)
ISIP=1429 psi (1.10 psi/ft)
Breakdown at 2900 psi
Injection Rate
Bottomhole Pressure
Note: overburden pressure gradient = 1.02 psi/ft
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
Vertical fracture closure is a proxy for minimum horizontal stress (S3 )
Vertical fracture closure at trend-line break-over = 1094 psi (0.84 psi/ft.)
Probable horizontal fracture closure (1.02 psi/ft)
91 hours of shut in time
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( )r rP P1h v v hνσ σ α α σν
⎡ ⎤− + += ⎢ ⎥−⎣ ⎦
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 = 1.0αh
= horizontal Biot’s parameter = 1.0Pr
= 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
t
Poroelastic Equation for Estimating In-Situ Horizontal Stress
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Bottomhole Treating Pressure Behavior
Variability in initial reservoir pressure is due to injection/ withdrawal imbalances within the field.
Regardless of initial pore pressure, hydraulic fracturing pressure (FG) is regulated by the overburden stress.
Initial WHP
0
100
200
300
400
500
600
700
800
900
Apr-08 Jun-08 Jul-08 Se p-08 Oct-08 Dec-08 Fe b-09 Mar-09 May-09
overburden (vertical) stress ~ 1.02 psi/ft
FG
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
Apr-08 Jun-08 Jul-08 Sep-08 Oct-08 Dec-08 Feb-09 Mar-09 May-09
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PostPost--Treatment Multi Test Hole StudyTreatment 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
Surface displacement during the treatment was equal to the thickness of 2 sheets of paper
Not to scale:10,000,000:1 horizontal to vertical ratio
0.0078 in
6500 ft
Tiltmeter mapping results show the classic signature of a horizontally-dominant hydraulic fracture system. Horizontal fracture component is 78-90%
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S1
S3S2
Hydraulic Fractures Open Normal to the Least Principal Stress
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 verticalprincipal stresses is small, as is the case with shallow reservoirs
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pad1-4 lb5 lb
Five Zone Limited Entry Treatment: Well AFive Zone Limited Entry Treatment: Well A
Top of sand
Top of vertical component
Bottom of vertical component
Horizontal fracture
Horizontal fractures
Horizontal Fracture?
Horizontal fracture
Top of fractured interval is capped by a horizontal fracture
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pad1-4 lb5 lb
Horizontal fracture
Top of sand
No apparent vertical component
Horizontal fracture
Horizontal fracture
Three Zone Limited Entry Treatment: Well BThree Zone Limited Entry Treatment: Well B
Dominant horizontal fracture signature
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Recompletion Tracer Log: Well C
New perfs
Horizontal fracture
Top of sand
Top of vertical component
Horizontal fracture
Horizontal fracture
Bottom of vertical component
Hydraulically fracturing via the new perf set increased oil productionby 10 fold. This response is indicative of the lack of vertical connectivity from the previously fractured original perf set.
Original perf set
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Two Zones with Ball Sealer Diversion: Well DTwo Zones with Ball Sealer Diversion: Well D
Horizontal fracture
Horizontal fractures
Horizontal fracture
Top of sand
Top of vertical component
Bottom of vertical component
Top of fractured interval is capped by a horizontal fracture
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pad1-4 lb5 lb
Five Zone Limited Entry Treatment: Well EFive Zone Limited Entry Treatment: Well E
Horizontal fracture
Top of vertical component
Horizontal fractures
Top of sand
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
ISIP = 1.07 psi/ft
Modeled pressure
Actual pressure
Injection rate
Proppant concentration
Actual results matched computer modeled results indicating good control of the process
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Limited Entry Treatment Modeling
Propped width after fracture closure
Hydraulic Fracture Modeling Results: Well E Width vs
radial position for each horizontal fracture
Vertical Fracture Component: assumed to be negligible
Horizontal Radius (ft)
Hydraulic Widthat end of injection frac #1
frac #2
frac #3
frac #4frac #5
frac #6
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SummaryConditions are favorable for propagating horizontal fractures in shallow reservoirs.
•
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-to-
vertical stress difference.
Fracture geometry can be estimated from the treatment pressure response. •
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. •
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.•
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.
