Relative permeability restoration using primary alcohols

Journal of Petroleum Science and Engineering, 6 ( 1991 ) 73-80

73

Elsevier Science Publishers B.V., Amsterdam

Relative permeability restoration using primary alcohols M.M. El-Gassier, A.E. Omar, A.S. Dahab and H. Awad-el-Kariem Petroleum EngineeringDepartment, King Saud University, P.O. Box 800, Riyadh 11421, Saudi Arabia (Received April 18, 1990; accepted after revision February 5, 1991 )

ABSTRACT El-Gassier, M.M., Omar, A.E., Dahab, A.S. and Awad-el-Kariem, H., 1991. Relative permeability restoration using primary alcohols. J. Pet. Sci. Eng., 6: 73-80. Two primary alcohols, iso-propanol and n-hexanol, were tested for the restoration of the permeability of damaged sandstone cores. The sandstone cores were Berea sandstone and two sandstone samples from Saudi reservoirs. Permeability damage was established by displacement with fresh water and was characterized by a decrease in the relative permeability to oil and increase in the oil residual saturations. The extent of damage varied according to the mineralogical composition. Treatment with isopropanol had no effect on the damaged relative permeability to oil nor on the increased oil residual saturation resulting in no change in the oil recovery. Therefore, it was considered to be an unsuccessful additive. N-hexanol, however, proved to be a successful additive. It increased the oil recovery by as much as 6% in some cases.

Introduction

Formation damage is characterized by a decrease of the relative permeabilities to oil and water, an increase in the residual saturation, and a decrease in oil recovery. The principal causes of these changes are dispersion of authigenic clays and fines attached to the pore walls and swelling of clay minerals (Baptist and Sweeny, 1955; Monaghan et al., 1959; White et at., 1960; Mungan, 1965; Gray and Rex, 1966; Maly, 1976; Gruesbeck and Collins, 1982). Originally, a formation will be in a dynamic equilibrium with its interstitial solution. An electric double layer extends from the charged surface into the solution. There is a net negative charge at the pore surface. The charge compensation ions are held in both a diffused three-dimensional atmosphere, and a two-dimensional layer of molecular thickness. Each type of exchangeable cation can be found both closely bounded to the surface and dissociated 0920-4105/91/$03.50

from the surface as a part of a swarm in the aqueous phase. The concentration of cations is greatest near the surface and decreases exponentially into the bulk of the solution (Sposito, 1981 ). When flooding a formation with a solution of much lower concentration than the interstitial solution, ions are continuously removed from the interstitial solution and a consequent readjustment in the thickness of the diffused layer occurs. This will result in a loosening of the binding charge between clay crystals and fines and the pore surface. Two distinct phenomena will result: ( 1 ) detachable clay crystals and fines will flocculate; and (2) swelling clay will start to expand due to the adsorbtion of broken-bond water and interlamellar water. These phenomena may occur individually or simultaneously depending on the abundance of swelling and detachable days and fines, and on the dynamics and structure of the pore surface and interstitial water (Gray and Rex, 1966; Arnold, 1978).

© 1991 - - Elsevier Science Publishers B.V.

74

M.M. EL-GASSIER ET AL.

Review of the literature indicates that several organic and inorganic fluids have been suggested for additives to restore the permeability, yet no conclusive results have been obtained (Bernard, 1955; Atwood, 1964; Clementz, 1982; Omar and El-Gassier, 1985). Water soluble alcohols dissolve the water trapped in swollen clay crystals causing them to collapse and hence substantially decrease in volume. Normal hexanol was used in this study because its partial miscibility with water should lead to diffusion of water through the brine additive interface which also may dehydrate the clay. Iso-propanol was used because of its total miscibility with water.

TABLE 3

Base exchange capacity of untreated clays Core type

Berea Alkhafgi Aramco

TABLE 1 Mineralogical analysis of cores Core type

Quartz (wt%)

Feldspar

Clays

(wt%)

(wt%)

Other minerals

(wt%) Berea Alkhafgi Aramco

75 92 85

10 2 3

10 5 8

5* 1 4**

*Mainly dolomite. **Mainly pyrite. TABLE 2

Relative abundance of clay minerals in the cores Core type

Kaolinite

Chlorite

Illite

Smectite

Berea

63 69 40

9 25 27

25 17

traces

Alkhafgi Aramco

6

Net base

(milliequivalent / 100 g)

exchange

Mg 2÷

Ca 2+

Na ÷

capacity NH4 distillation

4 2 16

3 5 5

17 7 26

17 7 26

TABLE 4

Sequence of displacement runs* No.

Saturating fluid

Displacing fluid

Sw**

1

5**** oil

oil*****

swi

5

5

oil

oil

0 oil 0

1 - Sot swi 1- s o t ~s~, l - Sot

damaged

1 - Sot

treated

Procedure Cores from Berea sandstone and two Saudi sandstones (one from Aramco and one from Alkhafji production areas) were used. Tables 1 and 2 present the mineralogical and chemical properties of the sandstones. The base exchange capacity of the untreated clays is given in Table 3 (Omar et al., 1988 ). The Saudi reservoir rocks (Aramco and

Cations

2 3 4 5 6

0

oil

kro and k~w curves*** undamaged

Additive Treatment 7

oil

5

*Overburden pressure = 1000 psig; temperature = 30 ° C. **At the end of the displacement. ***Calculated using the method of Johnson et al. ( 1959 ). ****Numbers refer to brine saturation at %wt NaC1. *'**Arabian Light crude oil.

Alkhal]i) were cleaned using CO2 and touluene in a CO2 core cleaner. Berea cores were not treated prior to the displacement runs. The cores were dried in an oven at 60°C for 24 h. Note that every care was taken to preserve the original mineralogical structure of the cores. The cores were then vacuumed for 48 h and saturated with brine (5wt% NaC1). Two sets of cores, comprising of one of each type of cores, were used. Each set was treated with a different additive. Table 4 shows the sequence of displacement runs carried out on each core. The cores were labelled B43 and B44 for Berea samples; K43 and K44 for Alkhafgi samples; and A43 and A44 for Aramco samples. Cores labelled 43 were treated with iso-propanol and

RELATIVEPERMEABILITYRESTORATIONUSINGPRIMARYALCOHOLS

those labelled 44 with n-hexanol. During the displacement runs, the pressure drop across the cores and the volume, pH and electric resistance of the effluent were measured. After runs 2, 6, and 7, the cores were mounted clown the holder and their elasticity was measured using resistive electric strain gauges and a Wheatstone bridge. The capillary pressure-saturation relationship also was determined using the centrifugal method. The basic treatment with additives was as follows: after run 6 and the associated elasticity and capillary pressure measurements, each core was mounted again on the core holder and five pore volumes of the additives to be used for the core were pumped through the core, then the core was aged in the additive for 30 clays before displacing again with the additive. Whereas aging and displacing with additive, the following properties were carefully mea-

75

sured: ( 1 ) the electric resistance of the cores, and (2) the pH, resistance, and surface tension of the effluent and additive. Immediately following the treatment procedure the cores were displaced with oil with the refractive index of the effluent measured intermittently. The oil injection was stopped when no further change in the refractive index of the effluent was observed. The core was then displaced with brine. After that, it was taken out of the core holder and its elasticity and capillary pressure were determined. In the last step of the treatment, the core was displaced with oil and brine saturation was reduced to the irreducible saturation value. The displacement equipment is composed of three major parts: a constant rate non-pulsating pump, an oven assembly, and a control panel (see Fig. 1 ). Other minor components

O•L

1,

Fig. 1. Schematic diagram of experimental apparatus. 1. Jefri pump drive 13. Upstream Brine pressure gauge 2. Jefri pump brine reservoir and piston 14. Pressure transducer 3. Jefri pump oil reservoir and piston 15. Backpressure regulator 4. Brine reservoir 16. Oil filter 5. Oil reservoir 17. Core holder 6. Floating piston cylinders 18. Heating coils 7. Brine filter 19. Overburden pressure gauge 8. Pressure control system 20. Gas balance cylinder 9. Nitrogen cylinder 21. Backpressure gauge 10. Oil pressure gauge 22. Backpressure regulator multiplier 11. Brine pressure gauge 23. Hand pump 12. Upstream oil pressure gauge 24. Water supply

76

M.M. EL-GASSIER ET AL.

were a chart recorder, a hand pump, and two fluid reservoirs.

.....

Fresh

*

Care

Domoged

...... *

*

Core

R

Treeted

2

DP

Core with

=

1

=

3

lsoproponol

Results and discussion lo

Figures 2, 3, and 4 show the relative permeability curves for cores B43, K43, and A43. Three relative permeability curves are shown in each figure. The relative permeability of the fresh core is indicated by the continuous line, whereas that of the damaged core by the broken line and the iso-propanol-treated core by stars. Figures 5, 6, and 7 show the relative permeability curves for cores B44, K44, and A44 which were treated with n-hexanol. The capillary pressure curves are presented in Figs. 8 and 9. When cores are subjected to formation damage they undergo changes in their porosity characteristics as well as pore topology. These changes are reflected in the relative permeability curves in the form of an increase in the oil [

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

.

I

J i

F,~sh

i i

Core

Eamaged •

*

re

R Core

Treated

2

~)P with

=

1 5

Isopropanol

i:

k .

r

\

\i

'

0 [?

04 ,4r;r e

06 Sotur

08,

~ Q

at;on

Fig. 2. Relative permeability curves of Berea Sandstone ( B43 ) before and after damage produced by fresh water, and after treatment with iso-propanol.

q

0.8

K ro

~,, E

~'o.4

\

Y

.\ t

b N,

0 2

O0

0.2

04 ,~. rir, e

0.6

0.8

! 0

<;~lt ur<~f o n

Fig. 3. Relative permeability curves of Alkhafji Sandstone (K43) before and after damage produced by fresh water, and after treatment with iso-propanol.

residual saturation, and a drop in the relative permeability to oil curve. This drop varied from one type of core to the other. This variation in the extent of damage may be attributed to the differences in the amount of swelling and detachable clay as well as the amount and nature of exchangeable ions in the cores. Some types of clay crystals are not dehydratable such as kaolinite. Other types of clay show varying swelling tendencies (increasing from chlorite to illite to smectite ) and this is one of the reasons that the Alkhat]i cores showed less damage when subjected to displacements with fresh water. Inasmuch as the pore surface is negatively charged (Sposito, 1984), the cations occupying the inner part of the double layer promote the adsorbtion of anions by the solid surface. The outcome is that the surface accommodating adsorbed ions will possess a certain negative charge density and, therefore, possesses a cation exchange capacity in dynamic equilibrium with the interstitial brine.

RELATIVEPERMEABILITYRESTORATIONUSINGPRIMARYALCOHOLS

-

-

77

2

Fresh Core

R

=

-

I

DP=3

-- -- - O o m o g e d C o r e ~ - ~ , - ~ CormTl*oot~l with IiIoproponol

--

-

2 R DP

Fresh Core --

- DornoQed Core

*

*

= =

I 3

Core Treoted with n - h e x o n o l

1.0

1.0

0.8

0.8

Kro ~

K ro

>-

\

.~0.6

~ 0.4

'~'~,

.~ 0.4

/ *

\\\\ 0.2

0.2

o,o

I I

0.0

I I

I T I

'

I ~ I I

,

I

I

0.2

0.4

0.6

Brine

,

0.8

I ( 1

1.0

Soturation

Fig. 4. Relative permeability curves of Aramco Sandstone (A43) before and after damage produced by fresh water, and after treatment with iso-propanol.

--

-

2 R = I

Fresh Core

-- - D o m o g e d Core -~ - ~ Core Treoted with

DP=

3

n-hexonol

1.0

0.8

K ro

>,

0.6 g

•~ 0 . 4

\ '"

K

rw

\\~,

0.2 \\ \

0.0

t j

, , , , , , , , , r l i J l l , , , ,

0.0

0.2

,Jfl,,,

0.4 0.6 Brine Soturotion

0.8

1.0

Fig. 5. Relative permeability curves of Berea Sandstone (B44) before and after damage produced by fresh water, and after treatment with n-hexanol.

Krw ~

0.0 0.0

.... ,,,,,i . 0.2

.

. . . . 0.4 0.6 Brine Soturation

.

i

0.8

1.0

Fig. 6. Relative permeability curves of Alkhat~i Sandstone (K44) before and after damage produced by fresh water, and after treatment with n-hexanol.

In the case of the exchangeable ions being divalent, the flocculated particles will be less mobile due to a higher negative charge density, subjecting the formation to a less permeability drop. This is the other reason for the variation in the extent of formation damage. Organic additives may reduce the surface tension between the phases, but the improvement in relative permeability characteristics (an increase in the relative permeability to oil and a decrease in the oil residual saturation) is attributed to another mechanism. Since the additives used are either partially or completely miscible with water, a gradient in the water concentration will be established between the diffused double layer and the bulk of the flowing additive, and fresh water will be removed from the pores. Inasmuch as the flowing additive dissociates weakly, the cations in the interstitial brine will migrate counter currently towards the pore surface, tending to increase the thickness of the dif-

78

M.M. EL-GASSIER ET AL.

260 - - ~ -~ - *

Fresh

Domoged

-*

Core

R

Core

= 1

with

65

240 -

DP = 5

Cote

Treated

2

V

T

-60 --

n-hexanol

220 -

T

?

200 -

--

.......

Before After

Treatment Treatment

55

o

Alkhafji Core (K43) Bereo Core (B43) × Aramco Core (A43)

•50

180

45

£ 160 0.8

t

140

40~ d

F

d

55B S

a)

£ 120-

>,

i °6

\ \ ',,~ kk

K

50£

2 loo-

rw

>.

IL

25£ 0

5

0.4

80

X \ '*"

20 °

60-

40 1

x~

10

0,2 20 t

\

5

o 0 0

"

O0

~

I , I I [ , ~ I I I ' ] [ I I

0.2

0.4 0.6 Brine Saturation

0.8

t

10

I I , I 1

2C)

3~0

1.0

Fig. 7. Relative permeability curves of Aramco Sandstone (A44) before and after damage produced by fresh water, and after treatment with n-hexanol. fused layer. The net effect of this counter current diffusion is: ( 1 ) the flocculated fines will become more attached to the pore surface, and ( 2 ) a reduction o f the water contained in the expanded crystal lattice o f the swelling clays will result and cause this structure to break and hence induce a substantial decrease in its volume. Iso-propanol was added because o f its complete miscibility in both oil and water. It was assumed that iso-propanol would bring about wettability changes by absorbing the water in the expanded clay crystals and hence causing the extended layer of clay crystals to break and shrink. This did not occur, however, because of the complete miscibility o f iso-propanol with water. Diffusion o f iso-propanol towards the pore surface occurred, which resulted in a decrease in the electric charge o f the diffused layer. N o washing o f water from the clay crystals occurred since no concentration gradient

[

I

I

40 50 60 70 Brine Saturation,

J

l

80

90

o 100

Fig. 8. Capillary pressure versus brine saturation of cores before and after damage producedby fresh water, and after treatment with iso-propanol.

26o

65 L60

240 t

__

._

t

II

180 -

it

"~ 1 6 0 -

J

Before

Treatment

After Treotrnent

o A~khafji Core (K44) * Bereg Core (B44) × Aromco Core (A44)

:-50 4S

1

40~;

If

~4

!40 m 120

I I I

i,

b

100 80 -

L55

t

O-f----~ .... j 10 20 50

I/

r2o °

I\

T. . . . . T T~ ~ 40 50 60 70 Brine Saturation,

, 80

] 90

I 0 ! 00

Fig. 9. Capillary pressure versus brine saturation of cores before and after damage producedby fresh water, and after treatment with n-hexanol.

79

RELATIVE PERMEABILITY RESTORATION USING PRIMARY ALCOHOLS

was established. The slight improvement in the relative permeability curves (Figs. 2-4 ) could be attributed to the substantial decrease in the surface tension between the flowing phases as inferred from the considerable change in the capillary pressure curves (Fig. 8 ). The n-hexanol was able to improve the relative permeability curves (Figs. 5-7) by increasing the mobility of both fluids and decreasing the residual saturations. This improvement is attributed to the fact that water is only partially miscible in n-hexanol thus inducing a concentration gradient between the water contained in the diffused layer and the flowing stream of additive. This caused a substantial increase in the flow area by decreasing the volume of swelling clay, which is shown in the capillary pressure curves (Fig. 9 ).

Conclusions Two primary alcohols were used to restore the permeability of damaged sandstone cores. The damage was characterized by a drop in the relative permeability to oil and an increase in the oil residual saturation. The extent of damage varied according to the composition of the cores. Iso-propanol was not effective in reducing the residual oil saturation or increasing the relative permeability to oil of the damaged cores. On the other hand, n-hexanol, which is partially miscible with water, restored some of the damaged relative permeability to oil and reduced the oil residual saturation. This resulted in an increase of oil recovery (6% in some cases).

Acknowledgement We would like to thank King Abdulaziz City for Science and Technology for their financial support without which this work could not have been accomplished.

References Arnold, P.A., 1978. Surface electrolyte interactions. In: D.J. Greenland and M.H.B. Hayes (Editors), The Chemistry of Soil Constituents. Wiley, New York, N.Y., pp. 355-404. Atwood, D.K., 1964. Restoration of permeability to waterdamaged cores. J. Pet. Technol., 16(4): 1405-1409. Baptist, O.C. and Sweeny, S.A., 1955. Effect of clays on the permeability of reservoir sands to various saline waters, Wyoming. U.S. Bur. Mines, R.I. 5180:1 l - 19. Bernard, G.G., 1955. Effect of reactions between interstitial and injected waters on permeability of rocks. Prod. Mort., 20( 12): 26-31. Clementz, D., 1982. Stimulation of water injection wells using sodium hypochlorite and mineral acids. J. Pet. Technol., 34(9): 2087-2096. El-Gassier, M.M., Omar, A.E. and Dahab, A.S., 1987. Effect of high brine concentration and overburden pressure on permeability and resistivity of sandstone cores. J. Egypt. Soc. Eng., 26 (2): 74-81. El-Gassier, M.M., Omar, A.E., Dahab, A.S. and Awad-elKariem, A.A., 1990. Permeability restoration using inorganic additives. J. Pet. Sci. Eng., 4 (3): 235-243. Gray, D.H. and Rex, R.W., 1966. Formation damage in sandstones caused by clay dispersion and migration. Proc. 14th Natl. Conf. Clays and Clay Minerals, pp. 355-366. Gruesbeck, C. and Collins, R.E., 1982. Entrainment and deposition of fine particles in porous media. Soc. Pet. Eng. J., 22(12): 847-856. Johnson, E.F., Bossier, D.P. and Naumann, V.O., 1959. Calculation of relative permeabilities from displacement experiments. Trans. AIME, 216: 370-374. Maly, G.P., 1976. Close attention to the smallest job details vital for minimizing formation damage., Formation Damage Control Syrup. Monaghan, P.H., Salathiel, R.A., Morgan, B.E. and Kaiser, A.D., Jr., 1959. Laboratory studies of formation damage in sands containing clays. Trans. AIME, 216: 209-216. Mungan, N., 1965. Permeability reduction through changes in pH and salinity, J. Pet. Technol., 17 (12): 1449-1453. Omar, A.E. and El-Gassier, M.M., 1984. Effect of salinity on permeability and oil recovery of Saudi fields. King Abdulaziz City of Sci. Technol. Proj. AR-5-028, 1st Progr. Rep. Omar, A.E. and El-Gassier, M.M., 1985. Effect of salinity on permeability and oil recovery of Saudi fields. King Abdulaziz City of Sci. Technol., Proj. AR-5-028, 2rid Rep. Omar, A.E., El-Gassier, M.M., and Dahab, A.S., 1988. Effect of salinity on permeability and oil recovery of Saudi fields. King Abdulaziz City of Sci. Technol., Proj. AR-5-028, Final Rep.

80

Sposito, G., 1981. Thermodynamics of Soil Solutions. Claredon Press, Oxford, pp. 155-186. Sposito, G., 1984. Surface Chemistry of Soils. Ch. 3. Clarendon Press, Oxford.

M.M. EL-GASSIER ET AL,

White, E.J., Baptist, O.C. and Land, C.S., 1960. Susceptibility of petroleum reservoir sands to water damage power river basin, Wyoming. Pap. SPE 514-G, presented at SPE 35th Annu. Meet.