asphaltene deposit removal long-lasting treatment with a co-solvent
TRANSCRIPT
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S
Society of PetroIeun ngineers
SPE 21 38
Asphaltene Deposit Removal: Long Lasting Treatment With
a Co Solvent
M.G. Trbovich, WelChem Inc., and G.E. King, * Amoco Production O
SP Member
Copyright
1991,
Society of Petroleum Engineers, Inc.
This paper was prepared for presentation at the SPE International Symposium on Oilfield Chemistry held in Anaheim, California, February 20-22,
1991.
This paper was selected for presentation by an SPE Program Committee following review of information contained
in
an abstract submitted by the author s . Contents of the paper,
as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author s . The material, as presented, does not necessarily reflect
any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subjectto publication review by Editorial Committees of the Society
of Petroleum Engineers. Permission to copy is restricted to an abstract of not more than
300
words. Illustrations may not be copied. The abstract should contain conspicuous acknowledg
ment of where and by whom the paper is presented. Write Publications Manager, SPE, P O Box
833836,
Richardson, TX
75083-3836
U.S.A. Telex,
730989
SPEDAL.
ntrodu tion
Asphaltene
problems
ar e increasing on a wide
scale
in th e
petroleum
industry. The
deposition
of these
materials
has been increasingly not.ed in production
wells of O
2
floods and in miscible drive floods, after
acid
st.imulations
in
a spha lt ic c rude oil formations, and as
pressures
in older fields near
th e
deplet.ion point.
Many reservoirs produce
wit.hout
evidence
of
asphaltenes
until
th e
oi l stability
is
disturbed.
After the
ini tial problems wit.h a spha lt enes , even t ho se cau sed by
a
single use,
catalytic
behaving stimulus
such
as
an
acid
job,
many
wells con ti nue t o exh ib it problems
long
after
opel at.ions return to
normal.
NumenHis n ~ m e d i e s
to remove asphalt.ic
deposits
and stabi lizat ion met.hods t o
control th e
deposit.ion
have
influences
are
removed,
th e
asphaltic
particles
coalesce
into larger
groups, called flocs, that separate and, with
a
density of
1.2
g/cc,
precipitate from th e
oil.
7
Asphal
t en e con tent s may range from 0 to over 60 .8
Resin
volume-to-asphaltene ratio is on the order of 1:1 to 20:1
in oils that
are
s tab le t o
less than
1:1 in oils that ar e
characterized by rapid
precipitation
of
asphaltenes.
7
•
9
•
10
Asphaltene content usually i nc re as es w ith
decreasing
API
gravityll
but instances of asphaltene precipi tat ion in
light
oi l
and even wet ga s streams are known, though
the occurrence
is
rare.
The
treatment
of
the asphaltene deposition problem
should begin with a discussion
of
th e factors
involved
in
inducing precipitation.
Destabilization Forces
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2
ASPHALTENE DEPOSIT REMOVAL - LONG LASTING TREATMENT WITH A
COSOLVENT SPE
21038
2
3.
4
5.
Rich Gas - Flooding with ric h gas destabilizes th e
asphaltene complex by lower ing th e carbon-to-hy
drogen ratio.1
6
Stripping gas from
th e
oil
ha s
been
shown to improve
th e
solubility of
asphaltenes.
17
.
18
The
straight
chain hydrocarbons
have
less affinity
for
the asphaltic
ring structures
that oils that have a
higher carbon-to-hydrogen
ratio. The negative effect of
rich
gas
is
at
a
maximum near
th e
bubble point 1O 12 18 -
20 and
may
decline
afte r th e
bubble point is
reached.1
8
This
behavior
near
th e bubble point
in
more
pro
nounced
with
th e
r ich gas
than
with CO
2
12
pH shift
- This
may
be
caused
by CO
2
,
mineral
acid, or natural ly occurring or bacterial produced
organic acid.
A
shi ft i n well operating
conditions
may alter th e
equilibrium
under
which th e
crude
exists in
th e
reservoir and l iberate more
natural
acids, surfactants, or
other reactants
or products.
Mixing of
crude
streams - Thi s i nc ludes
local
instabilities that may not even
occur
under
more
complete
mixing.1
8
Most likely causes
ar e a
shift
of
pH by a natural organic
acid in an
incoming
crude, and CO
2
outgassing or physical
shear
or
other
d is rupt ion caused
by cavitation in some
pumps
or mixing
manifolds
or chambers.1
8
Prob
lems
of this type can
sometimes
be prevented
by
more complete mix ing
of
th e crude s tr eams unde r
r educed shear .
One
sou rce r epor ted
that a
deposit of as pha lt ic mate ri al was resolubilized
after
mixing
procedure was
changed.
18
This mixing
problem also cover s the a spha lt ic upsets caused
by
ho t
oiling.
Incompatible
organic
chemicals - Isopropyl alcohol,
methyl
alcohol, acetone, and even some
glycol,
alcohol, or
surfactant
based mutua l solvents
that
do no t have an aromatic component ca n
selec
tively
wet or
attract
th e mal tene s and res in s and
drop th e
asphaltenes.
9
10.
temperature
reduction may cause an
area
of
instability, or asphaltene deposition envelope as
described by Leon Taritis,
o
Strict
pressure
f luctua tion can a lso cause precipi ta tion as
shown
by Akbar and
Saleh.1
9
It shou ld
be noted that
these
tests show
the behavior of
specific crude-oil
samples.
Other oils will
vary
in
behavior accord
ing
t o a roma ti c/ asphal tene conten t, mal tene and
r es in con tent, a nd
specific
asphaltene
structure.
Perhaps one of
th e
largest effects on behavior
is
th e
production treatment.
In general, if
asphal
tene
precipitation problems
occur
at one
set of
operating conditions, a
shift
i n wel l head pressure
or
other operating condition
may
change th e ra te
of deposition.
Turbulence
may
increase
th e
amount of asphaltenes precipitated
I9
or improved
mixing of crude streams may
prevent
precipitation.1
8
Streaming potential - Streaming potential through
porous
media ha s
been
identified
as
a cause of
aspha ltene precipi ta tion and mar. be associated
w it h p re ss ur e drop
or
charge.
I
4
Only limi ted
operational
data is
available at this
time.
Temperature drop - This
factor
may have more to
do with ind irec t destabilization by
upsetting
th e
stabilizing
forces
than by having a direct
effect
on
th e asphaltenes.1
3
Temperature may
affect
th e
solubility of
the maltenes
and
resins
or
a temper
ature
drop may
create
a
paraffin
precipitation
that traps
some a sph al te nes as it solidifies. CO
2
also contributes to the oI ganic precipitation
problem
by cooling th e wellbore
during
i ts expan
sion. Temperature readings
during
logging runs
in
producing
wells
with very severe
CO
2
break
through have
been reported as
40°F
below
th e
static
bottom hole
temperature
of
95°F in one
Texas panhandle
location. Other
operators
have
reported
no
significant temperature change.
6.
Stimulation - Very severe asphaltic upsets can
follow
acidizing
and other
forms
of
chemical
treating.
7
16 20 Acidizing involves
a
violent shif t in
local
chemical
equilibrium, pH, and
CO
2
gas
lib
eration.
also sharply elevates concentrat ion of
some
ions, such as iron,21 that may hav e a direct
or symbiotic
relationship
with formation of
11.
Charged, bare
metal surfaces
- This condi tion may
be
a
combination
of
th e
problems
o f s hea r and
pressure drop and
is
one of t he l ea st unde rs tood
of th e destabilizing forces.
3
21 22 has
been not ed
in h igh veloc ity flow streams near liner slots. a nd
may assoc ia ted with
outgassing.
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SPE
21038
M
G TRBOVICH
AND G E.
KING
3
tene content
are
noted
in
th e
literature.
These h ighe r
asphaltene
values ar e
typical of low gravity, high pour
point
crudes.
A high asphaltic
content does
not, how-
ever,
result
in precipitation problems
if
th e resin com-
ponent is also high.1°
Over
a
period
of
severa l years
of
operation
of CO
2
floods and miscible floods, asphaltenes
from several
parts
of th e
country
have been
collected
and
analyzed
for
general solubility.
Most of th e
deposits
ar e
mixed with
paraffins,
scales , and
other foreign material. An analysis
w as made
of a
group
of
samples
from th e Bairoil field
in
Wyoming (under
CO
2
flood). In
this
set of
samples,
with
al l
having
th e same black, viscous appearance, asphaltic
conten ts var ied from 0 to
92 .
The
wide
variety in
composi ti on was
typical
for asphaltene samples col-
lected
ove r th e past t en year s.
Asphaltene deposi tion
in
th e
formation has been
known for an exte nd ed period of time, but has been
described by relatively few authors.
4
•
24
Most in
situ
deposition of
asphaltenes probably occurs as a result
of
th e oi l
mixing
with incompatible solvents, acids, and
other hydrocarbon fluids. These addi tives
or
fluids may
include
drilling, workover, stimulation or packer fluids,
or extraneous liquids
from casing
or tubing
leaks. Once
th e deposit is formed
in
the
formation,
clean up is
often
slow.
Experimental
Results
Of the numerous a sphaltene samples that were
obtained
for
study,
th e solubility in th e primary solvent
xylene was amazingly similar. Approximately 8 to
10 grams of the asph altic m aterial pe r hundred
cc's
of
xylene approached the
solubility
limit. Very
slow
rate
of
removal
as
th e solubility limit is
neared
leads to
speculation that
th e
l im it may be only that quantity
of
asphaltene that can be quickly pulled into
solution.
Additional
material may
be
softened and go into solution
with
time.
Once
in
th e
solution,
the materi al s remained
stable.
Additional
material may
also be
dispersed.
Asphaltene solvents o th er t han
xylene
have
been
t ri ed , bot h
in
th e literature
and
in
th e work for this
study 5 2 27 The per fo rmance o f t he se
additives
is usually
dependent
on
th e specific conditions, reaction is influ-
enced by many
factors.
benefit
in a 1) water
wet s ys tem
or in a
2)
water
external emulsion or sludge that is stabilized by asphal
tenes.
By combining th e xylene
with non adsorbing,
field
proven, water penetrating solvents, a series of cosolvents
were formulated that could outperform
th e
straight
xylene in
asphaltene stabilization tests and some removal
comparisons.
The
cosolvent mix tu re s
ar e
not
an
improvement
on xylene in dissolving capacity;
because
they
are
only
partly
xylene,
actual
solubility is less.
These
cosolvents offer a broader application to asphaltic
removal problems that may inc lude s ludges , emuls ions
and some hard deposits.
These
deposits were found to
be
bound with or
wetted by water in many field
samples.
The
information
gathered through experimental
and
isolated
field tests was taken to th e field
and
tests
on
chemical removal
and stabilization
was started. In many
of t he se t es ts , blends of
sol vent s, b ot h a roma tic
and
linear,
were tried
in
an a tt empt
to
establish
a
balance
of
solubility and wett ing
character.
Field
Resul ts o f
Cosolvent
Treatment
Thirty-one random ly
selected
wells ranging
geographically
from Alaska,
Alberta,
Wyoming , Colo-
rado,
New
Mexico,
Nebraska,
Michigan, Kansas, and
Texas were squeezed treated with t he su rfa cta nt free,
cosolvent
aromatic blends to remove
both suspected and
proved asphaltene damage. The
candidate
wells
from
these areas
were
s el ec ted based on
identification
of low
productivity
from
aspha lt ene and
heavy
tar
deposition,
combination aspha lt ene and paraffin accumulation, and
emulsion formation .
Specific
combinations of w ells
within a field with
common p robl ems were sel ec ted for
comparison with
other
chemical
and
mechanical treat
ments.
The
key areas
of
comparison were:
1)
removal
of damage with a sma ll volume o f t re at ing fluid, and
2) maintenance of the product ivi ty
increase.
In
general,
mechanical scraping was one of the
worst
techniques, with
most operations ei ther failing
to
increase product ion
or
actually decreas ing production.
Single
solvent t reatments
of
xylene were
successful
in
mos t cases
in
restoring
production,
but failed to achieve
long lasting productivity increase. The best overall
damage removal
approach
was
th e use of the cosolvents
that
could
both
dissolve and
disperse
asphaltene
deposits
and
actually
water
wet
th e surf ac es
in vo lved i n
th e
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ASPHALTENE DEPOSIT REMOVAL -
LONG
LASTING TREATMENT WITH A
COSOLVENT SPE 21038
wett ing propert ies
made pos si ble by
th e
us e of moderate
length carbon chain length alcohols. Performance
results
on tests following
th e
recovery of initial load
fluid
ar e shown in Figure 2
for
a dozen
wells from
Canada
to
Nebraska.
Immediate
post treatment
production was charac
terized by a spike of peak production,
followed
by a
slight to
moderate decline,
then a stabilized
rate
with a
slow
decline
last ing several months.
Longevity
effect of
th e
treatment
under
asphaltic
conditions
lasted up to
35 mon th s w it h an
average
improved response of
6
to
8 months . T he r es ult s
from
two of
these
t reatmen ts a re
r ef lect ed in F igures 3 and 4. In this
dat a, t he
peak pro
duction tapers
off
slowly.
Single
component. a roma tic a nd
mechanical c1ean
outs y ie lded lower treatment
peak
production rates, as
well
as
a
shorter duration of
increased productivity.
A
comparison of t he se t re atmen t
results
wit h th os e of a
cosolvent. are
s hown in F igure 5 for
wells
in a
common
field. The mechani ca l
scraping
results in this figure
show poo r
response.
The overa ll success of
th e
scraping
seemed to depend on th e lo cati on of
th e
asphalt . ic prob
lem.
A deposit. in t.he tubing
could
be
removed
by
scraping,19
but s cr ap ing o f a
deposit
near th e
per fs cou ld
introduce
th e
sol ids i nto
th e
perfs. The
xylene
jobs
were
t.ried on th e
higher
rat.e
wells
and p robabl y had
less
ini
t.ial damage
to remove.
The after
treatment
results
of
Product A
showing
over 100 improvement
is
a
typical
response.
On e
of
th e most graphic
illust.rations of
th e
cosolvent's
ability
to providing
long
last ing response is
shown
in
Figure
6. In
t hi s t es t,
a small soak
treatment
with xyl ene r ai sed p roduct ion briefly
bu t declined
rap
idly
to pret.reatment levels. Treatment with Product
B
produced a sharp i nc rease in product ion accompanied by
an equally sharp dec line to pre tr ea tmen t. levels in
less
than
two weeks .
Subsequent
treatment
with
Product A
produced
a
stable
increase
that has lasted
several
months.
Injection well treatment with other solvents, Fig
ures 7 an d 8, shows ver y good r esponse with
pressures
lowered substantially or inject.ion rate improved at con
stant p re ssur e. Longevi ty in these jobs was considered
Payout
Chemical treating payouts of approximate ly one
week wer e
common,
an d al l th e s uc ce ss es were b etween
3 and
30
days.
Th e
extreme short payou t was
possible
by
th e
immediate
spike production, sustained high
levels
of
production and
minimal
mechani ca l app li ca ti on
expense
involved.
Level
o f T r ea tmen t
Success
The treatments using products A, B, an d C were
successful in
27
of
31
treatments with succe ss defined
a s abi li ty to both payout
th e
job in
30
days or less an d
provide longer l as ting result.s t han o th er
alternatives.
The typical initial production
increase
was one
hundred percent .
Th e amount
of
sustained
production
increases varied
with
the t reatmen t.
The c aus es of the four
failures
were varied.
One
of
the failures was a
well
treated with 1 gallft that
res po nd ed v ery
slowly
and required over
30
days'
c le an up to s how an improved rat.e. The delayed response
was
thought
to
be
attribut.ed to below minimal
treat
ment
volumes.
The second
failure
was th e treatment. of an uncon
solidated sand with a
perf
wash tool. The well sanded
up
following
injection. Previous treatments in
these
unconsolidated sands wer e squeezed
down
th e backside.
Two
failures
offered
no
significant explanation to
explain their lack of response. One exh ib it ed a large
incremental response, bu t
declined
to pretreatment
levels.
The fourth
well failed
to respond
and
was
t.hought to be
a problem in placement. The
well
is
heavily
naturally fractured.
Conclusions
The
aromat.ic-containing
cosol vent sys tem
offers
advantages
t o
th e
us e of st l'a ight aromat ic
solvent
in
three areas.
1. The success o f t he cosolvents
of
over
80
in
pro
viding production Increases was very high for
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SPE 21038
M. G. TRBOVICH N
G.
E. KING
5
Nature of
SPE
16713,
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
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2
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2
-Induced Organic Deposition,
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75-12_
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Park,
S.
J ., Mansoori ,
G. A.,
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D. E.,
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Venezuela, pp. 55-62.
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R., Nicoll, D. C.,
Dick,
G.,
Asphaltene
Deposi tion in
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App ro ach To Solve Asphaltene Deposi tion Prob
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James
L.
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J. , (24), (3), 1984, pp. 283-293.
Coppel, C. P.,
Newberg,
P. L.,
F ie ld Resul ts
of
Solvent Stimulation
in a Low Gravity Oil Reser
voir, SPE
3687, 1971, pp. 1-12.
Douglass, B. C., King, G. E., A Comparis on of
Solvent/
Acid Workovers in Embar Completions
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Table
Desc ript ions o f
cosolvents used
in
the w ell
tes ts
Product
Description
A romatic and
straight
chain solvents
with
small amount of hydrophylic solvent
B romatic solvent
with
small amount of
hydrophylic
solvent
C Hydrophylic solvent and small amount of
aromatic solvent
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S 2
8
PRODUCTION
RESPONSE
AFTER
LOAD RECOVERY OF
SEVERAL WELLS TO TREATMENT W T PRODUCT
A
FIGURE 2
14
Cl
12
j
J
Legend
III
_ BOPD BEFORE TREAT
BOPD AFTER TREAT
l
....
::
8
:z;
Eo <
6
U
;::J
::
4
<
W
ll
LONGEVITY
OF PRODUCTION INCREASE
FOLLOWING
TREATMENT W T PRODUCT A SUNSHINE BASIN WYOMING
FIGURE
3
LONGEVITY OF PRODUCTION
RESPONSE FOLLOWING
TREATMENT
W T
PRODUCT
A SUNSHINE BASIN
WYOMING
FIGURE 4
I
I I
Legend
_ PRE TRE TMENT BOPD
AFTER TREATMENT BOPD
I I
o
3 6 9 5 8 4 7 3
MONTHS AFTER TREATMENT
3
5
III
Z
Eo <
15
U
;::J
::
1
l
5
8
6 9
MONTHS AFTER TREATMENT
o
o
5
3 i i
5
......
o
o
III
z;
o
......
Eo < 15
U
;::J
Cl
o
::
1
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S lOS
500
I I I I
THREE
TREATMENT
COMPARISON
ON
AN
ASPHALTIC
OIL
PRODUCER
WYOMING SAKDSTONE
FIGURE 6
C O ~ P R I S O N OF
ASPHALTENE
REMOVAL
METHODS
PEAK
PRODUCTIO)J, NEBRASKA
WELLS
FIGURE 5
~
00
PRODUCT
C
TREATMENT
OF AN
INJECTION
WELL
MEDICINE HAT, ALBERTA
FIGURE 7
.00
······1
PRODUCT C TREATMENT OF
AN
INJECTION
WELL
MEDICINE HAT,
ALBERTA
FIGURE 8
Il
i
\
I
3700
GAL
PROD.
A
SOAK
I T i ~ I ~ ~ L S O A K
QZ
I
i
i
o 100
200 300
400
500
60 0
CUMULATIVE TIME
DAYS
z
o
E::
u
p
<=>
o
po:
200
p.
o
Ii:
J: 30 0
Legend
/ _
BOPD
BEFORE
TREAT.
a
BOPD AFTER TREAT. a
SCRAPE XYLENE XYLENE SCRAPE A AA
o
A
Po<
o
80
Ii.1
.-<
o 60
0::
Po<
Z
o
b
u 40
§
0::
Po<
20
g
7000
, I 400
400 iQ
>.LI
::g
U
300
;:0
8
p::
>.LI
E <
200
o
>.LI
tl
>.LI
....
100
- -1 -_- - 0
o
3 6 9
12 15 18 21 24 27 30
33 36
MOl THS OF
OPERATIOl
Legend
_ PRESSURE -
KPA
INJECTION RATES M3
o
I
j
2000
6000
6000
,
I
500
a:
::<:
I:k:
;:J
[fJ
[fJ
4000
J
Z
o
CIJ
P::
30 0
>.LI
::g
U
;:0
P
u
200 p::
>.LI
o
> LI
tl
100 >.LI
88
f8:i
f;§3
I
I
I
fa fa
8:1E
I
@l f?j
?J i J
0
I
I I
6 9 12 15 18
21
24 27 30 33
MONTHS
OF
OPERATION
o
Legend
_ PRESSURE -
KPA
I2J
INJECTION
RATES
-
6000
1000
a:
5000
::<:
I:k:
iii
4000
}
I:k:
J
Z
3000
o
t=:
u
...,
:5 2000