00049102[1] Sln-polimerización Adsorción Superficie-Chevron

8/10/2019 00049102[1] Sln-polimerizacin Adsorcin Superficie-Chevron

1/11

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

461


2/11

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

462


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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).

463


4/11

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

464


5/11

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 (


6/11

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 (


7/11

*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

467


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8

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

468


9/11

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

469


10/11


11/11

LR7W FORMATION F\NES STABILIZATION USING SURFACE ADSORPTION POLYMERIZATION

--- Prtor to Treatment After Treatment

-..

800

I

f

6

8 Jsand prduction

o

. . .

00049102[1] Sln-polimerización Adsorción Superficie-Chevron

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Transcript of 00049102[1] Sln-polimerización Adsorción Superficie-Chevron