Buildup Tests Drill Stem Test Production History and ... · PDF file• Drill Stem Test...
Transcript of Buildup Tests Drill Stem Test Production History and ... · PDF file• Drill Stem Test...
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Well Testing
• Buildup Tests
• Drill Stem Test
• Production History and Decline Analysis
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Well Testing – What Can it Tell You?
Drawdown
Buildup
Both drawdown and
buildup tests are useful.
Well tests combined with
production data can be
very useful.
What does a well test show?
1. Permeability
2. Damage
3. Depletion
4. Boundaries (sometimes)
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Build Up Tests – Some Basic Well
Work Clues – Using Derivatives
Early Time –
Measuring
wellbore, but
not reservoir
Permeability Indication
Damage
indicated by
difference
Boundary
indicator?
Dimensionless Time
Press
Pressure Data
Pressure Derivative
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Special Cases – Dual Porosity System
May be fractures
and matrix or
other
combinations.
Compartments?
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Sources of Confusion in Testing
• Wellbore dynamics
– Liquids moving in and out of the wellbore, varying height of
liquid during the tests and the small pressure differences
caused by changes in liquid heights.
– Plugging: hydrates, scale, etc.
– Phase separation – gas / liquids separate as well is shut in.
• Location of the pressure recorder in the wellbore with
respect to the producing zone.
– Must account for pressure effect of distance of recorder
from the producing zone.
• Wellbore vs. reservoir transients
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Multilayer, Multi-Reservoir or ?
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What happens to the liquid column in a
flowing well when the well is shut in?
Two Cases
Liquid Loaded Gas Well Dispersed Gas Lifted Oil Well
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1. Density Segregation,
2. Pressure Buildup and
3. Liquids Forced Back in Formation Liquid Loading in Gas Well
Phase Separation in Flowing
Oil Well
As shut-in pressure
rises, the liquids
may be forced back
into the formation to
an equilibrium
height.
This changes liquid
level and the
pressure differential
between a gauge
recorder and the
formation.
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From Drilling Kick Technology
PBH PBH PBH
PS PS PS
As a gas bubble rises in a
closed liquid system, the
bottom hole pressure, PBH,
also rises since the bottom
hole pressure is equal to the
liquid gradient plus the
pressure above it.
Since the perforations are
open in a well, the
increasing pressure pushes
the liquids back into the
reservoir.
Change in liquid height may
affect recorder readings if
the gauge is above perfs.
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After Shut-In, Downhole, When
Gauge is set above the Perfs 1 Pressure
difference
between
the gauge
and the
perfs is the
density of
the fluid
between
them. Perfs
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After Shut-In, Downhole, When
Gauge is set above the Perfs 1 Pressure
difference
between
the gauge
and the
perfs is the
density of
the fluid
between
them. Perfs
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Pressure Rising and Liquid Level
Starting to Drop 2 As long as
the liquid is
above the
gauge, then
gauge and
perf
pressures
only
separated
by liquid
density. Perfs
Note that the
pressure measured
by the gauge
(bottom) and the
reservoir pressure
are separated only by
the liquid gradient.
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Pressure Rising and Liquid Level
Below the Gauge 3 As liquid
drops
below the
gauge, gas
density,
which is
much less
than liquid,
affects the
recorded
pressure Perfs
As the liquid drops
below the gauge, the
difference between
gas and liquid must be
used to adjust the
gauge pressure back
to the reservoir
pressure.
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All Liquid Forced Back into the
Formation 4 Gauge and
reservoir
read nearly
the same
when only
gas is in
the
wellbore.
Perfs
As the liquid drops
below the gauge, the
difference between
gas and liquid must
be used to adjust the
gauge pressure back
to the reservoir
pressure.
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Now, what was this recording?
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Add gradients to the curve.
Liquid Gradient
Gas Gradient
Gauge reading
Reservoir pressure
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Now, What do you do with it?
• Look again at depletion analysis
Is this really depletion?
Look at the well test
conditions and see what was
in the wellbore at the start of
the test and at the end.
The only way to really tell if
the depletion is genuine is to
know what fluids and where
the fluids were in the
wellbore at the start and at
the end of the tests.
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Run Gradients at Start and End of
a Well Test
Gas, about 0.1 to 0.15 psi/ft (pressure
dependent)
Liquid,
oil = 0.364 psi/ft
fresh water = 0.43 psi/ft
brine = 0.52 psi/ft
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Gradients at Start and End of a
Buildup test
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Permeability
On a routine buildup
test, how can
permeability
difference be
recognized?
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Permeability
Higher perms build
up fast, lower perms
build up slow. Higher perm
Lower Perm
Note that the rate of
change is
continuously
decreasing from the
start of the test – a
way to spot
anomalies.
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What Causes Anomalies?
Injection or
other pressure
support may
increase
pressure.
Drainage of
your acreage by
an offset well
may explain
late time
changes.
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Early Time Effects
An increase
in buildup
pressure in
the early time
usually
indicates
phase
redistribution
– a wellbore
effect.
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Some Observations on Well
Testing
• Not a reservoir effect if it happens suddenly
• Wellbore transients dominate over reservoir transients
• Draw wellbore schematic & see if wellbore fluid dynamics are affecting the test
• Run static wellbore gradient before & after.
• Run gradient to lowest perf.
• Differentiate between wellbore & reservoir effects.
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Production Decline Analysis
Assumptions
Well Test Production Data
Constant Rate
Declining
Pressure
Constant
Pressure
Declining Rate
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Differences
• Well Test
– Smooth, min. flux
– BH measurement
– High frequency
– Controlled test
– Expensive
– Not always available
– Short term
• Production Decline
– Noisy
– Surface measurement
– Averaged data
– Data sometimes poor
– Inexpensive
– Always available
– Long term
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Type of Decline Analysis
• Exponential
– Not valid for transient flow (e.g., tight gas)
• Hyperbolic
• Harmonic
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Constant Rate and Reservoir
Transients
Wellbore
Reservoir
Boundary Reservoir
Boundary
Pressure Distribution
represented by the curved
lines.
The transient portion occurs
before the pressure distribution
reaches the boundary at Pwf.
When the boundary is reached,
the flow is in “pseudo-steady
state flow” (pressure at the
wellbore falls at exactly the
same rate as the reservoir
pressure).
Transient
Pwf boundary
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Constant Pressure – tied to Pwf
As the pressure distribution or
transients reach the boundary,
the flow becomes boundary
dominated.
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Comparison of Constant Pressure
and Constant Rate Plots
Constant Pressure Solution
Exponential Decline
Constant Rate Solution
Harmonic Decline
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Material Balance, Normalized or
Cumulative Production Time
Actual Time Dimensionless Time
Q
Q
q
Actual Rate Decline Equivalent Const. Rate
=Q/q (i.e., cum. Prod/rate)
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Constant Pressure Solution Corrected
by Material Balance Time
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Log q/DP
Log Material Balance Time
Transient –
Infinite acting
Boundary
Dominated
Decreasing
Skin
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Production Type Curves
Log q/DP
Log Material Balance Time
Transient – Infinite acting
Boundary
Dominated
More
Damaged
Stimulated Well
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Production Type Curves
Log q/DP
Log Material Balance Time
Transient – Infinite acting Boundary
Dominated
Curve match in
this area indicates
pure volumetric
depletion
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Production Type Curves
Log q/DP
Log Material Balance Time
Transient – Infinite acting Boundary Dominated
Data above the curve
may indicate pressure
support, layers, or
compartments.
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Production Type Curves
Log q/DP
Log Material Balance Time
Transient – Infinite acting Boundary
Dominated
Data below the
curve may
indicate liquid
loading
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Production Type Curves
Log q/DP
Log Material Balance Time
Transient –
Infinite acting
Boundary
Dominated
Transitional
Effects
Difficult to see
events in this
zone with
production data
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Blasingame Curve Showing Damage
Data set on type curve set –
matched on a “flat” line, but data
set shows increasing rate with time
– a sure sign that a damaged well is
slowly cleaning up.
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Higher Permeability Well
Pressure support
Indicated by later
time data
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Agarwall-Gardner Type Curve
Match of a Fractured Well
Derivative. Shows
successful
fracture in a tight
gas well.
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Agarwal-Gardner Type Curve Method
• The A-G type curve method uses existing field
production data to diagnose conditions of producing
wells as well as reservoir properties and conditions
• This new method can be used to determine how
effectively a well has been stimulated, the remaining
available reserves, and to predict how long it will take to
effectively produce them.
• The A-G type curve method can be used to predict a
well’s response to a work-over, a re-fracture treatment, a
change in tubulars, or to quantify the effects of
compression
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Agarwal-Gardner Type Curve Method
• The A-G type curve method is based on rigorous, pressure transient analysis (PTA) methods.
• This technique makes special provisions to account for changes in well rates and depletion effects to maintain analysis accuracy over a wide range of well producing conditions and production times.
• The A-G type curve method uses special groupings of variables, to help distinguish between completion, reservoir, and well operating effects. Proper quantification of each of these effects, allows for more effective well interventions and for better field management.
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Agarwal-Gardner Type Curve Method
• The A-G type curve method uses a suite of graphical type curves which can better ensure analysis accuracy and better predictive results:
• For better ease of data manipulation, software familiarity, and user convenience, the A-G type curve method has been implemented in MS Excel
1 .E-03
1 .E-02
1 .E-01
1 .E+ 00
1 .E+ 01
1 .E+ 02
1.E
-04
1.E
-03
1.E
-02
1.E
-01
1.E
+0
0
1.E
+0
1
1.E
+0
2
1.E
+0
3
1.E
+0
4
tD
1/PD
Xe/Xf= 1
Xe/Xf= 25
Xe/Xf= 5Xe/Xf= 2
CfD= 500
CfD= 0.5
CfD= 0.05
CfD= 5.0
Fig. 1: Reciprocal Dimensionless Pressure,
1 PD
vs. Dimensionless Time,
t D
, based on Xf
1.E-02
1.E-01
1.E+ 00
1.E+ 01
1.E+ 02
1.E
-05
1.E
-04
1.E
-03
1.E
-02
1.E
-01
1.E
+0
0
1.E
+0
1
tDA
1/PD
Xe/Xf= 1
Xe/Xf= 2
Xe/Xf= 5
CfD= 500
CfD= 500
CfD= 500
CfD= 05
CfD= 5.
CfD= 0.5
CfD= 5.
CfD= 5.
Fig. 2: Reciprocal Dimensionless Pressure,
1 PD
vs. Dimensionless Time,
tDA
, based on Area
0.00
0.02
0.04
0.06
0.08
0.10
0.12
0.14
0.16
0.18
0.20
0.00 0.02 0.04 0.06 0.08 0.10 0.12 0.14 0.16
Dimensionless Cumulative Production, QDA
1/P
wD
GIP = 15.4
BCF
GIP = 18.5
BCF
GIP = 22.4
BCF
re/rwa= 100
re/rwa= 1000
re/rwa= 10000
re/rwa= 1.E+ 06
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Wattenberg Well Example
Rate and Bottom Hole Pressure
0.00
0.50
1.00
1.50
2.00
2.50
0. 1000. 2000. 3000. 4000. 5000. 6000. 7000.
time (days)
Ra
te (
MM
SC
F/D
)
0
1000
2000
3000
4000
5000
6000
7000
Pb
h (
ps
ia)
Daily Rate (MMSCF/D)
Bottom Hole Pressure (psia)
calc Pbh
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A-G Excel SpreadSheet
Program FINITE CONDUCTIVITY FRACTURE TYPE CURVES
chart title
>>>>>>WELLNAME: Example D, Wamsutte r Well developer documentation: dcg
"v102799.xls " 10/27/1999
FINITE COND. FRAC. TYPE CURVES Tubing Len 8500.0 ft Res ults
Only Enter Data in BLUE Number Boxes Tubing ID 2.2 in area: 0.0 acresRed Numbers Are Calcula ted K: 0.000 md Z(Pint): 0.993 @ Pinitia lBlack Numbers Are Optional Xf: 532.7 fee t m(Pint): 1.35E+09 @ Pinitia lValues , optionally read from GASPRO .dat file Net Pay: 30.0 fee t (uCg)i: 3.42E-06 @ Pinitia l
Res . temp: 185.0 F C|Qd: #DIV/0!
Hydrocarb' Poros ity: 0.063 fraction C|Td: 0.00E+00
Initial Pres (BHole): 5100 ps ia Xe / Xf: 0.00 Calc.'d
OGIP: 0.00 BSCF SuPs T-C= N/A Calc.'d
WH temp: 60.00 deg F Data-TC var= N/A Calc.'d
Gas grav: 0.68 (a ir=1.0)
Indicator: 1 (0=BHP,>1=WHP) Workspace to Right --->>>
Time
(days )
Cumulative
Production
(MMSCF)
Daily Rate
(MMSCF/D)
Input Pres
(ps ia);
0=BHP
2=WHP
Bottom Hole
Pres s ure
(ps ia)
number of
Prod. data
values
(below)
Pres s ure
(ps ia) If
GASPRO
will
Vis cos ity
(c 'pois e) is
us ed, be
z-factor
(dimenles s )
thes e
Calc 'd!
number of
PVT Values
>99
31.0 8.72 0.28 4760.49 5748.81 194 10 0.01306 0.999 1.592E-01 0.000E+00
61.0 14.65 0.20 4751.27 5738.61 71.22 0.01308 0.99293 0.000E+00 5.270E-01
92.0 52.03 1.21 3527.06 4373.77 132.45 0.0131 0.98693 corners of se lection trapezoid r^2 OGIP:
122.0 110.22 1.94 2335.70 2964.81 193.67 0.01312 0.98101 4.690E-02 4.470E-01
153.0 164.04 1.74 2017.40 2562.91 254.9 0.01316 0.97516 4.690E-02 3.290E-01
184.0 216.39 1.69 1698.92 2156.53 316.12 0.01319 0.9694 1.139E-01 9.700E-02
212.0 236.21 0.71 2524.93 3185.50 377.35 0.01323 0.96373 1.139E-01 2.150E-01
243.0 278.21 1.35 1958.24 2482.30 438.57 0.01328 0.95814 4.690E-02 4.470E-01
273.0 322.72 1.48 1585.53 2007.29 499.8 0.01333 0.95266
304.0 363.92 1.33 1549.71 1958.58 561.02 0.01338 0.94727
334.0 407.00 1.44 1247.57 1573.61 622.24 0.01344 0.94199
365.0 407.00 0.00 2781.85 3495.66 683.47 0.0135 0.93682
396.0 459.82 1.70 1184.10 1499.96 744.69 0.01357 0.93176
426.0 497.91 1.27 1338.61 1686.47 805.92 0.01365 0.92683
0.00
0.50
1.00
1.50
2.00
2.50
0. 1000. 2000. 3000. 4000. 5000. 6000. 7000.
Ra
te (
MM
SC
F/D
)
0
1000
2000
3000
4000
5000
6000
7000
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WELLNAME: Example D, Wamsutter Well
1.E-02
1.E-01
1.E+00
1.E+01
1.E-02 1.E-01 1.E+00 1.E+01 1.E+02 1.E+03
tD(Xf)
qD
Xe/Xf=1
Xe/Xf=25
Xe/Xf=5
Xe/Xf=2
Fcd=0.5
Fcd=5
Fcd=0.05
Fcd=500
5.00Xe/Xf=
0.064K (md)=
532.7Xf (ft)=
5100Pinit (psia)=
15.10OGIP (BCF)=
651.4Area (ac)=
XD5,FCD5.SuPs T-C=
9.722E-02Data-TC var=
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Rate and Bottom Hole Pressure
0.00
0.50
1.00
1.50
2.00
2.50
0. 1000. 2000. 3000. 4000. 5000. 6000. 7000.
time (days)
Rate
(M
MS
CF
/D)
0
1000
2000
3000
4000
5000
6000
7000
Pb
h (
psia
)
Daily Rate (MMSCF/D)
Bottom Hole Pressure (psia)
calc Pbh
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Dimensionless Numbers used in A-G
type curve
• Dimensionless Pressure/Rate
• Dimensionless Time
• Dimensionless Cumulative
• Dimensionless Fracture Conductivity/Length
freservoir
ff
CDxk
wk=F
Ttq
pmhkp
g
D
D
)(1422
)(
f
eD
x
x=x
2
410637.2
)(=
fg
g
Dxtc
tkt
D
DADA
p
tQ
)(
)(14221
pmhk
Ttqq
p g
D
D D
Atc
tkt
g
g
DA)(
=
410637.2
)(
)(2)(
pmGz
tQptc
ii
ig
D
Di
)())z((
2=
p
tppp
pdp(t)pm
ii
i
G
tQ
z
p
pz
p )(1
)(
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Depletion, Compaction, Perm Loss What has depletion to do with Well Productivity *
(1)
Initial Reservoir pressure
Maximum energy to drive production
Maximum permeability
Single phase production
No depletion, No compaction, Min.
formation stress
Minimum production cost
1
100 80 60 40 20
Permeability (% of initial K)
Re
se
rvo
ir pre
ssu
re
Time Rp ini
2
RpAL
Pressure maintenance = • Increase Well Productivity • Increase Recoverable Reserves • Minimize Permeability Loss • Minimize Compaction
RpAban
3
(2)
Artificial lift required (gas lift, ESP, etc)
Sharp increase in production cost
Multi phase production > reduced
saturation, loss of capilary pressure
Loss of cohesive forces
(3)
Abandonment pressure
Minimum energy to drive production
Maximum depletion, compaction,
formation stress
Minimum remaining permeability
* (SPE 56813, 36419. 71673)
Reslink
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Drill Stem Tests
• Diagnostics
• Application
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The basic recording
graph paper of an old
style DST – pressure in
the well, recorded
against time, usually on
a clock that runs from
the time the tool is
switched on at the
surface immediately
before it starts into a
well.
Electronic advances
have altered the
appearance of the data,
but the basics remain
the same.
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