Note: Descriptions are shown in the official language in which they were submitted.
:~2~7
A~ cation for Patent
Title: METHOD FOR DETERMINING RESIDUAL OIL
SATURATION OF A GAS-SATURATED RESERVOIR
Inventors: Joseph S. Tang and Bradford C. EIarker
:~pecification
Field of the Invention:
The present invention relates to a method of using
tracers to determine the in situ residual oil saturation
between two locations in subterxanean gas-saturated oil
reservoirs with gas being the ~obile phase. More
specifically, -the present inverltion relates to the
: determination o~ the relative concentrations of oil and
gas within subtèrranean reservoirs: by measuring over a
period o~ tlme -the chromatographic separation of -tracers I
having distinctly different Henry's law constants or
: K values in the oil and gas phase fluids in the reservoir.,
Background of:the:Invention: :
Typical oil reservoir:formations are made up of rock
containing tiny, interconnected pore spaces which are
saturated with oil, water, and gas. KnowIedge of the
concentrations of these fluids in the formation is
critical for the effic~ient p~oduction of the oil. When
the formation is first drilled, it is necessary to know
: -the or~ginal oil saturation in order to plan the
: 20 exploitation of the ~ield. Later in the life of the
field, the amount of oiI remaining in the ormation will
22658/16/1-1-1/ME
13 2 ~
often dictate the most efficient secondary and tertiary
recovery operations.
Several methods are currently used to determine Eluid
saturations of a formation. One techni~ue involves
coring, i.e., direct sampling of the formation rock and
fluids wherein a small portion of rock satura-ted with
fluids is removed and brought to -the surface where its
fluid content can be analyzed. Coring, however, is
susceptible to several shortcomings. First, the small
sample may not be representative of the formation as a
whole since it only investigates the immedia-te vicinity of
the wellbore. Second, the coring process itselE may
change the fluid satur~tions of the samples. Finally,
coring can usually only be done in newly drilled wells.
Another method of de-termining fluid saturations
involves logging techniques. This method, too, suffers
from the shortcoming of investigatin~ a limited area which
is in the immediate vicinity of the wellbore. In
addition, logging techniques are often unable to
differentiate between properties of the rock and those of
its fluids. U~fortunately, coring and log~ing are not
suitable for low-pressure, low-porosity, gas-filled
carbonate reservoirs.
Another approach involves material balance
~5 calculations based on production history. ~Iowever, this
approach is susceptible to error since it requires a
knowledge of the ini-tial fluid saturation of the formation
~y some other independent means.
More modern methods for determining fluid saturations
involve the injection and production of tracers. The
technigues are based on chromatographic theory~
Typically, two tracers having different ~artition
coefficients are used. The tracers are
chromatographically retarded to different e~tents as they
3~ pass through the formation. The degree -to which the two
tracers are differentially re-taxded can be used to
determine the formation fluid saturations.
22658/16/~ MF
~ 3 ~ 3~ r~
Most tracer techni~ues for the determination of fluid
saturations involve using a single well. A fundamental
problem wi-th single well testing is that only a very
limited portion of the formation, the area immediately
surrounding the wellbore is investigated. ~part from this
fundamen-tal problem, single well testing which a-ttempts to
take advantage of chromatographic principles also suffers
from an additional shortcoming -- the "mirror image"
effect. The mirror image effect occurs where two or more
tracers having different partition coefficients are
injected into a formation. The tracers will separate as
they are injected into the formation, and thP degree of
separation will be a function of the oil sat~lration.
However, when the tracers are withdrawn from the formation
by means of the same well, the separation will disappear.
When the tracers moved away from the well, one tracer
moved faster than the other due -to the difference in
partition coefficients and the residual oil saturation.
When the well was placed on production, the faster moving
tracer again moves further than -the other and the two
tracers arrive at the wellbore at approximately the same
time.
Several schemes have been devised to avoid this
problem. In one techni~ue, the well is shut in after the
injection of the tracers for an extended period of time.
This allows the tracers to drift, i.e. to move in the
formation under -the in1uence of forces unrelated to the
injec-tion or withdrawal of fluids a-t the well. When the
well is pu-t on production, the tracers are somewhat
separated and a determination of fluid saturations becomes
more feasible. The problem ~ith this technique is that it
is difficult to determine the -time necessar~ for the
tracers to drift. Furthermore, e~tended residence time in
the formation creates other problems, such as
gravita-tional separation of the tracers.
Another way of getting around the "mirror image"
effect is to inject a non-reactive tracer along with a
22658/16/~
~L32~37
tracer precursor. The injec-tion is followed by a shut~in
period during which -the precursor is allowed to react to
Eorm a tracer. The precursor and corresponding tracer
have different par-titioning coefficien-ts. During -the
in~ection phase, the precursor and non-reactive tracer
move away from the well a-t certain velocities determined
by their partition coefficients. During the production
phase, the non-reactive tracer moves back toward the
wellbore at the same rate but the newly formed tracer,
because it has a different parti-tion coefficient from that
of its precursor, moves at a rate different from -that of
its precursor. The resul-t is a separation at the wellbore
of the two tracers. The problem with this method is that
it depends for its success on chemical reactions which are
influenced by various factors, such as formation
temperature. In addition, this method is not applicable
to gas-filled reservoirs because o~ a lack of suitable
tracers which can react in the gas phase or the oil phase
to generate the necessary tracers.
The mirror image problem can be completely
circum~ented by injecting a carrier fluid containing at
least two non-reactive tracers having different partition
coefficients between the fluid phases into one location in
the formation and produciny f~om another. Typically, one
well is used to inject the carrier ~luid bearing the
tracers while another well is used to p~od~ce formation
fluids. Because different injection and production
locations are used, it is unnecessary to rely on fluid
drif-t for the separation of the tracers. Nor is it
necessary -to use tracer precursors and rely on chemical
reactions to produce tracers with different partitioning
coefficients. Instead, non-reacti~e tracers can be used
which are chromatographically separated as they pass
through the formation, and this chromatographic separation
is a func-tion of the saturation of the immobile phase.
The basic idea of chromatographic separation was
disclosed by Dr. Claude Cooke in U.S. Patent 3,590,923.
22658/16/l-1-l/MF
-5- ~3~ 7
Cooke injected fluid containing at least two tracers of
differen-t partition coefficients. The tracers were
chromatographically retarded in their passage -through the
formation to dif~erent ex-tents. The breakthrou~h of -the
tracers was detected in another location, and inferences
were drawn about the relative proportion of forma-tion
fluids.
While the Coo]~e method was superior to any of those
previously used, it suffered from a number of serious
drawbacks. First, little guidance was given on the
selection of appropriate tracers. Second, the Cooke
method used only tracer breakthrough quantities -to
calculate residual oil saturation. Because of dispersion,
stratification, streamline effects and the detection
properties o~ various properties, it was usually difficult
to determine the precise time of breakthrough with great
accuracy. Even when breakthrough was determined wi-th
considerable accuracy, -the effect of using only the
breakthrough was that only the residual oil saturation of
the most permeabl~ layer was determined. The saturation
of other layers in the formation were not determined by
this techni~ue. Thus, there still exists a need in the
industry for a method to accurately determine the residual
oil sa-turation of a formation.
Summary of the Invention:
The present invention relates to an improved process
in which residual oil satuxations o a
hydrocarbon-containing, ~as-saturated formation are
determined by injecting a fluid containing at least two
properly selected non-reactive tracers into the formation.
The tracers have different partition coefficients and are`
chromatographically retarded in their passage through the
formation to differing extents. The presence and amounts
of the tracers are detected over extended periods of time
at another location. The complete results are analyzed
using chromatographic theory or reservoir simulation
methods to determine the relative proportions of formation
22658/16/1-1-l/MF
:~ 3 ~ 7
fluids for various por-tions of the formation be-tween the
injection and production locations.
The presen-t invention re~uires selecting appropria-te
tracers. One of these tracers is selec-ted from the group
consisting of halocarbons, halo~hydrocarbons and tritiated
or carbon 14 tagge~ hydrocarbons. This first tracer is
oil partitioning with a Henry's law constant in -the
appropriate range. The second tracer is preferably an oil
non-partitioning tracer, such as sulfur hexafluoride,
-tritium gas or radioactive isotopes of inert gases with a
Henry's law constant at reservoir con~itions which is hi~h~
relative to the selected oil partitioning tracer.
However, this second -tracer can be selected from the same
group of oil partitioning tracers as the first tracer so
long as it has a Henry's law constant different from the ¦
first tracer.
The tracers are injected into the formation through
an injector well. Production is from a well in
communication with the injection well. Samples are taken
of -the produced fluids over an extended period o~ time and
are anal~zed for the presence and amount of the tracers.
The residual oil saturations of the various layers of -the
formation are calculated accord:ing to chromatographic
theory using the breakthrough ~uantities and the
production function of the tracers.
Brief Description of the Drawings:
Fig. 1 is a plot of inverse Henry's law constants
with retention pore volume for a slimtube test 1.
Fig. 2 is a plot of inverse Henry's law constants
with retention pore volume for a slimtube test 2.
Fig. 3 shows tracers partition profile (concentration
as a func-tion o time).
Fig. 4 shows tracers partition profile ~concentration
as a function of time) with four "landmarks" indicated.
Fig. 5 shows plots of inverse Henry's law constants
versus production time for the four "landmarks" of Fig. 4.
2265~/16/1-1-1/MF
~3 ~
Fig. 6 is a plo-t of "Sor" versus cumulative recovery.
Description of the Invention:
Selectlon of Tracers
Tracers useful in this invention include oil
partitioning tracers, such as halocarbons,
halo-hydrocarbons, triti.a-ted or carbon 14 tagged
hydrocarbons, as well as oil non-partitioning tracers,
such as sulfur hexafluoride, tritium gas and radioactive
isotopes of inert gases with a ~Ienry's law constant at
reservoir conditions which is high relative to the oil
partitioning tracer used.
Tritiated hydrocarbons are ordinary hydrocarbons with
at least one hydrogen replaced by tritium. Likewise,
carbon 14 tagged hydrocarbons are ordinary hydrocarbons
with at least one carbon replaced by carbon 14. These
txitiated or carbon 14 tagged hydrocarbons, which can be
saturated or unsaturated, may contain up to 5 carbons.
Selection of the appropriate halo hydrocarbon, halocarbon,
and tritiated or carbon 14 taggecl hydrocarbon is based on
~0 the Henry's law constant (or K value) at reservoir
conditions and on the detection limit.
Henry's law constan-ts can be determined in the lab
using pre-e~uilibrated reservoir gas and oil at reservoir
temperature and pressure by a static partitioning test or
by a dynamic slim-tube test. In -the static partitioning
test, a 0.001~ to 2% concentration of halo-hydrocarbon or
halocarbon is introduced into the pre-e~uilibrated gas
which is then eguilibrated with the oil for at least 4
hours in a rocking cell. The halo-hydrocarbon or
halocarbon concentration in the gas and liquid phases can
then be determined by: (a) direc-t measurement; ~b)
measuring the halo-hydrocarbon or halocarbon concentration
in the gas phase and determining the concentra-tion in the
oil phase by head-space analysis; or (c) measuring the
halo-hydrocarbon or halocarbon concentration in the gas
22658/16/1-1-1/ME
--8--
~ 3 ~
phase before and af-ter equilibrium and de-termining its
concentration in the oil phase by material balance.
In the static partitioning tes-t, a small dosage of
tritiated hydrocarbon or carbon 14 -tagged h~drocarhon,
typically less than 0.001 m Curie, is introduced into -the
pre-eguilibrated gas which is then equilibrated with the
oil for at least 4 hours in a rocking cell. The tritiated
hydrocarbon or carbon 14 tagged hydrocarbon concen-tration
in the gas and liquid phases can then be determined by
first separating the components by preparative gas
chromatography or other means with or without added inert
carriers and measuring the activities of the individual
tri-tiated hydrocarbons or carbon 14 tagged hydrocarbons.
Alternatively, the tritiated or carbon 14 tagged
hydrocarbon concentration in the gas phase before and
after equilibrium can be measured, and its activity in the
oil phase can be determined by material balance.
Henry's law constant "Hi" is defined as:
Hi = xi (atm~ (1)
where "yi" is the mole fraction of -tracer "i" in the gas
phase, "xi" is the mole fraction of tracer "i" in the oil
phase, and "P" is the reservoir pressure, atm. Henr~'s
law constant can be calculate~ as:
Hi - ~ Ai* )( RTZ(T,P) ) Vo ~2)
Ai~-Ai* Vg Vm
where Ai, Ai* are the gas chromatograph peak area counts
for halo-hydrocarbon or halocarbon "i" or the
decompositions per cc of gas at a reference T, P per
minute for tritiated or carbon 14 -tagged hydrocarbon "i"
before and after e~uilibrium respectively, "Vol' and 'IVg
are the volumes of oil and gas in the rocking cell for
partitioning test, IlVm" is the molar volume of the oil,
llZll is the compressibility factor, I'Rl' is the gas
constant, and "T" is the temperature, in degrees Kelvin.
22658/16/1-1-1/MF
-
- 9 -
~32~
A slimtube with 0.1 -to 0.5" ID and 40-120 ft. lenyth
is suitable for the dynamic test. Th~ tube is packed with
glassbeads and maintained at reservoir pressure by using a
back pressure regulator. The test is conducted in an oven
at reservoir temperature. The tube is first saturated
with oil and then gas-flooded to residual oil saturation
with the pre-equilibrated reservoir ~as. ~lterna-tively,
the tube can also be first saturated with formation water
and then oil-flushed followed by a gas-flood to connate
water and residual oil saturations. A known but small
slug containing the halocarbons, halo-hydrocarbons or
tritiated or carbon 14 tagged hydrocarbons to be tes-ted is
injected into the tube, and the tracer concentrations in
the effluent gas are continuously monitored through a
sampling valve by a gas-chromatograph with an electron
capture detector in the case of the halo-h~drocarbons or
haloearbons and b~ a gas proportional counter or li~uid
scintillation counter in the case of the tritiated or
carbon 14 tagged hydrocarbons. Component separation prior
to coun-ting is not required sinee various tritiated or
carbon 14 tagged hydrocarbons have been separated in the
slimtube.
The Menry's law constants for individual tracers can
be ~alculate~ from the produeed peak pore volumes
(retention ~olumes or Vpi) aceording to the following
equation:
Hi = (RVm) ( Vpi - Sg
where "So" is the oil saturation and "Sg" is the gas
saturation~
In order to obtain the responses of the partitioning
tracers in a reasonabl~ short time and get sufficient
separation of peaks, the best range of "Vpi" is 1.5 Sg to
5.0 Sg with corresponding "Hi" values of:
_ 1 RTZ So
Hl 5 ~ Vm ) ( Sg ) for Vpi = 6 Sg (4)
to
22658/16/1-1-1/MF
--10--
~ 32~7
Hi = 2 RTZ ( Sg ) for Vpi = 1.5 Sg (5)
Using a non-partitioning tracer, such as -tritium gas
or any raclioactive isotopes of light inert gases, in the
tracer slug is preferred. The non-partitioning tracer is
produced at Vpi = Sg, corresponding to an infinite Henry's
law constant. If, however, a non-partitioning tracer
cannot be identified, it can be substituked with a second
partitioning tracer having a Henry's law constant value
different from the Henry's law constant of -the first
tracer. If both tracers are partitioning, the tracers
must have a Henry's law constant such that the retention
volume of one tracer (Vpi~ is at least 1.5 times larger
than that of the other tracer.
Henry's law constant can also be estimated from the
vapor pressure (Poi) of tracer "i" at reservoir
tempera-ture or from equations of state. The
halo-hydrocarbon and halocarbon vapor pressure which is
always lower than the Henry's law constant can be improved
through khe use of Regular solution theory which can
par-tially account for the non-ideal behavior of
halo-hydrocarbon in oil.
Detection Limits of Halo-Hydrocarbons and
Halocarbons
Linearity of the response and detection limit can be
determined by measuring the ga~ chromatograph signals of a
series of samples prepared by successive dilu-tion of a
mi~ture of halo-hydrocarbons with reservoir gas. The
detection limit for a chemical is adversely affected by
possible interferences from the reservoir ~as, as well as
by the noise level of the detector. For any design to be
prac-tical, the detection limit of the chemical should be
lower than 1 ppm unless the sweep volume of the test zone
is ex-tremely small. In order to be detectable at the 1
ppm detection level, khe halv-hydrocarbon and halocarbons
should have at least ~ chlorine atoms or 1 bromine atom or
1 iodine atom.
22Ç58/16/1-1-1/MF
~ 3 2 ~ ~ ~ J
Detection Limits of Tritiated and Carbon 14 Ta~ge~
EIydrocarbons
A good separa-tion o:E individual tritia-ted and
carbon 14 -tagged hydrocarbons is essential for -the success
of the test. The most common means o~ separation is
preparative gas chromatography and, less commonly, low
temperature flashing. ~periments have to be carried out
to chec~ the separation of the selected tritia-ted and
carbon 1~ tagged hydrocarbons.
Description of the Method:
A mixture of at leas-t two tracers made up preferably
of a partitioning tracer, such as halo-hyclrocarbons,
halocarbons, or carbon 1~ tagged or tritia-ted hydrocarbons
and a non-partitioning -tracer, typically sulfur
hexafluoride, tritium gas or other radioactive isotopes of
inert gases, is injected into the formation with the
injection gas above the dew point. The mi~ture can be
injected as a slug, a spike, o:r continuously at low
concentration.
Tracers can be injected separately from cylinders
each of which contains a single tracer at or about its own
vapor pressure. Pumps are adjusted so that the tracers
are delivered to the injection line at the desired
proportions. The tracers are then vaporized and mixed
thorou~hly with the injection ~as whi~h is subse~uently
warmed to the reservoir temperature by an in~line heater.
Alternatively, the tracers can be premixed in a cylinder
and discharged to the injection line by a single pump. In
this mode of injection, however, a vapor-liquid phase
e~uilibrium calculation has to be carried out to study the
effect of differential liberation of individual tracers
during discharging. A fast injection rate may help
minimize the impac-t of differential liberation on the
process. Tracer injection time typically ranges from less
than an hour to continuous injection.
The production rates and injection rates should
remain as steady as possible throughout the -test.
Production rates do not have to be egual to the injection
22658/16/1-1-1/~`
~ 3 2 Q ~ ~ ~
ra-tes as long as the reservoir pressure is not
significantly changed by the unbalanced injection and
production. As a limiting case, the producers can be used
as observation-sampling wells where small but
representative samples are obtained wi-ch time. This zero
production rate has the merit o~ giving a non-disturbed
flow pattern which provides a reliable means o~
determining the permeability and permeability thickness
distribu-tion as well as sweep volume.
Produced gas samples are collected at a predetermined
freguency and analyzed for the tracers. If all the
tracers follow the various flow paths in similar
proportions, and the residual oil saturations are
identical along the various ~low paths, the residual oil
saturation can he determined by the chromatographic theory
shown below. If, however, either of these criteria is not
met, simulation must be used.
This method can be extended to the simultaneous
determination of three-phase saturations ~y including one
or more high vapor pressure oil-non partitioning/water-
participating and/or oil-partitioning/water-partitioning
tracers.
Data_I_terpretation
1. Chromatographi~ Th~ory
According to chromatographic theory:
Qi = Qs [1 t RTZ So ] (63
~iVm Sg
where "Qi" is the breakthrough volume for tracer "i" and
"Qs" is the gas volume in the flow path (sweep volume).
A plot o~ "l/Hi" versus "Qi" ~or the various tracers
yields a straight line. The slope of this line is used to
determine -the residual oil/gas saturation ratio, i.e.,
So/Sg. In order to solve for "So" and "Sg", at least one
o~ the following needs to be known.
(i.~ any saturation (i.e., Sw, So or Sg)i
(ii) any combin~tion o~ two saturations; or
(iii) porosity and sweep volume.
22658/16/1-1-l/MF
-13 ~ 3~ 7
Usually the breakthrough volume (Qi) is difficult -to
obtain. Instead one can use extrapolated break-through
volumes, peak volumes or half height volumes (i.e., volume
corresponding to half of the peak height) in the "1/Hi"
plo-t. It is usually mos-t convenient and most accurate to
use half height volume.
2. Simula-tion
Reservoir simulators capable of modeling sweep volume
can be employed to interpret -the results by matching the
entire tracer production profiles.
Example 1: Slimtube Test 1
Gas N2
Oil Tetradecane
Water 110,000 ppm brine
Tracers* CH4, F23, F22 and F12
Sg 0.63
So 0.~1
Sw 0.06
P 300 psi
T 22C
Example_2~_ Sl tube Test 2
Gas Pre-equilibrated reservoir gas
Oil Pre-equilibrated reservoir oil
Water 110,000 ppm reservoir brine
Tracers* F23, F22 and F12
S~ 0.42
So 0.36
Sw 0.22
P 600 psi
T 68C
*NOTE: Fl2 = dichloro-difluoro-methane
F22 = chloro-difluoro-methane
F23 = trifluoro-methane (fluroform)
22658/16/1-1-1/~
14- ~32~
By combinin~ equations ~2) and ~3~, it can be shown that:
Vpi = Sg + ~ Ai i Ai* } V~So (7)
Therefore, as shown in Figure 1 (Slimtube Test 1), and
Figure 2 (Slimtube Test 2), a plot of halowhydrocarbon
peak volume Vpi vs. reciprocal EIenry's law constant
(Ai - Ai*)/Ai* measured independently in a static test
yields a straight line with the slope given by:
~ (8)
Vo
From the above relationship, the residual oil saturations
are determined to be 31% and 36% which are in excellent
agreement with the experimental values of 32% and 36%,
respectively.
Example 3
A freon interwell test was carried out to determine
residual oil saturation in a gas-filled carbonate
reservoir located in Central Alberta, Canada. The
reservoir, which has an average porosity of 17%, was first
produced by primary depletion and then by gas-cycling
since 1953. The upper part o~ the reservoir has already
been gas-flooded down to residual oil saturation. The
reservoir pressure and temperature were 600 psi and 60C
respec-tively at the time of the tracer test. The tracer
test was conducted in a 2-SpQt (i.e., one injector and one
producer) unconfined pattern. The wells were 152 m apart
and an interval of 5 m was perforated for the test. ~he
test was run at steady state with the injection and
production rates maintained at 40,000 SCM/day and
7~,000 SCM/day, respectively, throughout the test.
To satisfy the vapor pressure and detection limit
re~uirement, SF6, F13B1 and F12 were selected for the
test. Some of the parame-ters for these tracers are listed
in Table 1.
22658/16/l-1-1/ME
~32~7
T~BLE 1
Parameters of the Tracers
SF6
Formula Sulfur Hexafluoride
~olecular Weight 146.07
v.p. @ 70F 310 psig
l/HEi 0.561
Detection Limit (lab) 0.2 ppb
F13Bl
Formula Bromo~trifluoro-methane
Molecular Weight 148.93
v.p. @ 70F 190 psig
l/HEi 2.13
Detection Limit (lab) 2 ppb
15 F12
Formula Dichloro-difluoro-methane
Molecular Weight 120.93
v.p. @ 70F 70.19 psig
1/~Ei 4.45
Detection Limi-t ~lab) 6 ppb
A slug of freons composed of 5.6 Kg of SF6, 17.4 Kg oE
F13B1 and 33.6 Kg of F12 was injected with dry gas at the
specified injection rate and gas samples were collected
from the pro~ucer 4 times ~ day using an automatic
sampler. The samples were subsequently analyzed. From
the production profile o~ the most volatile component SF6,
there appear to be 3 layers (or flow paths) contributing
approximately 20%, 30% and 50% to the flow.
The production curves for SF6, F13B1 and F12 are
plotted in Figure 3 for comparison. It is noted that the
production curves for F13Bl and F1~ are "delayed"
fingerprints of the SF6 profile, every detail of which is
preserved in the production curves of the two higher
boiling tracers. Because of fre~uent sampling, the
hreakthrough times were found exactly to be 4.4 days, 5.1
days and 6.1 days for SF6, F13B1 and F12, respectfully, as
would be expected from their Henry's law constan-ts. The
2265~/16/1~ MF
-16 ~ 3 ~ 7
cumulative recoveries for the three tracers were
transposed to a recovery-tracer profile (i.e., "landmark")
cross-plot indicated in Figure 4. I-t can be shown in the
cross-plot tha-t recovery correlates well with -the con-tour
of the tracer produc-tion profile, i.e., the "landmark."
For instance, a cumulative recovery of 18% corresponds to
the peak positions (i.e., peak C) of -the three tracer
curves. Therefore, when determininy residual oil
saturation by the chromatographic -theory technique either
"landmark," e.g., breakthrough time and peak -times, or
equal recovery time can be used for comparison.
For constant injection and production rates, Equation
(6) can be written as:
ti = to*[1 ~ So/(HEi*Sg~] (9)
where "ti" and "to" are the production times for the
partitioning tracer "i" and the non-partitioning tracer at
a given cumulative recovery or "landmark," and "HEi" is
the effective Henry's law constant defined as:
HEi = Hi*Vm/(RTZ) (10)
Therefore, a plot of "l/HEi" versus "ti" for the three
tracers would yield a straight line from the slope and
intercept of which the oil to gas saturation ratio (So/sg)
can be determined. "So" can -then be solved explicitly if
connate water satura-tion is known. To demonstrate the
chromatographic method, "l/HEil' is plotted against "ti" in
Figure 5 at five cumula-tive recoveries of 0%, 2%, 9%, 18%
and 22.5% which correspond to breakthrough, peak A,
peak B, peak C and late production respectively. It is
found that, as predicted by Equation (9), -the three
tracer points fall on a straight line for each of the five
recovexies with the corresponding residual oil saturations
determined to be 9%, 7%, 15%l 19% and 20% at an estimated
connate water saturation of 8%. Residual oil saturations
measured at various cumulative recoveries from
?2658/l6/1-1-1/MF
-17~
breakthrough -to 40% are plotted in Figure 6 with arrows
indicating the peak posi-tions. The variation oE residual
oil saturation with recovery is due to the overlapping of
three layers with different residual satura-tions, i.e., 7%
for peak A, 15% for peak B and 20% for peak C. Residual
oil saturation reaches a constan-t level of 20% in late
production where layer C domina-tes the tracer production.
All the above observations, i.e.,
1. Recovery correlates with the contour of the
production profile ('!landmar~"),
2. The "HEi" vs. "ti" plot yields a straight line
at various recoveries,
3. Residual oil saturation reaches a constan-t value
at late production,
demonstrate that chromatographic theory and the "landmark"
comparison technique in -this case accurately estimate
residual oil saturation ~rom the tracer profiles, and thus
simulation is no-t necessary.
A dual-porosity mixing cell model was used to check
the validity of -the "landmark" comparison techni~ueO The
simulation results indica-te that only under a
pseudo-single porosity situation, i.e., no non-flowing
fraction or extremely fast or extremely slow mass transfer
between flowing and non-~lowing fractions, will -the above
phenomena be ohserved. For a real double-porosity system
wi-th an intermediate ma~s transfer rate, the peak tends to
give the residual oil saturation in the flowing fraction
and, as the mass transfer rate increases, the pore-average
xesidual oil saturation, whereas the late produc-tion tends
to give the non-flowing oil saturation. For such a
system, irregularities may be encountered in using the
chromatographic technique to calculate ~'Sor". Also, the
non-flowing oil saturation cannot be accurately measured
even if a dual porosity simulator is used for profile
matching. From the simulation results in this case, it
would appear that this carbona-te reservoir behaves as a
single porosit~ reservoir.
The prînciple of the invention, a detailed
description of one specific application of the principle,
22658/16/1-1-1/MF
-18- ~32~
and the best mode in which it ls contemplated to apply
that principle have been described. I-t is to be
understood that the foregoing is illustrative only and
that other means and -techniques can be employed without
departing from the true scope of the invention defined in
the follow.ing claims.
22658/16/l-1-l/ME
