Upload
others
View
3
Download
0
Embed Size (px)
Citation preview
Characterizing Mechanical and Flow
Properties using Injection Falloff Tests
Presented by
Dave Cramer / March 28, 2011
EPA Hydraulic Fracturing Technical Workshop #3
Fate and Transport
2
Agenda
• Review the basics of fracture injection / fall-off tests.
Describe fracture closure analysis for determining in-situ stress and non-ideal fracture closure mechanisms.
Describe after-closure analysis for determining reservoir flow behavior, reservoir flow capacity (kh/u) and initial reservoir pressure (pi).
Discuss integration of this information for enhanced control of hydraulic fracturing.
•
•
•
3
Injection Fall-off Diagnostics
The process starts with the creation of a small hydraulic fracture,
typically requiring less than 5 barrels for a shale gas interval.
4
Hydraulic Fractures Open Normal to the
Least Principal Stress
This stress regime is typical for deeply buried reservoir rock.
S1
S3S2
5
Parameters driving hydraulic fracture pressure response at the wellbore (from Nolte)
Drivers of Bottomhole Pressure Behavior
Initially, rock mechanical properties and in-situ stress influence
the pressure fall-off response. Later, pressure fall-off behavior is
dominated by reservoir flow properties and pore fluid pressure.
From Nolte
6
Fracture Closure
initial late time
Asperities on opposing fracture faces touch in the initial stages of fracture
closure. The adjacent void space imparts residual fracture conductivity.
Proportional to normalized fracture width
MWX Test Site Project
7
Flow Regimes in Hydraulically Fractured
Wells with Residual Fracture Conductivity
Achieved in the after-
closure period.
Radial flow solutions
can be used to derive
far-field kh/u.
During the pseudo-radial flow period, the area of
investigation is well beyond the region of the fracture.
From Cinco-Ley
8
Assumed Case for Modeling Purposes: Fracture-
Enhanced Wellbore in Cylindrical Reservoir
Hydraulic Diffusivity
=k / ø μ cT
=fluid mobility / fluid storativity
Hydraulic diffusivity determines the speed that pressure changes induced by
production or injection are transmitted through the reservoir.
0.01
0.1
1
10
100
0.001 0.01 0.1 1 10 100 1000 10000
tD = 0.000264 k t / ø μ c xF2
pD =
(kh / 1
424qT)
(m(p
)i -
m(p
) WF)
Xe/Xf=10 Xe/Xf=infinity Xe/Xf=1 Xe/Xf=1.5 Xe/Xf=2 Xe/Xf=3 Xe/Xf=5 Xe/Xf=7 Xe/Xf=15
unit slope
half slope
Well centered in square reservoir1 1.5 2 3 5 7 10 15
8
xE/xF =
SPE 4051
Approximate start of semi-log straight line
(pseudoradial flow period)k / ø μ cT 1/xF
2
p
Q (rate)
Fractured-Well Type Curve
tD = 0.000264kt/φμcTxF2
Start of pseudo-radial flow tD>1
9
Pressure Memory Gauge
To facilitate doing long-duration tests, memory gauges are used to monitor
and record the pressure fall-off downhole or more commonly at the wellhead.
10
4300
4740
5180
5620
6060
6500
1080 1100 1120 1140 1160 1180 1200
Elapsed Test Time (min)
Ca
lc.
Bo
tto
mh
ole
Pre
ss
ure
(p
si)
.
31
471
911
1351
1791
2231
We
llh
ea
d P
res
su
re (
ps
i)
.
perforating event
wireline and perforating gun
removed from the well
ready to start
DFIT
pressure loss: 9 psi in ~33 minutes
increase pressure in the
wellbore prior to perforating
Pre-job estimate of
reservoir pore pressure
Overbalanced Perforating
Maintaining the wellbore pressure above reservoir pressure prevents gas influx
into the wellbore and enables closed-chamber analysis under certain conditions.
11
Propagating a Hydraulic Fracture
Compressing the wellbore fluid
Injection rate (bbl/d)
Calc. Bottomhole
Pressure (psi)
1 bbl/min injection rate;
1 bbl of fluid injected
following fracture initiation.
Fracture initiation event
Stop injection.
Start shut-in period
Injection time and volume are kept short to minimize fracture
dimensions and satisfy the conditions of an impulse event.
12
Lebien 1 Silurian DFIT
Fracture Penetration (m)
1.0
2.0
3.0
4.0
5.0
6.0
7.0
8.0
9.0
1.07 min
2915
m
TVD
2920
2925
2930
2935
Stress (psi)
6475
7025
Silt
yS
ilty
Silt
yS
ilty
Silt
y
0.000
0.008
0.016
0.024
0.032
0.040
0.048
0.056
0.064
0.072
0.080
Wid
th -
Tota
l in
Modeled Fracture Geometry
Even with a small injection, reservoir investigation is significant.
13
Pressure Fall-off History
Hydrostatic pressure is added to the observed wellhead
pressure value to compute bottomhole pressure.
14+ days of data
Hydrostatic pressure is added to the observed wellhead
pressure value to compute bottomhole pressure.
14
Diagnostic Log-Log Plot of Pressure Fall-Off
Derivative plot is used for identification of fracture closure behavior
and after-closure reservoir flow regimes.
15
Log-Log Graph Characteristic Slopes
From Barree (SPE 107877)Primary derivative (dp/dt or dΨ/ta)
Semi-log derivative (t dp/dt or ta dΨ/ta)
Impulse derivative (t2 dp/dt or ta2 dΨ/ta)
Diagnostic slopes depend on the derivative type used.
16
G Function Plots for Fracture Closure
Identification
The semilog derivative is the primary plot for identifying fracture closure.
17
G-Time Functions for Analyzing a Closing
Fracture
ΔtD = (t – tp) / tp
g(ΔtD) = 4/3 ((1+Δtp)1.5 - Δ tp
1.5)
G(ΔtD) = 4/π (g(Δtp) - g0
where,
t = total test time (pumping and shut-in)
tp = pumping time
G(ΔtD) = G-Function time in previous slide
G(ΔtD)C = G-Function time at fracture closure
η = fluid efficiency (i.e., fluid remaining in
fracture total fluid injection, at shut-in)
η = [G(ΔtD)C] [2 + G(ΔtD)C]
The G-Time Function linearizes the pressure response
of a closing fracture under ideal conditions.
18
Square Root of Time Plots for Fracture
Closure Identification
The 1st derivative plot is a secondary method for confirming fracture closure.
19
r rP P1
h v v h t
Where,
σv = overburden stress, psi = 10,752 psi (1.12 psi/ft; bulk density log)
ν = Poisson’s ratio = 0.23 (from dipole sonic log computation)
αv = vertical Biot’s parameter = 1.0
αh = horizontal Biot’s parameter = 1.0
Pr = reservoir pore pressure, 4693 psi (0.49 psi/ft; DFIT)
σt = external (tectonic) stress, psi = 0 psi (assumed)
σh = minimum horizontal stress, psi = 6503 psi (predicted from above)
σh = minimum horizontal stress, psi = 7269 psi (observed from DFIT)
Poroelastic Equation for Estimating In-Situ
Horizontal Stress
The fracture closure method for deriving minimum in-situ stress can be
used to evaluate and adjust the values derived from predictive equations.
20
After-Closure Flow Regime Type Curve
Pseudo-radial flow is indicated by 1.) the -1 slope trend in both ΔP & semilog
derivative plots and 2.) equivalency of ΔP and semilog derivative values .
Pseudo-radial flow period
21
After-Closure Flow Regimes Plot Time Function
LFlinear flow time function =
2LFlinear flow time function2 =
where,
t = total test time (including injection time)
tc = time to fracture closure (including injection time)
Note: In gas reservoirs, the pseudo-time function (ta) is
used to adjust time.
It’s the linear flow time function squared,
which is a function of total test time and fracture closure time.
22
After-Closure Radial Flow Plot
24 70.6i
R
kh V
M
The solution derived with the Radial Flow specialty plot
shows good agreement with the Type Curve plot.
MR=63,300 psikh/u = 24x70.6 [1.06 (63,300)]
=0.028 md-ft/cp; kh=0.000732 md-ft:
k=0.000045 md or 45 nanodarcies
μ=0.0258 cp
Vi: bbls
k: md
MR: psi/cycle
h: ft
μ: cp
a
1
t or t , hrRF
t = injection time + shut-in time
23
ACA Regimes Plot-MCM Shale,Int3,Cyc4
dP
/dP
'0
.20
0.5
01
.02
.05
.0
dP
= (
P-P
i) a
nd
dP
'
10
02
00
50
01
00
0
1/F-L 2̂
1.0
2.0
5.0
10
20
dP
dP/dP'
dP'
290.0
Less Smoothing
More Smoothing
PRes (psi)
Cycle 5
After-Closure Flow Regime Plot: Linear Flow
Ratio plot
ΔP
dΔP
Pseudo-linear flow indicator: when pressure change and
derivative both lie on the half-slope trend line & pressure
change is 2x the value of the derivative. This test meets the
criteria for pseudolinear flow. Reservoir pressure can be
inferred from this analysis.
half slope
trend lines
Radial flow signature
is absent
Nolte method
2x
Certain types of naturally fractured reservoirs exhibit long-term linear flow.
2
1
LF
2
1
LF
24
Summary Injection Fall-off Testing is an efficient way to derive in-situ information on
most rock types. • A modest-size hydraulic fracture is created and pressure fall-off during shut in period is
analyzed for fracture closure and after-closure radial flow period.
• Injection rate and volume are tailored for interval thickness and leak-off characteristics.
Identification of fracture closure provides information on rock stress.• A combination of derivative-based diagnostic plots are used.
• Non-ideal fracture propagation (e.g., fracture height growth, fissure opening, multiple fracture closures) can be identified and evaluated.
After-closure analysis is used to derive rock transmissibility (kh/u) and pore fluid pressure.
• Radial flow is identified and evaluated by type curves and specialty plots.
• Computations are based on well testing theory.
The resulting information is employed to assist in controlling the hydraulic fracturing process.
• The information is used in hydraulic fracture modeling to predict fracture geometry, proppant placement, fracture conductivity, etc.
• Treatment design is modified as necessary to achieve treatment objectives.