Part 15 Slug Dst Mdt Iptt

8/13/2019 Part 15 Slug Dst Mdt Iptt

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Slug DST WFT MDT - WTA

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


= 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.


( )( )

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 TestersOverbalance case (pretest)

Sink

Total produced fluid is around 5 to 20 cm3 during pretest drawdown.

formasyon ressure

2900 psi


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fz

p=

433.0

Fluid density

Wireline Formation Testersq = 40 cm3/sec

Sink

H

V1

Spherical flow


Sink

SinkHorizontal

V probezp

Spherical flow


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)(

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.

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Part 15 Slug Dst Mdt Iptt