UTCHEM Chtterau Example

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Society

of

PetroleumEngineers

SPE 24931

Simulation of a Successful Polymer Flood in the Chateaurenard Field

Sunao Takaqi, G.A. Pope* and Kamy Sepehrnoori,*

U.

of Texas; A.G. Putz,* Elf Aquitaine;

and Hichem BenDakhlia,*

U

of Texas

SPE Members

Copyright 1992 , Society of Petroleu m Engineers Inc.

This pape r was prepared for p resentation at the 67th Annual Techn ical Conferenc e and Exh ibition of the Society of Petroleum Engineers held in Washington,

DC

October 4-7, 1992.

This paper was selecte d for pres entation by an SP E Program Comm ittee following review of information containe d in an abstract submitted by the author@ ). Contents

of

the paper,

as prese nted, have not been reviewed by the Society of Petroleum Enginee rs and are subject to correction by the author(@ . The mater ial, as presente d, does not necessarily reflect

any position of the Society of P etmleum Enginee rs, its officers, or me mbe rs. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society

of Petmleum Engineers. Permission o copy is restricted to an abstract of not more than 3 00 word . Illustrations may not be copied. The abs tract should contain conspicuous acknowledgment

of where and by whom the paper is presented. Write Librarian, SPE, P.O. Box

833836

ichardson.

TX

750834 836 U.S.A. Telex, 730989 SPEDAL.

BSTR CT

Early results of a successful polymer project started in

1985 in the Courtenay sand of the Chateaurenard field located

south of Paris, France, were presented at the fall 1988 SPE

meeting. We update these data and show that subsequent

performance has confirmed the highly favorable oil recovery

behavior of this project. The objective of this paper is

to

report

the results of a detailed compositional simulation study

conducted to understand this favorable result. Both alternative

reservoir and process characteristics were investigated in these

three-dimensional simulations. n particular, both a classical

layered reservoir description and a geostatistical reservoir

description were investigated. The latter represents a new

approach to the interpretation of polymer flooding and played an

important role in our study since the attenuation of reservoir

heterogeneities is known to be an important attribute of polymer

flooding. We also evaluated the importance of permeability

reduction and adsorption of the polymer on process performance.

After obtaining a good match of the production of oil, water and

polymer, we then investigated the importance of design factors

on the oil recovery performance. The actual polymer flood

consisted of injecting a large polymer slug followed by five

smaller slugs of decreasing polymer concentration

to

decrease the

time that a study of this type with an accurate compositional

simulator has been reported for polymer flooding. The

combition of better reservoir characterization methodology and

accurate process simulation of polymer flooding should aid in the

successful exploitation of this technology in the future.

This

project clearly shows the high potential of polymer flooding

under the appropriate reservoir conditions and with good design

and implementation methods.

INTRODU TION

polymer flood pilot test1 in the Courtenay sand of

the Chateaurenard field was started in 1985. This pilot test is

characterized by high oil recovery

1.5

bbl oil per lbm polymer)

and high retention of polymer in the reservoir. The performance

of this pilot was simulated using a compositional chemical

simulator called UTCHEM developed at The University of

exa as Actual field

data

and available physical property data

were used as much as possible to evaluate simulation input

parameters. UTCHEM is a three-dimensional, compositional,

multicomponent, multiphase, finite-difference simulator.

third-order correct in space finite-difference method3 with a flux

lirnitefi is used to approximate the partial differential equations.


2/16

2

SIMUL TION OF SUCCESSFUL POLYMER FLOOD INT HE CH TE UREN RD FIELD

SPE

24931

Geology and Reservoir Characteristics

The Chateaurenard field is located 100 km south of

Paris, France, and is divided into three main structures: Saint-

Firmin, Chuelles, and Courtenay. There have been several

polymer and microemulsion pilots and a commercial-scale

polymer flood conducted by Elf Aquitaine in the Chateaurenard

field.lv6-l2

Elf Aquitaine started a polymer pilot in the Courtenay

reservoir sand of the Chateaurenard field on October 1, 1985.

The sand was deposited on an already pre-existing structure of

channels and basins, which explains rapid pay thickness changes

even though the top of the formation is essentially flat.

Vertically this structure consists of three unconsolidated sand

layers. The lower layer is the polymer flood pilot target. The

reservoir thickness varies between 0 and 7 meters with an average

of 3.2 m. The structure of the Courtenay is a monocline with a

low dip of 2 to the northwest. In the southeast direction, the

structure is terminated by fingered stratigraphic traps with the

reservoir becoming increasingly shaly. In the northwest

direction, the oil zone is limited by a very large aquifer. This

reservoir is an unconsolidated sand with a small percentage of

clay (2 to 15 ), mainly composed of kaolinite. The porosity

is nearly uniform and about 30 . The field permeability varies

from 800 to 3,000 md and the mean value is estimated to be

1,600 md in the pilot area.

The original oil in place was 11.7 million m3 (73.6

million bbl) in the Chateaurenard field of which 1.3 million m3

(8.2 million bbl) is in the Courtenay sand. The pore volume and

original oil in place inside the five-spot used in the Courtenay

polymer pilot were estimated to be 44,444 m3 (280,000 bbl) and

27,555 m3 (173,000 bbl), respectively. A summary of original

oil in place and pore volume of each area is given in Table 1.

The oil viscosity is 40 cp at 3 0 ' ~ reservoir temperature) and the

oil density is 0.89 (~~'API) .The wells do not produce free gas.

The formation water is fresh with a total dissolved solids content

of about 0.4 glliter. The water viscosity is 0.73 cp at reservoir

temperature.

Production History

The Chateaurenard field was put into production in

1960. By December 1987, the cumulative production was 3.8

million m3 (23.9 million bbl). The total cumulative production

from the Courtenay reservoir was 0.389 million m3 (2.5 million

bbl). Well CY30 had been producing for five years with a total

production of 25,000 m3 (157,000 bbl), and wells CY40, CY41,

and CY42 had been producing for three years with a production

of about 11,000 m3 (69,000 bbl) for each well before the

polymer project.

well (CY543) was drilled for polymer injection in 1984. The

well pattern is shown in Fig. la.

The injected polymer was a partially hydrolyzed

polyacrylamide. The pilot operation consisted of successive

injections of a slug of 1,000 ppm polymer concentration,

followed by a tapered concentration as shown in Table 2. After

the final slug of 200 ppm polymer solution was injected, chase

water was injected. The total volume of polymer solution

injected was 47,200 m3 (297,000 bbl), which is 1.06 times the

pore volume of the five-spot, and the total amount of polymer

injected was 37.3 metric tons (82,300 lbm). The four producing

wells were kept at about the same producing rate and the total

production rate from the wells has been almost the same as the

injection rate.

Pilot Performance

The polymer solution injection started on October 1,

1985, and the injection rate was increased from the level of 50

m3/d (314 BID) until it reached 100 m3/d (629

BID

at the

beginning of 1987 after which it was kept nearly constant. Both

injection and production volumes in this paper refer to standard

conditions.

A distinctive characteristic of the injection well was that

the wellhead pressure of 18 bars (260 psia), which corresponds to

about 1,100 psia bottomhole pressure, did not increase even

when the injection rate increased or when the injection viscosity

was suddenly increased. This indicates that the injector was

operating above the parting pressure of the sand at least part of

the time. The very good injectivity of polymer is one of the

most favorable characteristics of this successful polymer pilot.

Putz

et

a1.l reported that 18,300 m3 (115,000 bbl) of

oil were produced from the Courtenay sand reservoir by 1987.

The average field oil cut was then 16.6 , with 38 for the

polymer pilot and 11 for the other wells. By June 1989, the

cumulative oil production from the pilot was 26,013 m3

(164,000 bbl), (about 94 of the initial oil in place inside the

five-spot; see Table 1) and the produced polymer was only 0.3

tons. Corlay t a1.13 estimated that the additional oil recovered

in the polymer pilot was 19,000 m3 (120,000 bbl), which is

about 1.5 bbl oil per Ibm of polymer, a very favorable result.

Figure 2 shows the total oil production rate from the

four producers in the pilot area after starting the polymer

injection. After the start of polymer injection, the oil cut of the

producing wells remained unchanged for 250 days, after which

two wells encountered a sharp increase in oil cut. For well

CY30, the oil cut increased from 18 to a maximum of 61 at

500 days (Fig. 3). For well CY42, the oil cut increased from

19 to a maximum of 50 at 450 days (Fig. 4). Well CY41

experienced the arrival of the oil bank a little later, with an oil

cut increase from 12 to 37 (Fig. 5). Only a weak response


3/16

SPE 24931

S.TAKAGI H. BENDAKHLIA G.A. POPE,A. PUTZ

ND K.

SEPEHKNOORI

3

arrival of tertiary oil banks in five wells and a high concentration

of polymer in one well have been observed.

S I M U L A T I O N

A complete description of the simulation input as well

as the polymer models used for each polymer property are given

in ~ a k a ~ i . l ~summary of the most important simulation

input parameters is given below.

Stat is t ical ly Dis tributed Permeabil i ty Field

Heterogeneous permeability fields were generated by the

method of moving averages or Matrix Decomposition Method

(MDM) using a spherical variogram and a log-normal

permeability distribution.15*16 A common measure of

permeability variation is the Dykstra-Parsons coefficient (VD~).

If the permeability distribution is log-normal, the Dykstra-

Parsons coefficient is described as

where k50 is the median permeability, kg4.l is the permeability

one standard deviation below k50 on a log-permeability plot, and

o nk is the standard deviation of log permeability.

A correlation length scale, h is the parameter used to

express spatial correlation. The degree of correlation between the

permeabilities at two points decreases as the distance between

them increases. The correlation length scale was normalized by

the length of the side of the simulated area (500 m or 1,640.5 ft).

For the base case, I 1,549 md, V D ~ 0.221, ~ D X

h ~ y1.0, and DZ 0.33. These parameters represent

relatively low permeability variations, a strong correlation in the

horizontal direction, and a low correlation in the vertical

direction. A verticaVhorizonta1 permeability ratio (kv /k~)f 1.0

was used throughout this study. The permeability field generated

by MDM for the 15x15~3rid is shown in Figs. 7 through 9.

Unfortunately, these parameters had to be inferred from history

matching rather than from core data or other measured reservoir

data since these were not available on this sand.

Injection Rate

The four producing wells were constrained by a constant

pressure of 100 psia, the same pressure as the initial reservoir

pressure. The total injection volume of this pilot was about 6

more than the total production volume from the four wells, so

the injection rate was made the same rate as the total producing

rate (Table

3 .

As a result, the total volume of polymer

solution injected was 44,524 m3 (280,000 bbl), which was

paper by Putz t a1.l with the calculated viscosity is shown in

Fig. 10. The parameters that determine the effect of shear rate on

polymer viscosity were obtained from data on partially

hydrolyzed polyacrylamide.17 The polymer viscosity at the

injected polymer concentration of 1000 ppm and 90 s-l is about

20 cp. This gives a mobility ratio between the initial polymer

slug and the oil bank of about 0.4.

For modeling the polymer adsorption in the simulator,

the salinity dependency was neglected since the salinity in the

reservoir is essentially constant. The adsorption isotherm for

both the base case and the final simulation are shown in

Fig. 11.

The permeability reduction was reported by Putz l a1.l

as 1.3. However, in order to simulate the high oil cut of the

producing wells, higher permeability reduction Rk than this

value had to be used. Figure 12 shows the calculated Rk as a

function of polymer concentration and permeability for the two

assumed cases that we simulated. In the final simulation, the

maximum gridblock permeability reduction was 9.182. The

reason why higher values are needed to match the field behavior

of this pilot is not known. Low values of permeability on a

small scale is one possible explanation for these higher values.

A value of 0.15 was used for inaccessible pore volume

in all simulation runs. Longitudinal and transverse dispersivities

were 1.0 and 0.0 ft, respectively.

The oil relative permeability was based on the data by

Putz

t

a1.l However, the water relative permeability was

modified by changing the endpoint relative permeability to water

and the residual oil saturation. The original values were 5.8

and 27 , respectively, and the modified values were both 20 .

Recent experimental research18 has revealed the fact that the

residual oil saturation to polymer (Sorp) in heterogeneous cores

is often about 6 lower than that to water (So,,) even when the

capillary number for each coreflood is kept precisely the same.

This is consistent with the residual oil saturation to polymer of

20 being lower than that to water of 27 needed to match this

field pilot data. We consider this to be one of the most

interesting and significant observations about this pilot study.

When large amounts of highly viscous polymer are injected into

heterogeneous rock containing oil above residual oil saturation,

both laboratory and field data support the conclusion that the

residual oil saturation in the swept zone will be lower to

polymer than to water, so polymer flooding has the potential in

some favorable circumstances of not only improving sweep

efficiency and accelerating oil recovery, but also of reducing the

ultimate oil saturation locally.

For the simulated area of 1,640.5 ft x 1,640.5 ft shown

in Fig. lb, a 15 x 15 grid with AX AY 109.367 ft was used.

For the three vertical layers used for the base case, A was equal

to 3.60858 ft. For the final match to the field data, variable


4/16

SIMULATION OF A SUCCESSFUL

OLYMERFLOO N

THE

CH TE UREN RD

FELD

SPE 24931

oil in place inside the five-spot was produced. The slope of the

recovery w e ecame steeper aftcr 500 days because the oil bank

formed by the polymer started to break through to the producing

wells. To determine the effect of mesh refinement on the base

case, one run with a 25 25 3 areal mesh refinement was

made. The effect of this mesh refinement on the oil recovery

efficiency is shown in Fig. 13. The areal mesh refinement

resulted

in

a change of only 2.3 in the oil recovery. A vertical

mesh refinement was done for the final field simulation shown

later and resulted

in

even less change in oil recovery.

Sensitivity of Oil Recovery to Adsorption

The adsorption isotherm with one-half the maximum

adsorption plateau of the base case (Fig. 11) was used for

comparison with the base case. As shown in Fig. 14, the oil

recovery for this Run PF2 increased 9 . The adsorption of

polymer in mass units was 105 pglg. This level of adsorption

resulted in 83.3 retention of the injected polymer for Run PF2,

while for the base case Run PFO, with an adsorption of 118

pgjg, 93.7 of injected polymer was retained. These retention

values are based upon the pore volume inside the five-spot

pattern. The actual local adsorption in any given gridblock

varies but is lower. The lower adsorption of Run PF2 resulted

in higher simulated polymer concentrations and earlier polymer

breakthrough times as would be expected. Detailed analysis of

s

nd other results can be found

in

Takagi's thesis.14

Sensitivity of Oil Recovery to Permeability

Reduction

The permeability reduction of the polymer was reduced

from the base values as shown in Fig. 12. A comparison of the

oil recovery for this Run PF3 with that of Run PFO is shown in

Fig. 15. The oil recovery is about 9 less than that of Run

PFO. Each well had a higher simulated polymer concentration.

The maximum permeability reduction in any gridblock was 10.8

for the base case but only 3.0 for Run PM. As expected, lower

permeability reduction resulted in lower oil cut and lower oil

recovery.

Sensitivity of Oil Recovery to the Dykstra-Parsons

Coefficient V D ~ )

A

VDP value of 0.5695 was used for the case of higher

heterogeneity (Run PF4)

th n

the base case (Run PFO; V D ~

0.221). A comparison of the cumulative oil recovery for Run

PF4 with that for Run PFO is shown in Fig. 16. The oil

recovery for Run PF4 is about 3 more than that for Run PFO.

This result indicates that the higher heterogeneity (VD~)han the

base case causes higher oil recovery, which was not expected.

Recall that the vertical and horizontal permeabilities are equal,

which is favorable for crossflow. The gravity number Ng)or

regions free of polymer is about 0.006 based upon an aqueous

viscosity of 0.73 and for regions with 1000 ppm of polymer is

about 0.0003 based upon 20 cp aqueous viscosity. The effective

This would not happen in most cases. Tables and contour plots

showing precisely how and where this happened in this

realization are given in Takagi's thesis.14

Comparison Between Layered and Stochastic

Permeability Distribution

Next, a simulation was made using a reservoir

description consisting of three permeability layers with 400 md

on top, 4000 md in the middle layer and 400 md on the bottom.

A comparison of the oil cumulative recovery for this Run PF5

with that for Run PFO is shown in Fig. 17. The oil recovery for

Run PF5 is about 5 more th n that for Run PFO. However,

as shown in Takagi, the agreement with the water cuts and

polymer production data from individual wells was not as good

as for the final field case using a statistically generated

permeability field as shown next and there is no easy mechanism

for systematically assessing the uncertainty of the result as there

is for the stochastic case.

Simulated (Run PF6) and field oil production are shown

in Figs. 2-6 and 18, and comparisons of the simulated water cuts

and aqueous phase polymer concentrations with the field data for

each producing well are shown in Figs. 19 through 22. For the

base realization, the field oil recovery at 1,369 days after start of

polymer injection was 94.4 of the initial oil in place inside the

five-spot (26,013 m3 or 163,600 bbl).

The simulated oil

recovery at 1,369 days was 90.3 of the initial oil in place

inside the five-spot (24,923 m3 or 156,600 bbl).

Increasing the number of vertical gridblocks from three

to six made almost no difference in these results. We also show

on

each of these figures another realization created by simply

changing the seed for the random number generator. Again, there

is little difference between this realization and the one labelled

base realization that was used to generate all of the results shown

in this paper. We did many more realizations with similar

results. This reflects the insensitivity of the results to small

changes in heterogeneity. The results of this fhal case differ

from the base case because log based variable sand thicknesses

were used rather than a uniform average thickness.

The simulated and field polymer breakthrough times are

very close. The simulated maximum polymer concentrations in

wells CY30 and CY40 are close to the field values, whereas the

simulated

peak

polymer concentrations for well CY42 and CY41

are about 70 ppm too high. The simulated retained polymer was

120 pg/g rock, or 95.0 of the injected polymer compared to

99.2 field retention. Retention of polymer in pg/g rock is

based on the rock volume inside the five-spot pattern. Local

adsorption values vary but are lower than this average based upon

the five-spot volume, which is used merely for a convenient

reference. The maximum adsorption for any gridblock was about

36 pgtg. This amount of adsorption is about the same as the


5/16

SPE

24931

S.TAKAGI.H. BENDAKHLIG

G A

POPE.A PUTZ

AND K

EPEHRNOORI

of simulated water cuts to the field data. Thus, a comprom ise is

required to simultaneously achieve a good agreement match of

both water cut and polymer production.

Field water cuts in well CY30 (Fig. 19) show a

stronger oil bank than the simulated water cuts. A comparison

of the simulated and field water cuts in well CY42 (Fig. 20)

shows good agreem ent in the first 800 days, but the simulated

water cuts are too high after 800 days.

A comparison of the

simulated and field water cuts in well CY41 (Fig. 21) show s that

the simulated water cuts are too high except for the time period

from

4

to 800 days. A comparison of the simulated and field

water cuts in well CY40 (Fig. 22) shows good agreement most

of the time.

Polymer concentration grading is a strategy for

decreasing fingering of the chase water through the polymer slug.

The

effect of graded polymer flooding was studied by comparing

its results with those of a single-slug polymer flood of

1,000 ppm polymer co ncentration. The single-slug polymer

flood case was simulated with the same amount of polymer as

the graded polymer case. The simulated area, the grid, the well

pattern, and all other parameters were the sam e as for the base

case.

There was essentially no difference between the

simulations for the base case (graded) and the ungraded

simulation, so the results are not plotted here but c nbe found in

Takagi, who also shows other simulations to study grading and

fingering. This may seem like a surprising result given the high

mobility ratio between injected polymer solution and chase water

and thus the tendency for viscous fingering. However, detailed

simulation studies of the unstable dis lacement of polymer

solutions by water made by KruegerlBand ~ U ~ Os well as

Takagi s results including some a t higher mobility ra tios and

using finer grids have shown that decreasing polymer

concentration gradually (polymer grading) often makes very little

difference in oil recovery for a given total amount of injected

polymer. Although space does not allow us to discuss these

results in detail, the general nature of the result can be

summarized as follows. Other factors may be so dominant that

fingering has little effect. In the case of the Courtenay sand

polymer flood, the dominant facto r was polymer adsorption. A

secondary factor was heterogeneity. Large directional variations

in

permeability caused the chase water to channel rather than

finger.

Several papers21-23 have recently addressed the

conditions under which channeling, fingering, or gravity

segregation tends to be the dominant flow mechanism in

miscible displaceme nts at unfavorable mobility ratios. High

heterogeneity, especially high correlation length, tends to

promo te channeling as opposed to fingering. Also, the very

high value of RL of 50 tends to suppress fingers and promote

cases, the dominant polymer design factors are likely to be the

total amount of polymer and its initial concentration rather than

grading. High concentrations and large amounts of polymer as

used in this Courtenay pilot have been found to be the best

approach to polymer flooding in the field cas es that Krueger and

Liu have studied to date.

ON LUSIONS

Good agreement was obtained between the simulated and

field performance of the Courtenay polymer pilot in the

Chateaurenard field using a statistically generated permeability

field. Better agreement with the field

data

and better ins ight into

the behavior of the pilot was obtained using this approach rather

than a reservoir description consisting of uniform layers. More

information from logs, cores, tracers or other sources would have

been very desirable to use in conditioning these stochastic

permeability fields, but even in the absence of conditioning some

insight into the uncertainty and importance of the reservoir

heterogeneity was obtained by a combination of sensitivity

studies and multiple realizations. Both areal and vertical mesh

refinement indicated that these simulation results were

numerically accurate since the oil recovery changed very little as

the gridblock sizes decreased . Sensitivity studies showed that

this polymer pilot was dominated by polymer adsorp tion. The

oil recovery was surprisingly insensitive to change in the

permeability distribution (heterogeneity as measured by the

Dykstra-Parsons coefficient). Reduction of residual oil saturation

by the polymer to values below that expected of water may have

contributed to the good oil recovery in this pilot.

Although the actual polymerflood pilot used a large,

graded polymer injection scheme, comparisons w ith simulated

resu lts for a single , large polymer slug with the same total mass

of polymer indica ted that grading made very little diffe rence in

this pilot, i.e., finge ring was not important. This result can be

explained in terms of the dominant importance of polymer

adsorption and fractional flow effects and to a lesser extent the

effects of heterogeneity with large correlation length and large

effective length to thickness ratio that promotes channeling

rather than fingering. The exc ellent oil recovery of this pilot

(1.5 bbl of incremental oil per lbm of polymer) was a result of

using a large amount of polymer, favora ble reservoir conditions

and good des ign and implementation of this technology.

NOMENCLATURE

kH

Horizontal permeabiiity (md)

k = Vertical permeability (md)

=

Endpoint relative permeability to aqueous

phase

0

Ng = kxAp H Gravity

Number


6/16

STMUL TIONOF

A

SUCCESSFULPOLYMER FLOO NTHECH TE UREN RD

FIELD

SPE

2493

Greek

Symbols

L

correlation length scale (ft)

p

Viscosity of aqueous phase

Porosity (fraction)

ACKNOWLEDGMENTS

We thank Ph. Corlay, Ph. DeLapace, J. Lecourtier, and

1. P~ersonfrom IFP for their contribution to the paper.

Financial support from the U.S. Department of Energy and the

participating companies of the Enhanced Oil and Gas Recovery

Research Program of the Center for Petroleum and Geosystems

Engineering at The University of Texas at Austin is gratefully

acknowledged. Computing resources for this work were provided

by

The University of Texas Center for High Performance

Computing. Sunao Takagi would like to thank Japan China Oil

Development Co. (JCODC) and Japan National Oil Co. JNOC)

for the financial support during this study.

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High Recovery Obtained in a New Polymer Flood in the

Chateaurenard Field, paper SPE 18093 presented at the

63rd Soc. Pet. Eng. Annual Tech. Conf. and Exhibition,

Houston, TX, Oct. 2-5, 1988.

Datta Gupta,

A.

G.A. Pope, K. Sepehmoori, and R.L.

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a Three-Dimensional Micellar/Polymer Simulator, SPE

Reser Eng.

(Nov. 1986) 1 No. 4,622-32.

Saad, N., G.A. Pope, and K. Sepehmoori: Application of

Higher-Order Methods in Compositional Simulation,

SPE

Reser Eng (Nov. 1990) 5 No. 4,623-30.

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79BC10095, Bartlesville, OK (1981).

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Field Test Recovery Mechanism and Interpretation, paper

SPE 12685 presented at SPE POE Symposium on

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Chapotin, D., J.F. Lomer, and A. Putz: The

Chateaurenard (France) Industrial Microemulsion Pilot

Design and Performances, paper SPE 14955 presented at

SPEPOE Symposium on Enhanced Oil Recovery, Tulsa,

OK, Apr. 20-23, 1986.

Putz, A. and R.C. Rivenq: Commercial Polymer

Injection in the Courtenay Field, J

Per Sci Eng

(1992)

7 15-23.

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Sodium Carbonate Preflush: Theoretical Analysis and

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1985.

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Champ de Chateaurenard Interpretation du Comportment

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A.R.T.E.P., CFP Total, ELF Aquitaine, I.F.P., Associe:

G.D.F. (Mar. 1991).

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(1992).

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Averages of Random Field, paper presented at the S o c m

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Yang A.P.: Stochastic Heterogeneity and Dispersion,

Ph.D. dissertation, TheU of Texas, Austin (1990).

Ganapathy, S., D.G. Wreath, M.T. Lim, B.A. Rouse,

G.A. Pope, and K. Sepehrnoori: Simulation of

Heterogeneous Sandstone Experiments Characterized Using

CT Scanning, SPE 21757 presented at the SPE Western

Regional Meeting, Long Beach, CA,

Mar.

20-22, 1991.

Wreath, D.G.: Polymer Flooding and Residual Oil

Saturation, M.S. thesis, The U. of Texas, Austin (1989).

Krueger, C.:

Viscous Fingering, M.S. thesis, The U. of

Texas, Austin (1989).

Liu, J.: Ph.D. dissertation (in progress), The U. of Texas,

Austin (1992).

Chang, Y.B., M.T. Lim, G.A. Pope, and K. Sepehrnoori:

Carbon Dioxide Flaw Patterns Under Multiphase Flow,

Heterogeneous Field Scale Conditions, paper SPE 22654

presented at the 66th Annual Technical Conference and

Exhibition of the Society of Petroleum Engineers, Dallas,

TX, Oct. 6-9, 1991.

Ringrose, P.S., K.S. Sorbie, F. Feghi, G.E. Pickup, and

J.L. Jensen: Relevant Reservoir Characterisation:

Recovery Process, Geometry and Scale, paper presented at

the 6th European IOR-Symposium, Stavanger, Norway,

May 21-23, 1991.

Waggoner, J.R., J.L. Castillo, and L.W. Lake:

Simulation of EOR Processes in Stochastically Generated

Permeable Media, paper SPE 21237 presented at the SPE

1 th Symposium on Reservoir Simulation, Anaheim, CA,

Feb. 17-20, 1991.


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Table 1. Pore Volume, OOIP and Cu mulative Oil Production

f December 1987

as of June 1989

Table 2. Injection Scheme of Polymer Solution in the Chateaurenard Polymer Pilo t

Table 3.

Injection Schedule of Polymer and Chase Water used in Simulations

Date started Time, t t

Injection Rate Concentration

Volume Polymer

mo/day/yr)

days)

days) B P I

[m3/dl

PPm)

@b l) [m31 Quantity

tons)

10/01/85 273 273 252 [40]

334 [531

408 [64.8]

230 [36.6] 1,000

555 [88.21 800

622 98.91 625

586 [93.1] 500

537 B5.41 400

531 [84.3] 200


8/16

Figure 1A Isopach map of the Courtenay field


9/16

0 200 400 600 800 1000 1200 1400 1600

Time

Days)

Figure 2. Com parison of the total oil production rate for the final simulatio n

PF 6) with the field data.

ield data

Base realization 15 x1 5~ 3)

*

Realization 3

200 400 600 800 1000 I200 1400 1600

Time

Days)

Figu re 4. Com parison of the oil production rate of well CY4 2

for the final simulation PF6 ) with the field data.

Time Days)

Figure 3 Co mp arison of the oil production rate of well CY3 0

for the final simulation PF6 ) with the field data.

Time

Days)

Figure 5 Com parison of the oil production rate of well CY41

for the final simulation PF 6) with the field data.


10/16

I l l l t l l l l l [ l l l { l l l l l r a l l l l r

ield data

Base rea li zat ion 15 x1 5~ 3)

Mesh refinement 15 x15 ~6 1

Realization 3

Figure 6. Comparison of the oil production rate of well CY40

for the final simulation PF 6) with the field data.

x direction

1 7

4

5

8

9

I 0 1 1 1 2 1 3 1 4 1 5

x

direction

1 2

4

5

6 7 8

9 1 0 1 1 1 2 1 3 1 4 1 5

Figure 7. Permeability contour map for the top layer 1 5x 1 5~ 3) .

Figure

8

Permeability contour map for the middle layer 15 x1 5~ 3) .


11/16

x direction

I 2 6

7 8 9 1 0 1 1 1 2 1 3 1 4 1 5

Polymer concentration (wt 7c)

Figure 10. Comparison of measured and modeled viscosities

of polymer solution at zero shear rate.

Figure

9.

Permeability contour map for the bottom layer 15x 15x3 ).

Polymer concentration

wtclc

Figure I I. Polymer adsorption isotherms.


12/16

1 5 . I I

ase case and at lOW md

Base case and at 1500md

- - - Base case and at 2000md

-

ow case and at 1000md

- - - .

Low

case and at 1500md

-

Low

ase and at

2000

md

Polymer concentration

( ~ 1 )

Figure 12. Permeability reduction factor for the base case and the low case.

200 400 600 800 1000 1200 1400 1600

Time Days)

Figure 13. Comparison of the oil recovery for the base case PFO: 15 ~15x3) ith

the oil recovery for the areal mesh refinement case PF1: 25x25~3).


13/16

0 200 400 600 8 00 1000 1200 1400 1600

Time

Days)

Figure 15. Comparison of the oil recovery for the base case PFO) with

the oil recovery for the lower permeability reduction case PF2).

0 200 400 600 8 1000 1200 1100 I600

Time Days)

Figure 16. Comparison of the oil recovery for the base case

PFO)

with

the oil recovery for the higher VDpcase PF4).


14/16

Time

Days]

Figure 18. Com parison of the oil recovery for the final

simulatio n PF6 ) with the field oil recovery.

200 400 h00 XI10 1000 1?00 1400 h l l

me Days


15/16

0 2 0 0 OO 600 SO0 1000

1200 1100

Time Days)

Figure 20. Comparison of simulated well performance PF6)with the field well

performance in well CY42.

2 0 0 400 600 8 0 0 I J00 12illl 11110 lh 00


16/16

SP 24931

ield data

Base realization l S x l h 3

Mesh refinement

1 5 x 1 5 ~ 6

........

UTCHEM Chtterau Example

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