Modelling the CO2 huff'n' puff process in solution-gas drive reservoirs using a black-oil simulator

Journal of Petroleum Science and Engineering, 8 ( 1992 ) 167-179

167

Elsevier Science Publishers B.V., Amsterdam

Modelling the C O 2 Huff'n' Puff process in solution-gas-drive reservoirs using a black-oil simulator B.F. Towler and Y.A. Wagle Department of Petroleum Engineering and The Enhanced Oil RecoveryInstitute, Universityof Wyoming, P.O. Box 3295, Laramie, WY82071, USA (Received November 1, 1991; revised version accepted February 5, 1992 )

ABSTRACT Towler, B.F. and Wagle, Y.A., 1992. Modelling the CO2 Huff 'n' Puff process in solution-gas-drive reservoirs using a black-oil simulator. J. Pet. Sci. Eng., 8: 167-179. The cyclic CO2 stimulation of low-pressure solution-gas-drive wells is investigated using a black-oil simulator. It is concluded that relative-permeability hysteresis and reservoir pressure increase are likely to be significant mechanisms in the success of the process. Relatively dead oils are more likely to respond to the stimulation than gas-rich live oils. A free gas saturation is also shown to be detrimental to the process, because it tends to reduce the relative permeability to oil. Investigations also did not reveal any theoretical reason for holding a back pressure during production.

Introduction

The CO2 huff'n' puffprocess (or cyclic C O 2 stimulation) has been investigated since 1977 (Patton et al., 1982a,b). A large number of field trials have been implemented and reported (Patton et al., 1982a,b; Claridge, 1984; Simpson, 1988; Monger and Coma, 1988; Miller, 1990 ). The investigations have been so far centered on Kentucky, Louisiana, Texas, California and Wyoming, but its use is spreading. The mechanisms that affect the process are not well understood. The mechanisms listed in Table l, however, may be important under different conditions. In order to determine which mechanisms may be important under what conditions, it is necessary to history match field and laboratory tests using a reservoir simulator. At high pressures it is best to Correspondence to: B.F. Towler, Department of Petroleum Engineering and The Enhanced Oil Recovery Institute, University of Wyoming, P.O. Box 3295, Laramie, WY 82071, USA.

use a compositional simulator because the CO2-oil-methane-water phase behavior can become quite complex. Hsu and Brugman (1987) have reported history match results, using a compositional simulator. Denoyelle and Lemonnier (1987) have also attempted history matching using a black-oil simulator and this approach may be valid at low reservoir pressures, where the phase behavior can be simplified. It is the intention of this paper to investigate the parameter sensitivity of the cyclic CO2 injection process in solution-gasdrive reservoirs using a black-oil simulator. TABLEI Cyclic C02 oil recovery mechanisms 1 2 3 4 5 6

Oil viscosity reduction Solution gas drive Oil swelling causing saturation increase Shifts in relative permeability due to hysteresis, changes in water saturation, wettability alteration Hydrocarbon extraction Interfacial tension reduction

0920-4105/92/$05.00 © 1992 Elsevier Science Publishers B.V. All fights reserved.

[ 68

There exists a large number of low-pressure solution-gas reservoirs and Miller (1990) has shown that this process can work well in such reservoirs. Some of the questions that we seek to answer are:(a) What effect will a free gas saturation in the reservoir have on the process?(b) How important is relative-permeability hysteresis at low pressures? (c) Should a back pressure be held on the production wells in order to hold the COz in solution? The black-oil simulator used in the process was written by the principal author and has been described elsewhere (see Towler, 1986,1991 ). The simulator does not allow solubility of CO2 in the water phase, but it is assumed that at low pressures and at low connate water saturations this will not have a large effect. It is also assumed that there is no difference in the CO2 and natural gas solubility in the oil at low pressures. The solubility data of Simon and Graue ( 1965 ) presented in the next section supports this assumption. Watkins (1982) has also used the same assumption in his four-component, miscible-flood simulator and others (see Patton et al., 1982; Hsu and Brugman, 1987 ) did likewise in their black-oil studies of the process.

B.P.TOWLERAND Y.A.WAGLE

These wells and the Kentucky tests were included in a large data base of tests analyzed by Monger-McClure et al. (see Monger and Coma, 1988; Thomas and Monger-McClure, 1991; Monger et al., 1991 ). To model the process, Patton et al. (1982a,b) and Denoyelle and Lemonnier

Solubility of C02 m Oil ( K = 1 2 )

500~ l i

i'

," /'/

/

/ >/.-:

200

10 i - 1

.....

T=IO0

.....

T=150

p,A T = 2 50 0 . . . .P.A^ .

i,1,,-1,=; i'b

ir,T~l~ =r T ~ G q I t I I , i , , , , r r ~ ' rl 650 13i00 1950 2600 Saturotion Pressure, psio

Fig. 1. Solubility of carbon dioxide in oil ( K = t2 ).

Literature review

Swelling Factor

of C02 + Oil ( K = 1 2 )

I

1.35

The first reported investigation of cyclic CO2 stimulation was by Shah et al. (1979), although Gates and Caraway (1971) had reported cyclic stimulation of oil wells using LPG solvents as far back as 1971. Patton et al. ( 1982a,b)investigated the process for a California heavy-oil project at North Bolsa. Miller (1990) presented data on a large number of successful low-volume tests on low-pressure fields in Kentucky. Haskin and Alston ( 1989 ) discussed the results of 28 tests in 12 fields in east and south Texas. They also compared a predictive correlation they developed, with one correlation developed by Patton et al. ( 1982b ). Simpson (1988) discussed results from two wells in the Timbalier Bay fields in Louisiana.

/

/

/

/-

1.30

1.25 8 ~6 1.20

+

~1.15

1.10 1.05

1.00

/

/

/

.

J

...

/y 650 Sdturotion

, ,

"7"L. 1300 Pressure

1950 , psio

2600

Fig. 2. Swelling factor of carbon dioxide in oil (K = 12 ).

CO2 HUFF 'N' PUFF PROCESSIN SOLUTION-GAS-DRIVERESERVOIRSUSINGA BLACK-OILSIMULATOR VISCOSITY OF CARBONATED OIL (K=12) AT 200 F

169

TABLE4

1.6

Parameters used in four independant simulator runs ~1 1.4-

II Logarithmic fit

1.2-

=

.

.

.

Runl

•

Run2

Run3

Run4

2

120

300

299.95

3 14 30 400 100

3 14 14 1014 600

3 14 283 1017 600

3.05 14 283 1008.6 100

1473

2811

2816

2805

X

Initial production (days) Injection (days) Soak period (days) Production (days) Initial pressure (psi) Saturation presssure (psi) Totalgas injected (Mcf)

10"

°o.81 ~o6. 04' >

0.2"

0,0 0

650 SATURATION

13'00 PRESSURE,

19'50

2600

PSIA

Fig. 3. Viscosity o f carbonated oil ( K = 12) at 200°F. GAS-OIL HYSTERESIS CURVE 1 1.0

TABLE 2 Krg

Reservoir grid used in the simulator Total length--x-direction Total length--y-direction Total length --z-direction Number of cells in x-direction (i) Number of cells in y-direction (j) Number of cells in z-direction (k) Cell size---dx, for i = 1...6, 10...15 Cell size---dy, for j = 1...6, 10... 15 Cell size--dz dx, for i = 7,8,9 dy, for j = 7,8,9

Krl

08

880 ft 880 ft 20 ft 15 15 2 50 ft 50 ft 10ft 10ft 10ft

m ~

06

~

O.4

|

0.2

000.0 TABLE 3

~

.

• 012

|

0'4 LIQUID

"

0.6

08

" - -1"0

SATURATION

Fig. 4. Gas-oil hysteresis curve 1. Rock and oil properties Rock properties ~, porosity K, permeability Reservoir temperature Oil properties Watson K-factor API gravity Molecular weight

0.12 20 mD 200 oF 12 33 236

( 1987 ) made use of black-oil-type simulators. The latter used an equation-of-state to generate equilibrium constants to model the pIT/" relationships. They also modified their simulator to include the relative-permeability-capillary-pressure hysteresis approach first intro-

duced by Killough (1976). Patton et al. (1982a,b) also felt the black-oil approach was adequate and used measured solubility data for the particular reservoir they were modeling. They did not allow for hysteresis. Hsu and Brugman (1987) used a compositional simulator which allows a more rigorous investigation of the PI/'T complexities. They also did not allow for hysteresis. The writers feel that the black-oil approach has limitations but may be adequate for lowpressure reservoirs, such as solution-gas-drive reservoirs with low bubble-point pressure. However, hysteresis should be allowed for. We

170

B.F. T O W L E R A N D Y . A . W A G L E

are currently investigating use of a compositional simulator to model the process.

CUMULATIVE

*

C02-oil solubility data

PRODUCTION

OIL

r , { } d u c h o r = F]je~l{Jrl

,+O~F

•

P r o d u c t i o n w d n hysleresPs

x

P r o d u c t i o n w ~ h o e t hysteresJ~

o

ru

2000 -

-

u)

A black-oil simulator requires PVT data on the CO2-oil mixture. These PVT data include the viscosity of CO2 in oil, the swelling (or formation volume) factor and the solubility of

,.J

-

0

1500

i

lOOO-

500 -

DAILY OIL PRODUCTION

(BHP=50)

0 ~0

20

•

Preduct~on w~th hy~teresls a h o r in~ect~on

+

Preduchonwithouthysteresisafter injechon

ii

Base run - w t t h o u l a n y ~n~11on

~

r

uc I ~

r

40

30 TIME,

50

DAYS

Fig. 7. Cumulative oil production ( B H P = 50) in Run 1.

in e c ~on

AVERAGE

RESERVOIR

PRESSURE

lOOO -

-i 10o6

Production with

8O0

hysleresls

N ProdUCtlenwithouthyslereslS Base run - w ~ h o u t s t l m u l a t ~ n ~

Pressure during

injecIiooand s o a k

60O

~

4oo-

0 10

20

30

40

50

DAYS

Fig. 5. Daily oil production ( B H P = 50) in Run 1. o

,

10

~r

,

2o

30 TIME,

DAILY GAS INJECTION

640-

<•560" z o

480 -

" 400-

~ 320w

~

240.

I II

160-"

80. 0

''~T 1

0

[i

~II

I

I lilililiIiIil,lilil11,

5

10 TIME,

DAYS

Fig. 6. Daily gas injection in Run 1.

5r~

Fig. 8. Average reservoir pressure in Run 1.

720

0

,

40

DAYS

ii

15

20

CO2 in oil expressed as a solution-gas/oil ratio (Rs). The most comprehensive set of such data is that by Simon and Graue (1965). They measured the solubility and swelling of CO2 in nine different oils at a broad range of temperatures and pressures, and correlated their data with respect to the Watson (or U O P ) characterization factor (K). Their plots, however, are for mole fractions rather than Rs. Hence, we recalculated and correlated their data as shown in Figs. 1,2 and 3. Figure 1 shows the solubility data for oil with K = 12, at four different temperatures, as solution-CO2/oil ratio, which is a function of saturation pressure. Figure 2

171

CO2 HUFF "N' PUFF PROCESS IN SOLUTION-GAS-DRIVERESERVOIRS USING A BLACK-OIL SIMULATOR

TABLE 5

Effect of free gas volume and gas injected on daily oil production Run

Free gas volume (MCF)

1 2 3 4

Gas volume injected (MCF)

Before injection

After injection

0.0 3848.1 2856.0 71.0

232.6 4539.5 3862.0 421.8

Oil rate (STB/day)

1473.0 2811.0 2816.0 2805.0

Before injection

After injection

71.3 85.8 30.0 8.1

151.7 82.6 41.5 125.4

TABLE 6 AVERAGE RESERVOIR PRESSURE

Free gas saturation around well-bore cell Run

900~

S s before injection

S~ after injection

layer 1

layer 2

layer 1

layer 2

0.0000 0.2689 0.4105 0.1021

0.0000 0.1152 0.1155 0.1012

0.3998 0.3999 0.3998 0.3987

0.3998 0.3999 0.3999 0.3977

800

1 2 3 4

700' ft.

600. 03

5oo. O.

400,

\

1.00

\ \

Gas-oil Hysteresis ..... ~ ~

Krl(inj) Kro'(inj) Kr,'(pro )

\ \ \

/ f /

J /"

200

0.80

hysteresis no hysteresis

: : : : -: =: : ~

300

i

0

i

i

i

~

i

i

i

40

i

,

,

,

i

,

,

i

i

i

i

80 TIME, DAYS

i

i

i

,

t

i

i

120

i

,

i

i

i

160

Fig. 10. Average reservoir pressure in Run 2. E~ 0 . 6 0

0

-6 0.40 t~

0.20

0.00 0.0(

......

~ , , . . . . ~,. . . . , . . . . . . . . . f ......... ,,, 0.20 0.40 0.60 0.80 Uquid saturation, ~.

,',~,g;,

1 .@

Fig. 9. Gas-oil hysteresis curve 2.

shows swelling factors as barrels of CO2-oil mixtures at reservoir temperature and pressure per stock tank barrel of oil with K = 12.

These are the data which are actually used in the simulation, although the solubility and swelling factor data for K = 1 l, 11.3, I 1.4, 11.5, 11.6, 12.2 and 12.4 have also been recalculated. All these data are being used to formulate an analytical correlation for solubility and swelling factor, which will be presented in a separate paper. Viscosity of CO2-oil mixture for oil with K = 12.0 as a function of saturation pressure is presented in Fig. 3. Viscosity and formation volume factor for pure CO2 at 200°F as a function of pressure were determined from standard correlations and are not shown here.

172

B.F TOWLER AND Y.A. WAGLE

DALLY

OIL

PRODUCTION

GAS/OIL RATIO

400

B

300 XX

hysteresis

.....

,,-,,

Sl

6

o r',, O

*

I~ufmg

#-

Producll~ afl6t tlllmulall~ w*th t~yst~e~e,

4

200-

E n

• 0

_-J o

a~l ~ak

ProduCllOn alter

~

Iltlmulall~

hysteresis

~lhlXII

~ ,'

I11

~

loo-

o ,

.

,

.

,

?0

.

,

40

.

eo

,

.

,

.

;::

80 100 TIME, DAYS

120

::=

,

.

_

t4o

Fig. 13. Gas-oil ratio in Run 2. 0

0

i,

I

i

i

i

i

i

i

i

i

i

,

i

40

i

i

i

i

i

i

i

80

i

i F ~ r r r [

120

i

i

i

160

TIME, DAYS

9o0

Fig. 11. Daily oil production in Run 2.

AVERAGE

RESERVOIR

PRESSURE

800 CUMULATIVE

OIL

PRODUCTION

700 11

30000-

600 i

25000-

20000

500

"~-.

"~...

400

-

_J

~ 15000 m 10000 100

--i

i

I

I

I

50

5000i

/

.....

no hysteresis

i i , l l l l l l l l l l l

i i i i i i i i l l , l l l l l

40

80 ]]ME,

120

I

I

1

~

100

]

-

~

T

150 IIM~, DA'G

I

I

I

200

I

l

I

I

250

300

Fig. 14. Average reservoir pressure in Run 2 (300 days).

/ 0 "

I

I

160

DAYS

Fig. 12. Cumulative oil production in Run 2.

Simon and Graue's data are widely used and accepted (see MuUiken and Sandier, 1980; Patton et al., 1982a,b; Monger, 1987; Chung et al., 1988; Haskin and Alston, 1989) but other measurements also appear in the literature. Some early work on five crudes by Welker and Dunlop (1963) measured the solubility,

swelling and viscosity of CO2-saturated oils and showed the large viscosity reduction that can occur for heavy crudes. They also showed that CO2 could reduce the viscosity much more effectively than methane. More recent data have also been obtained by Chung et al. ( 1988 ) and Mara et al. (1988). Monger (1987) has measured CO2-0il properties in the presence of contaminants such as CH4, SO2, N 2 and H2S. Mulliken and Sandier (1980) showed how to calculate CO2-oil mixture properties using an

leo

CO2 HUFF 'N' PUFF PROCESSIN SOLUTION-GAS-DRIVERESERVOIRSUSINGA BLACK-OILSIMULATOR

173

DNLY OIL PRODUCTION GAS/OIL

400

RATIO (WITH

HYSTERESIS)

300'

~2 = a o

~ 200

o

o

I Produchon after stimulation ]

o P,

productionbefore stDmulatlonI

~' J'--'--~

":

m

~

;

)

100

Injection and soak J 50 ,

,

,

,

i

,

,

,

i

50

0

i

,

r-,-,

1O0

i

,

,

,

,

i

,

m

,

,

150 200 TIME, DAYS

i

,

,

,

1O0 '

250

- - - -

150 '

2O0 '

25O '

3O0

TIME, DAYS

,

300

Fig. 17. Gas-oil ratio in Run 2 (300 days).

Fig. 15. Daily oil production in Run 2 (300 days). DALLY GAS INJECTION 1100'

1000 CUMULATIVE OIL PRODUCTION

40000

900

800" '" 700

~ 30000

600 §5ooi

w

Q 0 rv. 13_ ...J

400i

5 20000

m.

o

300

2OO tO0

10000

TIME , DAYS 0

p

I

i

i

i

riO

i

i

i

i

i

i

1DO

i

i

i

i

i

i

i

i

i

150 200 TIME, DAYS

i

i

i

,

i

~

250

i

i

i

300

3--~-,-~--~-~- I-,305

Fig. 18. Daily gas injection in Run 3.

Fig. 16. Cumulative oil production in Run 2 (300 days).

Model description

equation-of-state. They compared their results with the Simon and Graue data. A similar approach was followed by Grigg and Lingane (1983) who compared their results with experimental results of their own. These data will be compared with Simon and Graue's data and our own correlations in a separate paper.

The reservoir model studied here is described by a 15 × 15 × 2 rectangular grid pattern in three dimensions. It is 880 ft in the xdirection, 880 ft in the y-direction and 20 ft in the z-direction. A finer grid is used around the wellbore cell using three rows of cells in the xand y-directions of smaller dimensions. The

174

B.r. 1-OWLER AND Y.A. WAGLE

9oo

Results and discussion

AVERAGE RESERVOIR PRESSURE

800 ----::: BHP = 50 ==:==BHP = 100 -'::;; BHP = 1 5 0 ;;::: BHP = 200 -~~ ; ~ ; PRODUCTION

700-~ 6 0 0 .qt

500

iii1 TIME,

DAYS

Fig. 19. Averagereservoir pressure in Run 3.

DAILY OIL PRODUCTION

400

350 2 :=::: BHP = 5 0 ===== BHP = 100 ::~BHP = 150 : ~ : : : BHP = 200 : : ~ PRODUC~ON

300-

D

250.

0

200" 0

1500

~100.

50"

0 0

100

200

300 400 TIME , DAYS

500

600

Fig. 20. Daily oil production in Run 3.

complete details of the grid are presented in Table 2. The basic oil and rock properties are shown in Table 3. The oil used in this paper had a Watson K factor of 12. The other properties o f this oil are presented in Table 3.

The simulator was run using different initial pressures, saturation pressures and relativepermeability hysteresis. No-flow boundary conditions are used which are standard in black-oil simulators. The well rates in all the runs were pressure controlled by presetting bottomhole pressure. Bottomhole pressure for production varies between 50 and 200 psi, whereas for injection it is 1000 psi. The irreducible water saturation for all the runs was 15%. Four of these runs are significant and are discussed here. The baseline runs are added for Run 1 (Figs. 5,7 and 8 ) and Run 4 (Figs. 27,28 and 29 ) only because these two runs were done with different hysteresis curves. It is evident from the plots of these runs that the oil is incremental. The parameters used for these runs are presented in Table 4. For Run 1, the liquid-gas relative-permeability curves used are shown in Fig. 4, which also shows the extent of hysteresis used. This hysteresis is not only a function of the particular fluids used, but also the injection and production rates and the coarseness of the grid. In effect, they are psuedo-curves. The curves on the left are used for the production phase, whereas those on the right are used for the injection phase. Plots of gas-oil ratio, daily oil production, cumulative oil production, cumulative gas injection and average reservoir pressure are m a d e and are shown in Figs. 5-8. These figures also show the effect of hysteresis and reservoir pressure increase on the response of the well. Inasmuch as the initial saturation pressure is 100 psi, there is not much dissolved gas, and the free gas saturation in the reservoir is small, as shown in Tables 5 and 6. The response of the well to CO2 stimulation is quite good as can be seen from the daily oil production rates before and after injection in Table 5. Run 2 is done with different relative permeability curves, which are shown in Fig. 9. This large hysteresis shift was used to test the sen-

CO2 H U F F 'N' PUFF PROCESS IN SOLUTION-GAS-DRIVE RESERVOIRS USING A BLACK-OIL SIMULATOR

GAS/OIL

175

RATIO

4 .J

5 UL

0 ¢o Production before stimulation

3'

P,

Injection and soak

I,U

(J =)

1:2 0 ha. U) ,<

2'

f3

-

BHP=200

;

BHP=150

-

BH P=100 BHP--50

[L

0 tL

(J :!

1

0

I

1 00

!

i

200

300 TIME,

400

i

500

600

DAYS

Fig. 21. Gas-oil ratio in Run 3. sitivity of 'huff'n puff' response to hysteresis. The parameters used in this run are given in Table 4. The higher saturation pressure indicates that a higher amount of gas is dissolved in the oil initially. Figures 10-13 show the response of the well before and after CO2 stimulation. Referring to the daily oil production plot in Fig. I 1, it can be deduced that the well did not respond satisfactorily although hysteresis does have an effect on production. Table 5 shows a higher free-gas volume and decrease in the daily oil-production rate after injection. The run is extended to 300 days and the results are shown in Figs. 14-17. Run 3 is similar to Run 2 (which has a high saturation pressure of 600 psi), but has a larger initial production time. The other parameters

are shown in Table 4. The long production phase before injection causes a high gas saturation around the wellbore. The gas injection following this seems to have a smaller effect on the overall reservoir pressure. This is probably due to high compressibility of the gas. Figures 18-22 show the response of the well. The 'no hysteresis' case was not examined in this run. Four different back pressures were used during production, to see the effect of back pressure on production. The plots show that back pressure does not increase the production. The daily oil production rate after stimulation is almost the same as that before injection and the free gas volume is high as shown in Table 6. Also, the gas-oil ratio is very high after the soak before settling down. The writers deduce

176

B.F. TOWLER AND Y.A, WAGLE

CUMMULATIVE OIL PRODUCTION

DALLY OIL PRODUCTION

40000

300-

35000 ::::: BHP = 50 ""-~'BHP = 100 :~: BHP = 150 = ¢ = : : BHP = 2 0 0 :::=: PRODUCTION

250

30000. o 200. 25000. o 20000

150o

m 15000 100"

•-'-'-~BHP = 50 ====: B H P = 100 •~'~-'BHP = 150 ::::: BHP = 200 ,,,,, PRODUCTION

10000.

5000

0

'

0

'

'

'

I

'

100

,

u

i

I

200

u

,

,

,

I

i

,

,

300

,

,

,

u

400

,

I

'

'

500

m

50"

'

0

'

600

0 ....

l O'O . . . .

2 0'0 ' "

TIME , DAYS

~

"

~6o' ' ~ ~6o'

"

,'l 600

TIME, DAYS

Fig. 22. Cumulative oil production in Run 3.

Fig. 24. Daily oil production in Run 4.

CUMULATIVE OIL PRODUCTION

AVERAGE RESERVOIR PRESSURE

16000 I000 I :::=: BHP = 50 ===== BHP = 1 0 0 =:::~ B H P = 1 5 0

::::: BHP = 50 ===== BHP = 100 :::~= B H P = 150

800~

::::: BHP

::~:;

=

200

::::: :::~

=

200

PRODUC~ON

600:

0

o ~

BHP

PRODUCTION

a 12000 w o D

8000

4.00

4000 200

0

'"

'16o' "

~6o' ' ' ~ " :4~o' " TIME, DAYS

:~6o' ' ' ~oo

i i i 1 1 1 1 1 1 1 1 1 ~ 1 1 1 1 1 1 } 1 1 1 , 1 1 1 1 1

100

200

300 400 TIME, DAYS

500

600

Fig. 23. Average reservoir pressure in Run 4.

Fig. 25. Cumulative oil production in Run 4.

that the high gas saturation in the reservoir is a hindrance to the process. Run 4 is similar to Run 3, except a low saturation pressure of 100 psi was used. Hence, free-gas saturation in the reservoir after initial production is far less than in Run 3. This is tabulated in Table 6. Other parameters are the

same, as shown in Table 4. The response of the well is plotted in Figs. 23-26 for four different back pressures. (See also Figs. 27, 28 and 29. ) The well responds favorably by producing at a higher rate after injection than before, as shown in Table 5. The plots of gas-oil ratio (which remains lower) and reservoir pressure

CO2 HUFF 'N' PUFF PROCESS IN SOLUTION-GAS-DRIVE RESERVOIRS USING A BLACK-OIL SIMULATOR

GAS/OIL

17 7

RATIO

.,I

5 M,.

O m

a uJ t,j :) a O no.

<¢ O M.

O

a

Production before 'huff

•

Injection and soak

o

BHP=200

•

BHP=150

M

BHP=100

o

BHP=50

M.

o

0

m

0

i

i

100

200

r--

300 TIME,

I

I

400

500

600

DAYS

Fig. 26. Gas-oil ratio in Run 4.

CUMULATIVE

i

OIL

PRODUCTION

AVERAGE RESERVOIR PRESSURE (BHP=50)

(BHP=50)

1200O.

i o. "

100~.

6OOO.

4000.

r-

.....

P?inwlh°ui'ui°n

0

100

200

300

400

500

600

700

TIME, DAYS

~oo~ O'

-

i

100

•

I

200

-

i

•

300

I

400

•

I

-

500

i

-

600

TIME, DAYS

Fig. 27. Cumulative oil production (BHP= 50).

Fig. 28. Average reservoir pressure (BHP = 50).

(which is higher) substantiate this claim. Also it can be seen that the back pressure again does not help the production. In this run the reservoir pressure responds m o r e dramatically to

injection and this is due to the lower compressibility o f the reservoir fluid and the smaller free-gas volume.

178

f3.F. T O W L E R A N D Y.A. WAGLE DAILY OIL PRODUCTION (BHP=50)

Production

i~1 2oo

altar shmulatlonl

.J

°

v

0

1 oo

20o

300

4o0

500

600

TIME, DAYS

Fig. 29. Daily oil production (BHP = 50).

Conclusions The conclusions can be summarized as follows: ( 1 ) The black-oil simulator indicates that the CO2 huff 'n' puff process can work well in low-pressure reservoirs as long as the amount of free gas is small. (2) Hysteresis in the relative-permeability curves and increase in the reservoir pressure appear to be significant mechanisms for the process at low pressures. ( 3 ) There does not appear to be any theoretical reason for holding a back pressure during the production phase. Acknowledgements

Support for this project was provided by the Enhanced Oil Recovery Institute of the University of Wyoming and by ACS Petroleum Research Fund Grant Number 2385 l-G2. References Chung, F.T.H., Jones, R.A. and Nguyen, H.T., 1988. Measurements and correlations of the physical properties of CO2/heavy-crude oil mixtures. SPERE, 3: 822-828. Claridge, E.L., 1984. The CO2 huffand puffprocess. Presented at the Enhanced Recovery Week, EOR Using CO2 Symp., Houston, Tex., 10 pp. Denoyelle, L.C. and Lemonnier, P., 1987. Simulation of CO2 huff'n'puffusing relative permeability hysteresis.

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CO2HUFF'N' PUFFPROCESSIN SOLUTION-GAS-DRIVERESERVOIRSUSINGA BLACK-OILSIMULATOR

prepared by Lawrence-Allison and Assoc. Corp., U.S. D O E under contract EF-77-6-03-1582. Simon, R. and Grauc, D.J., 1965. Generalized correlations for predicting solubilityswelling and viscosity behavior of CO2-crude oil systems. J. Pet. Tcchnol., 13: I02-I06. Simpson, M.R., 1988. The CO2 huff'n'puffprocess in a bottomwatcr drive reservoir.J. Pet.Tcchnol.,40: 887893. Thomas, G.A. and Monger-McClure, T.G., 1991. Feasibility of cyclic CO2 injection for light-oil recovery. SPERE, 6: 179-184.

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Towler, B.F., 1986. Reservoir simulation in Mereenie field. Aust. Pet. Explor. Assoc. J., 26: 428-446. Towler, B.F., 1991. Simulation of Slattery South field, a Minnelusa 'A' reservoir. SPE 21816, presented at Rocky Mountain Reg. Meet. and Low-permeability Reservoirs Symp., Denver, Colo., 16 pp. Watkins, R.W., 1982. The development and testing of a sequential semi-implicit four component reservoir simulator. SPE 10513, presented at Sixth SPE Symp. on Reservoir Simulation, New Orleans, La., 21 pp. Welker, J.R. and Dunlop, D.D., 1963. Physical properties of carbonated oils. J. Pet. Technol., 15: 873-876.