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E 49102
rmation Fines Stabilization
. J. Maberry, SPE, Dowell, Syed A. Ali,
E, Dowell
pyright 1996, Society G+Petroleum Enginee=, Inc
6iila
m
. .
Society of Petroleum Engineer
Using Surface Adsorption Polymerization
SPE, Chevron USA Production Co., S. B. McConnell, SPE, and J. J, Hinkel,
is paper wss prepared for presentat ion at the 199S SPE Annual Technical Conference and
hibtion held inNew Or leans, Louis iana, 2743 September 1998.
is paper wss selected for presentat ion byan SPE Program Commi ttee fo llowing rsview of
ormation cuntabwd in an abstract submi tted by the author(s) . Contents of the paper , as
=nted, fi~ @ *n ~ewed by the Society of
PebdeumEngineers
nd are subjed to
rrection by the autho r(s ). The material, as p resented , does no t necessarily refxt any
sit ion of the Society of Petroleum Enginesrs , i ts t i cers, or members papas presented at
E meetings are subject to public&ion Hew by Edtwial Committees of the Satiety of
troleum Engineem. Electronic reproduction, distribution, or storage of any pmt G his paper
commemial purposes wi thout the wi tten mnsent of the Society of Pet ro leum Enginesrs is
ohibtsd. Permission to reproduce in print i s restr ic ted to an abstrsct of not more than 300
rck illustrations may nof bs copied The abstract must contain conspicuous
knowledgment ofwhere and bywhom the papw was presented. Wri te Librari an, SPE, PO.
x S33836, Richardscm, TX 750S3-3SS8, U.S.A., fax 01-972-952-943S.
ormation fines are ubiquitous in oil- and gas-bearing
ndstones. Formation damage resulting from dispersion and
igration of fines is a major concern in producing wells.
hese fines are mineralogically diverse and become a
oblem when they detach from pore walls, migrate with
owing fluids and choke off pore throats. The formation
age resulting from fines migration causes a reduction in
ll performance. A treatment that will inhibit the migration
fines will improve long-term well production. This paper
sents the results of a laboratory evaluation and field case
stories of fines control treatments in sandstone,
rmation damage resulting from dispersion and migration of
ays and other formation frees is a major concern. Fines
ome a problem when they become detached from the pore
ll and migrate through flow channels with produced fluids.
hese mobile fines are eventually deposited in pore throats.
lugging pore channels and causing a reduction of
rmeability. Factors contributing to the production of fines
clude exposure to high pH fluids, exposure to fresh (low
linity) water, fines nettability and increased fluid
The critical interstitial veloeity is the rate
yond which fines detachment and migration occurs.z
itical velocity can be used to determine injection rates used
core flow evaluations so that fines detachment and
gration can be controlled.
Quaternary ammonium salts, sulfonated polymers,
drolyzable metal ions and organosilane products have been
used to mitigate fines migration. These chemicals
adsorbed on the surface and prevent detachment by forming
protective shield around negatively charged clay particl
These additives have often been termed permanent c
stabilizers, and when compared to stabilizers such as KCI
IWLCI, they ean provide more than temporary c
protection. In reality the effects of such treatments may
much less than permanent. The potential disadvantages
these treatments are 1) charge neutralization does not preve
mechanical dislodgement of particles subjected to high fl
velocities; 2) fines with low charge density (feklspars)
not controlled effectively by charge neutralization, and
only tempora~ control is obtained because the polyval
ions tend to desorb over time as large volumes of fluid
produced. 3
Reeently, Stanley et aL4 field tested an alterna
fines stabilizer, organosilane, with limited success. The
limitations point toward the need for Mher research i
fines stabilizing techniques.
The hydrodynamic entrainment of fines can be preven
only by coating the fines with a solid thin film that is stable
high shear rates.3
A novel process has been developed
controlling the detachment and migration of formation fin
The process is a surface adsorption polymerization (SA
teehnique that forms a thin film that is stable at high sh
rates, thereby effectively immobilizing the fines on the p
wall surface.3 SAP is a three-step process that invol
adsorption of a cationic surfactant on the porous medi
followed by a monomer solution that preferentially resides
the surfactant layer.
An initiator solution is then used
polymerize the monomer on the surface of pore wa
forming an ultrathin film that is very stable and effectiv
immobilizes the fines on the pore wall surface. Prelimina
laboratory evaluations showed tines stabilization at h
velocities and long-term effectiveness with exposure to fr
water.3
The treating fluids are prepared using fresh wa
containing NaCl, NH4C1, or KCL The fluids are injec
individually and following the sequenee of surfaeta
monomer, and initiator. The treatment is displaced to
perforations and the well is shut in 2 to 6 hr.
A pump skid is used for injection. The treatment can
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2 L. J. MABERRY, SYED A. AL1, S. B. MCCONNELL, AND J. J. HINKEL
SPE
delivered down coiled tubing, and a downhole sensor package
(DSP) ean be used to monitor and reeord injeetion pressure
and temperature. Ml piping, valves, tubing pumping and
injeetion equipment are pressure and leak tested with brine or
seawater prior to pumping treating solutions. A stepped-rate
injeetion test with brine is performed to establish formation
injeetivity.
From this test, an initiaI injection rate is
eakmlated.
A ratio of 5:3:2 stiactant:monomecinitiator is
recommended. Required volumes ean be calculated based on
the volume of wufactant required to achieve desired
penetration into the formation and the eationic exchange
capacity of the rink, The cationic exchange capacity (CEC) is
a routine test performed in drilling fluids. The CEC for a
given formation is given in units of me@OO g and em be
used to calculate the volume of surfaetant necessary for a
given treatment.
The CEC in meq/100 g reek must be
converted to meq/cm3 of the reek pore volume, The porosity
of the reek ( ) and the CEC (in meq/100 g) is needed for this
calculation.
CL= CEC in meql cm pore vol. of rock
1)
2)
3)
4)
CEC (mea/100g) = CEC (me@g)
100
Calculate meq/cm3 ofrock
CEC (m@g) x 2.5 g/cm3 (average density of clays)
Calculate meq/cm3bulk volume of reek
CEC (meq/cm3) x (1- )
calculate meq/cm3pore volume of reek = Q
CEC (mea/bulk volume of reek)
4
5) Q,=~x 2.5 X@
100
+
CaleuIate the Required Volume of Surfactant:
pore volume of reek x Q, x MW,ti x 1
1000
C,d
1) z ((r,+ rW)2-W2)h = pore volume of reek treated (cm3)
rt =
radial penetration
r. = wellbore radius
h = net height
2)
3)
4)
Meq surfactant necessary to satis~ pore volume of
(meq/cm3pore volume of reek)
rc((rt+ rW)2-W2)h (cm3) x Q,
Conversion of meq to eq:
n ((r, + rW)2-rW2)h x Q
1000
Conversion to grams:
MW,ti = moleeular wt of surfactant (grams/equivalent
5) Conversion of grams to liters:
Cd = umeentration of surfaetant (grams/liter)
6) Calculate liters surfaetant, V,~:
Q,
.X Mws~x. ,1
1000
C,
Volume of monomer solution:
v
monomer
V,d
x
.60
Volume of initiator:
Vmitk,m
= V,tix 0.40
Experimental Approach
Berea sandstone cores ( 3- to 5.5-in. length, l-in. dia
were placed in 270 (wthvt) NaCl under vacuum for a pe
2 - 3 hr for saturation. All fluids were prepared
deionized water. The core was placed in a Hassle
coreholder under a contlning (overburden) pressure o
psi and a backpressure of 200 psi. Low-range and high
Rosemount differential pressure transducers were u
measure pressure drops. Fluids were delivered with an
2350 HPLC reciprocating piston pump designed for s
delivery in liquid chromatography applications requirin
rates of up to 10 mLhnin and pressures up to 6000 psi.
tests were performed at a temperature of 140F (60C)
constant fluid delivery rate. A flush of 20 mL was used
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E ~1~
FORMAT\ON FINES STABUUAT\ON USING SURFACE ADSORPTION POLYMERIZATION
fluid injeetion into the core. Baseline and regained
rmeabilities were obtained by flowing 2% (wtht) NaC1
lution through the core until a stable permeability was
tained. Treating fluids were flowed in reverse direction.
consolidated Formation Fines From Gulf Coast Field.
test cell used to eonfhe the core had an inner diameter of
in. The end caps were designed with sliding pistons so that
ssure (nitrogen) could be placed on either end to contlne
e core (Fig.
1).
Low range and high range Rosemount
Herential pressure transducers were used to measure
essure drops.
Fluids were delivered with an ISCO 2350
PLC reciprocating piston pump designed for solvent
livery in liquid chromatography applications requiring flow
tes of up to 30 mL/min and pressures up to 2500 psi.
core was prepared as follows:
The pack length was 3 in.
The pack diameter was 2 in.
1:1 formation material: 100 mesh sand was neeessary to
maintain reasonable permeability while applying
confining pressure.
1 in. 20/40 mesh sand was placed on either end of the
sandpack and retained by a gravel-pack screen.
250 psi confining pressure was applied to back side of the
sliding pistons on opposite ends of test cell.
Fluids were delivered with an ISCO 2350 HPLC
reciprocating piston pump designed for solvent delivery
in liquid chromatography applications requiring flow
rates of up to 30 mL/rnin and pressures up to 2500 psi.
Rosemount dMerential pressure transducers were used to
measurv pressure drops.
ffeets of Solvent/Acid on SAP Treated Cores.
A Berea
re, approximately 3 in. in length, was used in testing under
e following conditions: confining pressure of 2000 psi,
bient temperature, 200 psi back pressure for baseline and
tained permeability measurements, and no back pressure
hen injeeting treating fluids. A solution of 30 WC1 was
jeeted immediately following each acid stage to ensure that
e acid would not remain within the core for extended
riods of time. The pH of the effluent was checked at the
scharge line to ensure the pH of the fluid was no longer
idic before proceeding A 20-mL flush of the lines was
cluded when changing fluids. All treating fluids were
jeeted in the reverse direetion, with the exeeption of
turned treating fluids, which were injected in the forward
reetion and followed last in - first out order of injeetion.
he returned acids were not spent, but diluted in strength by
e-thir~ representing flowback of weakene~ live acid. All
uids were injected at a constant rate of 3 mL/min.
eating fluids and volume injeeted:
5 pme volumes: xylene, organic acid
5 pore volumes: 8% NI&Cl
5 pore volumes: 10% HC1
5 pore volumes: 13:1.5 HCI:HF
5 pom volumes:
5V0
HCI
Unconsolidated Formation Fines From North Sea Fie
The cores (3-in. length, 1-in. diameter) were prepared
packing the unconsolidated solids (solvent cleaned) into
organic-fluoride polymer tubing. Screens and retainers w
used to aid in confinement (Fig. 2).
The cores were placed in formation water under vacuu
for a period of 1 hr for saturation, Additional fluids w
prepared using deionized water. The core was placed in
Hassler-type eoreholder under a cxmtlning (overburde
pressure of 1200 psi. Low-range and high-range Rosemou
ditXerential pressure transducers were used to measu
pressure drops. Fluids were delivered with an ISCO 23
HPLC reciprocating piston pump designed for solve
delivery in liquid chromatography applications requiring fl
rates of up to 30 mL/min.
Core tests were performed
ambient temperature and a constant fluid delivery rate.
flush of 20 mL was used prior to fluid injection into the co
Baseline and regained permeability measurements w
obtained by flowing the seleeted brine solution through
core until a stable permeability was obtained. Treating flu
were flowed in the reverse direetion of permeabil
measurements.
T r ea t m en t T h r ou g h a Pr ev w u sl y T r ea t ed S ec t i on .
Unconsolidated formation fines were packed into a l
section of transparent 1-in. diameter PVC tubing. Fluid w
injected at 20 mL/min using an ISC02350 HPL
reciprocating piston pump. The pack was eonfined w
screens at atmospheric pressure and was vertically orient
with flow ftom bottom to top. The core was allowed 3 hr
curing following the SAP treatment. An additional I
section was prepared and connected to the initial ewe.
second SAP treatment was flow@ passing through
treated seetion and into the untreated seetion. A soluti
containing 3XO WC1 and methylene blue was flow
through the core following each treatment to sh
penetration through treated seetions
Laboratory Evaluation
Fines stabilization in Berea core was demonstrated throu
the initiation of a fkesh (deionized ) water shock to treat
and untreated cores. A 5.5-in. Berea core was subjected
2 NaCI brine flow until a sfable permeability of 92 nd) w
obtained. Seven pore volumes of tlesh (deionized) water w
flowed in reverse direetion, decreasing the permeability of
core to 3 mD. Ten pore volumes of a
20
NaCl solution w
again flowed in a fonvard direction, reestablishing
permeability of 3 rnD Table 1).
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4 L. J. MABERRY, SYED A, ALI, S. B. MCCONNELL, AND J. J. HINKEL
SPE
A 2 NaCl solution was flowed in another 5.5-in. Berea
core until a stable pmeability of 153 mD was obtained.
SAP treatment was injeeted in reverse direction, with
permeability values ranging fkom 113 to 132 mD during
treatment. Volumes for the treating solutions were 50 pore
volumes surfaetant, 30 pore volumes monomer and 20 pore
volumes initiator. The core was shut in for 6 hr in the heated
(60*C) core apparatus, after which a stable permeability of
127 mD was obtained with
27.
NaCl solution.
Six pore
volumes of tlesh (deionized) water were flowed in reverse
direction with a resulting permeability of 120 rnD. A
regained permeability of131 IUDwas obtained with
2 40
NaCl
solution. Seven pore volumes of flesh (deionized) water were
flowed in forward direetio~ followed by a
27.
NaCl solution
until the permeability was stable at 140 mD
Table 2).
The
above tests showed fkesh water shock caused
significant damage to the untreated core (pereent retained
permeability was calculated as 3%), while minimal damage
was observed in the treated core. The treated core showed a
retained permeability of 92% foI1owing exposure to 13 pore
volumes fresh water (Fig. 3).
To determine the effects of oilhrine saturation on fines
stabilization,
a
3-in. Berea core was subjected to flow of oil
and brine injected at 3 mL/min. Permeability to brine at
residual oil saturation was obtained prior to SAP treatment by
flowing oil through the core followed by a
27.
NaCl solution
until a stable permeability was obtained. This permeability
was considered the baseline permeability measurement which
was used in retained permeability calculations following fresh
water shock. SAP treatment was then applied and the core
was shut in for 6 hr at 60C. Volumes for the treating
solutions were 50 pore volumes sutiaetant, 30 pore volumes
monomer and
20 pore volumes initiator.
Following
treatment and a shut-in perid the core was subjeeted to 15
pore volumes fkesh water. Subsequent flow of brine and oil
indicated a 100Aretained permeability to brine at residuaI oil
saturation and a 98%retained permeability to oil at residual
brine saturation (llig. 4).
Tests were pertiormed to determine the effectiveness of
SAP treatment on Berea core subjected to fewer pore volumes
of the treating solutions. Initial baseline permeabdity was
established by ftowing 2% NaC1. SAP treatment was injected
in reverse direetion and the core was shut in for 4 hr at 60C.
Volumes for the first test were 25 pore volumes surfaetant,
15 pore volumes monomer and 10 pore volumes initiator.
Twentyseven pore volumes of deionized water (flowed
through the core in forward direction following treatment)
showed no deerease in pmneability. In the second test, not
only were the injeeted pore volumes d- the
recommended ratio of 5:3:2 (stiactant:monomer initiator)
was modified to 5:3:1.
In this test 10 pore volumes
surfaetant, 6 pore volumes of monomer and 2 pore volumes of
initiator were injeeted in reverse direetion, after which the
core was shut in for 4 hr at 60C. Thirty-two pore volumes of
deionized water provided no loss in core permeability
5). This test showed that fewer pore volumes of tr
fluids can provide an effeetive treatment even when ha
recommended volume of initiator is injeeted.
An alternative fines stabilization treatment was perfo
on a 3-in. Berea core using l% organosilane (vol/vol) in
0/0
NaCl solution. Prior to treatment a stable ba
permeability to 2% NaC1 brine was obtained. Five
volumes of the organosilane solution were in
Reestablishing permeability of the core to 2% NaCl
showed a 108/0 retained permeability following treat
Permeability of the core following 15 pore volumes of
water (injeeted at 5 mIJrnin) showed a retained perme
of 105XOwhen compared to the baseline permeability p
treatment. A 2% NaCl brine was again flowed unti a
permeability was obtained. Permeability to brine at re
oil saturation was obtained by flowing oil (10 pore vol
followed by a
2 0
NaCl solution to a stable permea
From this point forward this value was used as th
baseline permeability in retained permeability calcula
Ten pore volumes fresh water injected at 5 mLhuin sho
retained permeability of 67% while 10 pore volumes o
water injected at 9 mL/min reduced the retained perme
to 30% (Fig. 6).
The above tests show the organosilane treatment to b
effective in the absenee of oil.
However, when oi
introduced the core became sensitive to fresh water, esp
at higher fluid veloeity, resulting in a significant redue
permeability.
An evaluation of SAP treatment on unconsol
formation material was performed. The formation
were taken (during drilling) from a well in the G
Mexieo, Sieve analysis on these solids showed
75 .
we
than 150 microns (passing through 100 mesh screen
50XOwere less than 75 microns (passing through 200
screen). A special sandpack and apparatus were u
testing (Fig.
1).
A 2%NaCl solution was first injec
increasing rates. At an injection rate of 10 mL/miN
treated and untreated cores showed a permeability of 13
At 15 mIJmin and 25 nd.bin, pmmability of the
core was reduced to 110 rnD, while the untreated
decreased to 24 mD.
Fresh water was injeeted
Permeability of the treated core was reduced to 75 mD
injeetion rate of 25 rnL/min, while permeability
untreated core was redueed to 3 mD at 15 mLhnin (F
The SAP treatment stabilized the core from the eff
increased fluid velocity and fresh water slwek. Migrat
solids was also controlled with the treatment. Solids
effluent (colleeted on 5-micron filters installed in l
discharge) showed solids present in the amount of 96
for the untreated sample. The sample treated with
showed only 3 mg/L solids present
Table 3).
comparison of the filters substantiated these findings (F
Testing was also performed at 120F to ident~ a
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49102 FORMATION FINES STABILIZATION USING SURFACE ADSORPTION POLYMERIZATION
tem that would remove the SAP treatment. An SAP
atment was first performed on a Berea sandstone core.
bsequent injection of 20 pore volumes of fresh water
wed 100/0retained permeability, indicating treatment was
Table 4).
A solvent solution (a blend of toluene
a mutual solvent) was injected to determine the volume
ired to remove the SAP treatment. Baseline permeability
2XONaCl was established followed by a fresh water shock.
lvent injection was continued until a drastic reduction in
eability was observed with exposure to fresh water. The
ta show that 60 pore volumes of the solvent solution are
to remove the SAP treatment
Table 4 ).
Testing was performed to determine the effects of typical
d treatment fluids on the performance of
an SAP
atment. Baseline permeability of 262 mD was obtained
th 3XONJ&Cl, followed by injection of treating fluids
ble 5). An SAP
treatment was then performed on the
re. Reestablished permeability to 3AmCl was 456 mD
lowing acid and SAP treatment. Subsequent injection of
pore volumes of fresh water showed a permeability of 401
8 8 7 0 retained permeability), indicating treatment was
Table 5). The
treating fluids were then injected
lowing a last in - first out order of injection. The returned
ids were not spent, but diluted in strength by one-third
esenting a worst-case flowback of weakened live acid.
ter the returned fluids were injecte~ permeability to 3%
Cl improved to 573 mD. Injection of 20 pore volumes of
sh water showed a permeability of 548 mD or 96%
ined permeability
Table 5). This
indicates the
SAP
atment remains effeetive following flowback of the acid
ating fluids, and the volume of ~lene (5 pre volumes
wed back) had not significantly affected the SAP
SAP was also evaluated on unconsolidated sandstone core
m a North Sea field with permeability from 1 to 2 D.
lls in this field utilize prepack screens and/or 110-micron
cluder screens. Migration of formation tines is a major
The effect of increased fluid flow rate was evaluated in an
treated core. It was determined that removing the core
tlet screen was neeessary to allow for fines movement. A
re with the outlet screen (lower screen considering top to
ttom vertical flow) removed was subjected to injection of
WCI brine at 25 mL/min. The measured permeability
owed a steady increase through 70 tin (from 1800 to 2800
D), indicating the pack was being disrupted and fines were
ving. Severe movement occurred between 70 and 110 ruin,
indicated by more radical permeability increases, followed
a rapid decrease in permeability (
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6
L. J.
MM3ERRY,
SYED A. ALI, S. B. MCCONNELL, AND J, J. HINKEL SP
Figure 11 shows oil production over an 8-month period
lxfore and after treatment. Presently, sand production has
keen controlled for 8 months following treatment, as the well
continues to produce only a trace (
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*O2 FORMATION FINES STABILIZATION USING SURFACE ADSORPTION POLYMERIZATION
TABLE lUNTREATED BEREA CORE EXPOSED TO FRESH WATER
Pore
Permeability
Fluid Direetion Of Flow Volumes
mD) Comments
2% NaCl Brine Forward 10
92 Baseline permeability
Fresh Water Reverse
7
3 Damaging fluid
~ 2%NaCl Brine Forward 10
3
Re ined rrneability
TABLE 2-TREATED BEREA CORE EXPOSED TO FRESH WATER
Pore
Permeability
Fluid Direetion Of Flow
Volumes
mD) Comments
2%NaCl Brine
Forward 11
153 Baseline permeability
SAP Reverse
50
132 Treating fluid
Solution 1
SAP
Reverse 30
132 Treating fluid
Solution 2
SAP
Reverse 20
113
Treating fluid
Solution 3
2V0NaCl Brine Forward
17
127 Regained permeability
Fresh Water Reverse 7 120 Damaging fluid
2%NaCl Brine
Forward 7
131
Regained permeability
Fresh Water
Forward 6
140
Damaging fluid
2%NaCl Brine Forward 5
140 Regained parneability
I
TABLE 3-FORMATION PACK FINES MIGRATION SOLIDS COLLECTED ON FILTER
INSTALLED IN-LINE AT DISCHARGE
Filter Initial Filter Final Filter
Total Fluid
Total Solids
Identification
Wt g)
Wt (g)
Flowed mL)
m L)
Untreated Core
0.164 0.238
770
96
SAP Treated Core
0.163
0.166 1120
3
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L. J. MABERRY, SYED A. ALI, S. B. MCCONNELL, AND J. J. HINKEL
SP
TABLE 4-REMOVAL OF SAP TREATMENT
TEMPERATURE = 120F)
Pore Permeability
Fluid Direction Of Flow
Volumes
mD) Comments
2V0 NaCl Brine
Forward
166
Baseline
lxxrneability
SAP Solution 1
Reverse 20
121 Treating fluid
SAP Solution 2 Reverse 12 127 Treating fluid
SAPSolution 3
Reverse
8
125
Treating fluid
2%NaCl Brine
Forward
226
Regained
permeability
Fresh Water
Forward 20
230
Fresh water shock
Solvent Solution
Reverse
10
---
Solvent Treatment
2%NaCl Brine
Forward
10
---
Mutual solvent to
+ 50/0 Mutual
water wet core
Solvent
2% NaCl Brine
Forward
203
Regained
Wrmeability
Fresh Water
Forward
20
190
Fresh water shock
Solvent Solution Reverse 20 . . . Solvent Treatment
2%NaCl Brine
Forward
---
Mutual solvent to
+ 50/0 Mutual
water wet core
Solvent
2% NaCl Brine
Forward
188
Regained
permeability
Fresh Water
Forward
191
Fresh water shock
Solvent Solution
Reverse
30
.
Solvent Treatment
2% NaCl Brine
Forward
---
Mutual solvent to
+
5 0
Mutual
water wet core
Solvent
2% NaCl Brine
Forward
130
Regained
permeability
Fresh Water
Forward
20
66 Fresh water shock
Solvent Solution
Reverse
20
-
Solvent Treatment
2?4.NaCl Brine
Forward
---
Mutual solvent to
+ 5% Mutual
water wet core
Solvent
2XONaCl Brine
Forward
51
Regained
permeability
Fresh Water
Forward
20
19
Fresh water shock
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mrx?
FORMAT\ON FN4ES STAB\lJZATION USING SURFACE ADSORPTION POLYMERIZATION
TABLE 5-EFFECTS OF SOLVENT/ACTDFLUIDS ON SAP TREATED CORES
Permeability
Retained
~
Permeabil-
Original Baseline Permeability
262
.-
preestablished Baseline Permeability Following
Injection of Treating Fluids (xylene, acid SAP
456
-.
treatment)
Fresh Water Shock (20 PV) 401 88%
Reestablished Permeability Following Acid/xylene
573
..-
Flowback
Fresh Water Shmk (20 PV)
548
96?4.
g. 2-Unconsolidated Core Assembly
100
I I
..
F.
1
Fig. 3-Effects of Fresh Water Shock
Berea core sensitized in
2V0
NaCl
Permeability of core= 100-150 mD
-1
unlrcamdam
Arhr 7
Pom Volumes of Fresh
-r Injected
Trea ted Core Mt8r 6 Pow
Volumes Fresh Water
lnJectad
1
-==
Tmtid Cora Mt@r 1S
Pom Volumes Fresh
Water In@c*d
., .-
110
100
7
Permeability
90
to brine at
raaidual oil
80
saturation
70
60
I
Permeability
60
to oil at
raidual brim
40
saturation
30
20
10
0
k----
..
Fig. 4-Retained Permeability to Oil and Brine Followin
SAP Treatment and Injeetion of 15 Pore Volumes Fresh
Water
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8/10/2019 00049102[1] Sln-polimerizacin Adsorcin Superficie-Chevron
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8/10/2019 00049102[1] Sln-polimerizacin Adsorcin Superficie-Chevron
11/11
LR7W FORMATION F\NES STABILIZATION USING SURFACE ADSORPTION POLYMERIZATION
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