Hycal Energy Research Laboratories Ltd

RESERVOIR ENGINEERING
D.W. BENNION and R.G. MOORE
University of Calgary
F.B. THOMAS
Hycal Energy ResearchLaboratoriesLtd
ABSTRACT
1Mrma/ numericalsimulato13"
havebeenusedto predict the performance of the steamstimulation processes.Our experienceis
that room tempenrtun relativepermeability curvesmeaswwf on
extractedcore samplesneed to be adjusted to match field perfomlOna. Thispaper describesa study which ttW"conducted to
observethe effects of temperatureon initial ~ter .mturations
and residual oil .mturotions.
A pre;S'erved
core ttW" mounted, slre.ssedbock to reservoir
conditions and .mturatedwith live reservoiroil, then ~terfloods
and oi(f100ds~
run at ~ir
and elevatedtemperatures.
~ single-cycienumericalsimulations ~e run. One utilized
relative permeability CUnleSderived from a room temperature
~terflood on on extracted core which was saturated with
mineral oil. 11reother simulation usedthe relati~ permeability
curvesfrom thepreservedcore, which wasrun with overburden
prFssurr, and live crude oil. Both sets of simulations used
temperaturefunctional relationshipsfor the residual oil saturations and connate ~ter .mturations. 77resimulation which used
the preservedcore relative permeabilities resulted in matching
lhejleld ~ter production much closerthan the simulation using
extractedcore relative permeabilities.
decreaseswith increasesin temperature. Poston (1970) and
Sinnokrot (1"911)found that as the temperature increasedthe
irreducible water saturation increased.Odeh (1965), Combarnous (1968), Wilson (1956)and La (1973)have postulated that
the decreasein viscosity ratio is responsiblefor the decreasein
residual oil saturation. Poston (1970)suggestedthe decreasein
residual oil saturation was due to a change in wettability.
Poston (1970) found that for unconsolidated sand both the
rdative permeability to oil and to water increased as the
temperature increased. Weinbrandt (1972) used consolidated
Boise sandstoneand reponed that the relative permeability to
oil increased with temperature. The relative permeability to
water decreasedat low water saturations but increased at
flood-out. The study of Lo (1973) using consolidated Berea
sandstone and porous teflon cores found that relative
permeability to oil and water increasedwith temperature.
Dietrich (1981)devdoped a set of empirically derived relative
penneability curvesto match the performanceof a cyclic steam
stimulation processin a heavy oil reservoir. To simulate this
process both imbibition and drainage relative permeabilities
relationshipswererequired. The empirically determinedrelative
penneability curves were very different from those generally
reported in the literature for unconsolidatedsand.
Introduction
Dwing the past severalyearsthe authors haveendeavouredto
Relativepermeabilitiesplay an important role in the resultsof a develop proceduresfor measuringrelative permeability curves
paper
numericalsimulation using a thermal simulator. In thermal pro- for unconsolidated sands containing heavy oil. ~
the experimentalprocedureused to obtain the curves.
cesses,the reservoir matrix and fluids undergo temperature descn"bes
changes.Thesetemperaturechangesreducethe viscosity of the It also presentsthe resultsof two cyclic steamnumericalsimulaoil, causerock fluid interactionsto occur, and increasestresses tions using relative permeability curves developed from
within the rock matrix. A number of investigatorshave found measurementson an extracted, mineral oil saturated core and
that increasesin temperatureresult in decreasesin permeability; measurementson a preservedcore using the technique develAfmogenou (1969),Weinbrandt (1972),and Okoh (1980).Other oped by the authors. The relative permeabilitiesdata for the
investigators have found that permeability either increasesor extractedcore were taken from curvescontained in the Alberta
remainsconstant. Gobran (1981)discussesthe finding of these Energy ResourceConservation Board's data file for the Sparky
investigators.Somerton (1981)has estimatedthat porosity may Sand in the Uoydminster area. The gas-oil rdative permeabilidecreaseas much as 3 to 5 per cent as a result of increasingthe ties from the extracted core were usedfor both simulations.
temperatureby ISOOC.
Edmondson (1965) found that the residual oil saturation Description of Equipment
The displacementequipmentis designedto operateto 20.6 MPa
and temperaturesto 300°C. The equipmentconsistsof threesets
equipment. core holder and gasKeywords: Reservoir engineering, Relative permeability, Stearn of components: the in~on
stimulation, Numerical simulation, Heavy oil, Waterflooding, Water
measuring equipment. A brief description of the components
saturation.
follows:
Paper reviewed and accepted for publication by the Editorial Board of the Journal of Canadian Petroleum Technology
40
The Journal of CanadianPetroleum
FIGURE I. Equipment schematic
Injection Equipment
The injection equipment consists of a variable rate Ruska
displacementpump. It is used to flood the core with dead oil,
recombinedoil and water. figure 1 presentsa schematicof the
equipment used in the study.
Core Holder
The core holder assemblyconsistsof a flexible sleevecore holder
mounted in a pressurejacket, heaters,pressuretransducersand
a back pressurevalve. The annular spacebetweenthe pressure
jacket and core holder is nonnally filled with water. The overburden pressureis maintained by pressuringa small void space
abovethe water with nitrogen. The pressurejacket is also equipped with a pressurerelief valve which relievesif it exceedsa set
pressure.The externalsurfaceof the pressurejacket is thennally
insulated. Internal heatersactivated by an automatic temperature controller allow for elevated temperature operation. The
core is mounted in a lead s1eeve
betweeninjection and production heads which have 0.11>mm slot plates to retain sand. A
flGURE 2. RdatiYe penneabUity-praerved core
pressure transducer connected across the core measuresthe
pressuredrop. Diaphragmisolatorsare usedto preventheavyoil
from migrating to the differential pressuretransducers.The core
holder also has Bourdon tube gauges on the injection and
core was 3.95 p.mz,while the preservedcore had a penneability
production 1inesfor a rough check on the pressuredrop. The
of 3.59 p.mzafter it was extracted.
dome-loadedtype back pressurevalve maintains the production
The core holder wasplacedin the pressurejacket and a c0nfinend of the core at the desiredreservoir pressure.
ing pressureof 10.34MPa applied~
nitrogen. Following leak
checking,
the
pressure
jacket
was
filled
almost to capacity with
Gas Measuring Equipment
water and pressuredwith a small nitrogen pocket to 10.34MPa.
The gas-measuringequipment consists of a mercury
The core wasfirst saturatedwith deadoil followed by live oil.
manometerand a collection separatorof known volume. Con- The live oil flood was continued until the GOR of the produced
stant produced gas volumes are measured by observing the oil equalled that of the oil being injected. Once this was
pressurerise over a measured period of time. If large volumes established,the injection was stoppedand the core pressurewas
of gas are being measured a Ruska gasometeror a wet test
allowed to stabilize.
meter is used.
Next, a waterflood was performed at 27°C. During this displacement,
sampleswere collected every 15 minutes. The water
Experimental Procedure
content of ead1samplewas determinedby vacuum distillation.
Three 3.81 cm di3meter
core plugs were drilled horizontally
This was necessarybecausethe water and oil formed an emulthrough a preserved field core. The plugs were then stacked to
sion which could not be separatedby centrifuging. Following
form a composite core for the test. Tabulated
below are the
the waterflood the core was flooded using live oil. Sampleswere
approximate
lengths and weights of the individual
core plugs.
collected every 15 minutes am the oil and water separatedby
distillation. During each of the tests, the pressuredrop across
Dailn.ted
PIal Weilbt
Pl1IIlenaI.
Pial Number
I
cm
the core was continuously monitored.
After the live oilflood the temperaturewasincreasedto lOOOC
I
1.57.7
7.62
2
1.51.2
7.62
and another waterflood condocted(during all testsconductedat
3
166.7
7.62
elevated temperaturesthe backpressure was maintained at a
levd to preventgasfrom coming out of solution). Following this
Total:
47.5.6
22.86
flood the temperature was increasedto I sooC and the flood
The individual plugs werestackedin the core holder with plug continued until no additional oil was produced. Then the
No. I closestto the inj«tion end, plug No.2 in the middle and temperature was raised to 22OoC and flooded to a residual
plug No.3 at the production end. The compositecore wasgently saturation. Fmally the back pressurewas reducedand the core
compacted after each plug was placed in the lead sleeve.The steamflooded to a residual oil saturation.
total length was measuredto be 21.17 cm after fmal compacNext, the core was oilf1(XXJed
using live oil at 22O°Cuntil no
tion. The absolutepermeability and mineralogyof the preserved additional water was produced, the temperaturewasreducedto
core weresimilar to the extractedcore. Permeabilityof extracted I sooC and the core oilflooded to a residual water saturation.
Technology, March-AprfI1985, Montreal
~
Anally the temperaturewas reducedto IOOOC
and flooded to a
residual water saturation.
At each endpoint during the waterl100d 100°C, ISOOCand
220°C and after the steamf100d,the penneability to water was
determined. During the oilflood, permeability to oil was determined at the endpoints of 200°C, ISOOCand IOOOC.The
relative penneabilities were calculated using a two-phase
numerical simulator and a non-linear least square regression
procedure. A similar model is discussedby Sigmund (1979).
FoUowing the completion of the test the core was solvent.
extracted using toluene, COz and methanol to remove the oil
and water. Mter the core was extracted the permeability to
water was measwed.
water increasesas the residual oil saturation d~
and the
temperature increases.The relative penneability to oil at the
irrcdua"ble water saturation decreases as the temperature
increases.
Figure 2 presentsa plot of the relative penneability curves
from tbe preservedcore at 27°C and 22O0C. It can be seen
from tbe 27°C water curves that the relative permeability to
water is larger with increasing water saturation than it is with
decreasing water saturation. The corresponding 27°C oil
curves show little hysteresisexcept at tbe lower water saturations. The water and oil relative permeability curves at 22QOC
are also included on this figure for the oilflood following
steaming the core.
Figure 3 shows the relative permeability curve from an
Discussion of Results
extractedcore. Thesecurveswere obtained from the ERCB files
From the data obtained in the various displacements,it was and were run by saturating the extracted core with formation
possible to calculate:
water, then oilflooding to a connate water saturation using a visI. Residual oil saturation foUowing hot waterflooding as a cous mineral oil. The core was then waterflooded and the
function of temperature.
recoveryand pressuredata usedto obtain the relativepermeability
2. Residual oil saturation as a result of steamflooding.
curves. Two thinp should be noted about these curves. FIrSt,
3. Drainage and imbibition hysteresis.
the irredUCIOIe
water saturation is much Io~ than thoseusually
4. Drainage and imbibition relative permeability curves for
found in unconsolidatedSparky sands from the Lloydminster
oil and water at 27°C.
area of Alberta, and second, the penneability to water at the
5. Imbibition relative permeability curves to oil and water at residual oil saturation is much higher than the ones measured
100°C.
using stressedpreservedcores and the actual reservoir fluids.
6. Residual oil saturation endpoint at 27°C, 100°C, ISOOC The extracted and p-eservedcore plugs both ~
from the
and 200°C and penneability to water at the endpoints.
Sparky sands.
i
Steamresidual oil saturation and permeability to water at
An examination of the curves in Figure 2 show that they
this point.
possessthe characteristicswhich Coats et a/. (1977)and Dietrich
8. Irreducible water saturation at 220°C, 150°C, 100°C and (1981) had to assumein order to match the stearnstimulation
27°C, and the permeability to oil at each of these end- process.The relative permeability curvesin Figure 2 possessthe
points.
following properties:
Table I presentsthe compositeproperties of the core foUowing extraction of the core at the completion of the test program.
Table 2 presents the permeabilities measured on the core
TABLE 3. Model parameters
sample at various endpoints during the displacementprocess.
Number of grid blocks In r direction
7
The data indicates that the endpoint relative penneability to
Numberof grid blocks in z direction
5
Maximum Injection pressure-kPa
10340
Steam quality at sand face
0.70
TABLE 1. Compositecore properties
Injection rate-m/day
180
Permeability-m
3.80
PoroSity
per cent (aft., extraction)
0.32
Pemleabillty
~m2(after extraction)
3.D
Porosity- per cent"
32.0
Water Saturation
- per cent (companionsample)
8.84
Ratioof verticalto horizontalpermeability
0.1
Inlti~ 011Saturation - per cent (companion sample)
70.16
Initial reservoir pressure-kPa
4030
--
Initial Pore Volume
Bulk Volume
Diameter
Length-
- Cm3(after extraction)
cm3
83.4
280.62
-
- cm
- cm
3.81
22.-
TABLE 2. Permeability p.m2
Permeability to 011
at irreducible water saturation
Permeability to water
at residual oil saturation
Permeability to water
at residual oil saturation
Permeability to water
at residual oil saturation
Permeability to water
at residual oil saturation
Permeability to water at residual
011saturation after steamflood
Permeability to oil
at Irreducible water saturation
Permeability to 011
at irreducible water saturation
Permeability to oil
at irreducible water saturation
Permeability to oil
at irreducible water saturation
Permeability to water after
extraction (1008/0water saturated)
42
27.C
051
27°C
0.0027
100.C
0.0030
1SOoC
0.0035
22O.C
0.0038
22O.C
0.00739
22O.C
0.414
1SO.C
0.495
100.C
0.532
27.C
0.576
27.C
-
3.594
:m
Initial reservoir temperature-K
Initial oil saturation
Initial watersaturation
.300
Density gmol/m
Heavy 011component
light 011component
Water
Solution gas
Motecular Weight kg/gmol
1382
4044
5.537x10+ 4
18700
Heavy 011component
light 011component
Solution gas
.720
.180
.016
Thermal Conductivity (J/m-day.K)
011
Water
Rock
Compressibility kPa-1
Rock
Heavy oil
light 011
Water
Coefficientof ThermalExpanslon-K-1
Rock
Heavy011
light oil
Water
Dead 011Viscosity
mPa.s
110
60
30
.695
1.15 x 10-4
5.35 x 10-4
1.496x 10-4
4.05
2.18
2.18
4.35
x 10-6
x 10-6
x 10-6
x 10-7
4.4 x 10-5
8.5 x 10-4
8.5 x 10-4
1.044x 10-3
Temperature
K
~
333
D
The Journal of Canadian Petroleum
I. Lower valuesof permeability to water at the endpoint. The
preservedcore value for water is .0037compared to .11 for the
extracted core.
2. The permeability to water is higher on the injection portion
of the cycle than on the production portion of the cycle.
3. Oil hysteresisis not as great as the water hysteresis.
The experi~tal results presentedin this paper confirm the
authors' experience that the practice of measuring relative
permeability curveson extractedcore material with mineral oil
leadsto relative permeability curveswhich must be adjusted to
match fidd stearnstimulation perronnance. The curves devdoped in this manner show higher permeability to oil at initial
water saturation, lower irreducible water saturation, very different values for the water relative permeability curve and
hysteresisof the water relative permeability curve.
Thesewere obtained from various sourceswithin the literature.
The relative penneability curvesfor the extractedcore casewere
shifted to fall within the ranse of saturations observed for the
preservedcore displacements.The shifted curve is shown in
Figure 3. This shifting reduced the width between initial and
final water saturation; and gavea higher relative permeability to
water at a given changein water saturation than the non-shifted
curves.
In both cases,the irreducible water saturation and residualoil
satW'ationswere made functions of ttrnperature. The data from
the preservedcore ~ts
testswereusedfor the extracted
Numerical Simulation
In order to determine the effect of relative permeability curves
on the results from a nwnerical simulation, similar twodi~nsional single-cyclesimulations (with the exception of the
rdative permeability curves) were performed using the Computer Modelling Group's general purpose thermal simulator.
Figure 4 showsthe grid systemused for the study. A total of 35
grid blocks wereemployed. The perforated interval is shown by
the cross-hatchedmarks on the left hand axis.
Approximatdy 6800 m) of water converted to steamwas injected, the wdl wassoakedfor 10 daysand then put on production. The bottomhole pressurewas systematicallyreduceduntil
it reached 1300kPa. The weDwas placed on a constant liquid
withdrawal rate until a bottomhole pressureof 200 kPa was
reached.Production was then governedby a minimum bottomhole pressureof 200 kPa.
Table 3 presentsmost of the parametersused in the study.
'nFIGURE4. Na_rlal
simulationgrid
"GURE 3. RelativepmDeabilitY-cIlractedcon
Technology, March-April 1985. Montreal
43
~
core as well as for the ~
core. For the preservedcore
~,
the waterflood relative peameabilitieswere used for the
injection cycle and the onflood relative permeabilitieswereused
for the production cyde.
Three hydrocarbon componentswere used: a heavy oil, light
on and soIun.:>ngas. Equih"briumconstantswere determinedso
as to match t.le viscosity of the oil at any given temperature.
Figure 5 shows the production rate of oil and water for the
two simulations. The preservedcore caseshows that the water
production rate ~ drastically decreasedwhile the oil rate is only
slightly reducedas compared to the extractedcore case.It took
40 days to inject the steam USingthe extracted relative permeabilitiesand 63 daysusin&the preservedcore relative penneabilities. Thus, the preservedcore relative permeabilitiesresulted in
reduced water injectivity and productivity. They appear to
affect the productivity much more than the injectivity. The
~ulation usin& the extracted core relative permeabilitiesproduceda total of 4640m3of water ascomparedto 904 m3for the
preservedcore ~.
The on production was 9365 m3 for the
extracted core relative penneabilities and 8170 m3 for the
preservedcore set of relative permeabilities.
FIgUre6 comparesthe water cut, calculatedusing the two sets
of relativepenneability data. with fidd data presentedby Coats
et aJ. (1977). This fIgUre shows that using the preservedcore
relative permeabilitiesin th~ simulation yjdds the correct shape
and magnitude for the water cut curve. This may be fortuitous
since the rdative penneability curves came from a different
reservoir than the one Coats presenteddata for. Nevertheless,
the shapeof the curves are similar to those which individuals
using nwnerical simulators have had to use to match the water
production. The main purpose of the simulation was to show
that laboratory measuredcurvesfrom preservedcore whendone
at reservoir conditions do not need to be adjusted to give low
water production.
use of their thennal simulator ISCOM to perform the simulation, NSERC for their financial assistanceand Hycal Energy
ResearchLaboratories Ltd. for providing the preservedcore
relative permeability curves.
REFERENCES
I. AFlNOGENOU,Y.A.: How the Liquid Permeabilityof Rocks
is Affected by Pressureand Temperature,SN/IGIMS (1969),
No.6, pp. J4-41.
2. COATS, K.H., RAMPSH, A.B., and WlNESTOCK,A.G.:
Numerical Modeling of Thermal Reservoir Behavior, Procwdings
01 the OiISandsolCanado
- V~/a1977,
CIMSpet". Vol. 17,
pp. J99-410.
3.
4.
S.
IiJ.
7.
R
J.
9.
10.
II.
Conclusions
I. Permeability tests using preserved core, overburden
pressureand live reservoir oil, give relative permeability curves
with hysteresisin both the oil and water curves.
2. Permeability to water using a preservedcore and reservoir
fluids is much lower at a given saturation than those obtained
using extracted cores and a mineral oil.
3. Relative permeabilities from a preservedcore when used in
a numerical simulator gave a relatively close match to the
shapeof a field water cut curve.
13.
Acknowledgments
IS.
The authors wish to thank Computer Modelling Group for the
12.
14.
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The Journal of CanadianPetroleum