Part 15 Slug Dst Mdt Iptt
Transcript of Part 15 Slug Dst Mdt Iptt
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Cha ter 15Slug, DST, and MDT Tests
DST DST (Drillstem Test) has been used as a method of
formation evaluation for many years.
Originally used to identify reservoir fluids, DST hasalso become an important method for estimatingreservoir pressure and well potential.
It can berunboth in o enand cased holeswithasingle packer or a dual (or straddle) packer.
DST can be viewed as a temporary well completionwith the purpose of obtaining some or all of thefollowing objectives:
Identification of reservoir fluid An indication of well productivity Pressure transient data to estimate permeability, skin
factor, and static reservoir pressure.
DST Tool
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DST Pressure Response
A Note on DST Analysis
DSTs in which fluid is produced to surface (higherproductivity wells) can be analyzed like any othertransient tests semilog plots, pressure andderivative type curves etc.
DSTs in which fluid is not produced to the surface
discussed later.
One important point to note is that DST tests areexamples of variable rate testing problems becausesandface flow rate changes in flow and buildupperiods, and flow rate measurements are often notavailable, and must be inferred from pressure data.
Flow Rate/Pressure RateBehavior
Flow periods of DST are
examples of Slug Tests,
if the fluid is not produced
to surface.
3 cycle DST
Buildup periods are
Examples of buildup tests.
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Flow Rate/Pressure Rate Behavior
As is seen from the previous slide, flow rateduring the flow periods are variable, in fact
usually decreases with time. The time rate ofdecrease in flow rate is a strong function ofskin factor and permeability. In cases, if
,flow rate is almost constant.
As mentioned previously, flow rate duringDST tests are not usually measured. In casesit is measured or estimated, then we cananalyze these tests by using variable ratemethods; convolution, deconvolution, etc.
Flow Periods As noted previously, pressure increases
during the flow periods of DST. Why does thishappen?
Flow period is an example of wellbore storagedue to rising of fluid in drill pipe.
t1
pwf1
t2
pwf2
pwf2 > pwf1
=
615.5
144 cF
AC
2
pc rA =
density of the fluidin drill pipe.
Estimation of Flow Rate
In cases flow rates are not measured, wecould compute flow rate from the amoun oftotal fluid produced or from measuredpressures, assuming constant wellborestorage coefficient by using the following
formula:
Or using a piecewise constant pressureapproximation for the measured pressuredata.
=
1
1)()(2424)(
jj
jwfjwf
F
t
wf
Fjsftt
tptpC
dt
dpCtq
j
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Estimation of Flow Rate
2
)()( 1+= jwfjwfj
tptpp
An Examplew =/144
= 0.325 psi/ft
Vu = 0.007 bbl/ft
CF = Vuw=0.0215 bbl/psi
qavg = 91.05 bbl/D
(for one-hour
flow period)
Taken from Bourdets book Well Test Analysis: The Use of Advanced Interpretation Models.
An Example
( ) 00
2424
4900.73 4724.5124 0.0215 91 /
1
pt
wf pwfFavg F
p p
p t pdpCq dt C
t dt t
bbl D
= =
= =
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Slug Test Type Curve
Ramey has developed type curves for analyzing flow periods of DSTs, not requiring
the knowledge of flow rate data.
Dimensionless Pressure
0
)(
pp
tpppp
i
wfi
DRwD
==
0
0)(11
pp
ptppp
i
wf
DRwD
==
Dimensionless Time
tC
kh
C
t
FD
D
= 000295.0( )
( )DDF
t
CtCkh
=
/
000295.0
Rameys Slug Test Type Curve
Use of Rameys Type Curve Data is matced only sliding in the time axis
horizontally.
From time match points determined, we can
obtain kh/ with the estimated value of CFfrom: From the value of CDe2s curve matched, we
can estimate skin factor:
( )( )
/
0.000295
D DF M
M
t Ckh C
t=
22
615.5
wt
FD
hrc
CC
=
( )21ln
2
S
D M
D
C es
C
=
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An Example
An Example
k= 41.7 md
s = 6.5
Relationship Between Slug andConstant Surface Rate Solutions
In 1989, Peres et al. (SPE 19843) showedthat slug test data could be converted todata that would be obtined if the well
produced at a constant surface rate.
)()(
000295.0
0
s
iF
cwD pIkh
ppCp
=
( )siF
cwD ptkh
ppCp
=
)(
000295.0
0
( ) = dptpIt
ss
0
))((
)()( tpptp wfis =
Peres et al. method is valid any model; fractured well, etc.
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We can use numerical integration to
perform the conversion:t
Relationship Between Slug andConstant Surface Rate Solutions
= ptp ss0
Trapezoidal rule
( ) =
=
+
=
n
j
jj
jsjsn
j
t
t
sns tttptp
dptpI
j
j1
1
1
1
)(2
)()())((
1
Slug ve Sabit Yzey Debili Testlikisi
Then, we can type curve match I(ps) andtps vs t with the wellbore storage typecurves for constant-rate drawdown tests.
Relationship Between Slug andConstant Surface Rate Solutions
( )( )
M
MDDF
t
CtCkh /
000295.0=
( )
=
D
M
s
D
C
eCs
2
ln2
12
2
615.5
wt
FD
hrc
CC
=
From Derivative and/or Time Match Points:
From the curve matched value of CDe(2s):
( )( )
s
McwDiF
pt
pppCkh
=
000295.0
)( 0
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Example Test 1kh/ = 197 md-ft/cp,s = 0, test during underbalance perforationtest: CF = Vwcwf , cwf = 7.3x10
-6 1/psi, Vw = 331 bbl,ct = 23x10-6
1/psi, = 0.41 cp,h = 39.37 ft
Example Test 2kh/= 575, s = -2.3, = 60 cp, h = 38 ft, = 0.062, ct = 10.2x10-6
1/psi, CF = 3.65x10-2bbl/psi
Example Test 3kh/= 21.5, s = -1.5, = 0.43 cp, h = 23 ft, = 0.13, ct = 1.5x10-5
1/psi, CF = 1.61x10-2bbl/psi
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Slug Test Semi-log Analysis
We can perform semilog analysis of slug test datausing convolution or superposition time
Slope = m
[ ] +
+=
src
tkhptp wt
msF
wf
s 87.023.3log000295.0
.
)(2
0
( )
=
=
0
1
1
1)(
)()(log
ptp
tptpttt
nwf
jwfjwfn
j
jnms
( )[ ]
+
= 23.3log
)/(15.1
2
*0*
wt
ms
twfs
rc
kt
m
pppIs ms
Slug Test Semi-log Analysis
Then, make
( )ms
s tvst
tpI.
)(
plot
( )[ ]
+
= 23.3log)/(
15.12
*0*
wt
ms
twfs
rc
kt
m
pppIs ms
m
Ckh
kh
Cm FF
000295.0
151.1
000295.0
151.1==
Note
It should be noted that Surge, Perforation inflow,and Impulse Tests are all examples of Slug tests,and can be anayzed by the methods discussed for
slu tests. Rahman et al. (JCPT, 2008) uses a late-time
equation given by:
He also gives early time approximations which canbe used to determine skin.
( ) ( ) ( )tkh
ppCptp iFiwf
=
1
2
2.141*24)( 0
His late-time analysis procedure is OK if radial flow exits .
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Example TestFrom semi-log analysis we found: kh/ = 21.1, s = -1.2From type-curve matching: we found kh / = 21.5, s = -1.5
t*ms
DST Buildup Period Buildup pressure data can be analyzed by
conventional methods based onsuperposition time function if the rates can
be computed.
different from the flow period.
wfwS cVC =
Volume between shut-in valve
And production zone, bbl
compressibility of the fluid,
1/psi
Classical Horner Analysis For DSTBuildup
We can use an average flow rate from theslug period:
+=
t
ttmptp
p
iws log)(
(( )/
6.162
kh
qm
averagesf= ( )
=
p
pwf
Faveragesf t
ptpCq
0)(24
+
= 23.3log151.1
2
wt
porti
rc
kt
m
pps
2
)(0 pwfort
tppp
+=
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Convolution for DST Buildup We will use the flow rate computed priorto shut-in:
Once flow rates are calculated, we can use them to
compute Agarwal multi-rate equivalent time:
Nbj
=
+
=
j jp
jp
eMttt
tt1 1
1
Nsf
jsfjsf
jq
qqb
,
1,, =
Convolution for DST Buildup
If we identify radial flow regime from log-logdiagnostic plot of buildup data, then we canperform semilog analysis of buildup data:
+
=N
jpjsfpsf tttqtq 1,)(6.162
= +j jppsfiws
ttttqkh 1 )(
H
psfpsf
Hm
tqkh
kh
tqm
)(6.162)(6.162=
=
( )
+
+
+
+
= =
N
j wtjp
jp
psf
jsfjsf
H
pwfhr
rc
k
tt
tt
tq
qq
m
tpp
s 1 21
11,,1
23.3log
1
log)(
)(
151.1
DST Buildup ExampleLog-Log plot based on Agarwal Multi-rate
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DST Kapama Dnemi/rnek
Klasik Horner grafii
kh/ = 1309 md-ft/cps = 3.3
DST Buildup ExampleHorner Plot
kh/ = 1031 md-ft/cps = 0.8
Wireline Formation Testers They are used as an alternative to RFT and DST
tests. They are used to
Obtain formation fluid samples and pressureprofiling along the wellbore to determine fluidcontacts.
vertical interference (or in general intervaltransient tests) at distinct points along thewellbore.
Determine permeability barriers andsuperpermeability streaks along the wellbore
Determine horizontal and vertical perms (andalso their distributions) along the wellbore.
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Wireline Formation Testers
The radius of investigation of these
tests are normally smaller thanconventional well tests and DSTs, butlarger than cores and logs.
Their radius of investigation is withintens of feet radially and verticallyalong the wellbore.
Wireline Formation Testers
Wireline Formation TestersOverbalance case (pretest)
Sink
Total produced fluid is around 5 to 20 cm3 during pretest drawdown.
formasyon ressure
2900 psi
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Wireline Formation Testers
fz
p=
433.0
Fluid density
Wireline Formation Testersq = 40 cm3/sec
Sink
H
V1
Spherical flow
Wireline Formation Testers
Sink
SinkHorizontal
V probezp
Spherical flow
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Wireline Formation Testers
)(
4.38
=
vp
h
pz
q
k
Slope = ms = 1.51 psi-sec1/2
q (cm3/sec)
=82.9vh qkk
2
)(
)(3.15
=
v
h
p
w
v
h
p
p
z
r
k
k
2
2
)(71064.6 wts
hh rcm
pk
=
hw pr
Packer-Probe Tests
Tests performed with such aconfiguration benefit from the largevolume that can be sampled by thepacker, especially when using apumpout assembly for an extendedtest.
Their radius of investigation is morethan probe tests.
Both packer and probe responses canprovide estimates of kh, k v, and skinprovided that storativity (ct) is known.