Note: Descriptions are shown in the official language in which they were submitted.
200~479
T 8339
PROCESS FOR RECOVERING OIL
This invention relates to a surfactant-enhanced gas flooding
process in which a surfactant solution and a gas are used to form a
gas foam in an underground reservoir to displace oil through the
r~servoir in order to recover oil from the reservoir. The
surfactants used are enriched in olefin disulfonate.
Several techniques have been used to enhance the recovery of
hydrocarbons from subterranean reservoirs in which the hydrocarbons
no longer flow by natural forces. One such technique is water
injection, or water flooding, to force hydrocarbons from the
subterranean reservoir by flowing water through the formations.
Another technique is the use of gas injection, which also functions
to force hydrocarbons from the subterranean formation. Gas
flooding for oil recovery is frequently used subsequent to water
flooding. To enhance the effectiveness of gas flooding, a miscible
gas may be used to swell and reduce the viscosity of oil present in
the formation.
Due to the low viscosity of gas, it will finger or flow
through the paths of least resistance, thus bypassing significant
portions of the formation, and resulting in early breakthrough at
the production well. Also, due to its low density, the injected
gas tends to rise to the top of the formation and "override"
portions of the formation. The mobility of the injected gas,
combined with variations in reservoir permeability, often results
in an irregular injection profile. All of these factors may result
in lower hydrocarbon recovery.
The overall efficiency of a gas flooding process can be
improved with the addition of a foaming agent or surfactant which
is introduced directly into the reservoir by means of a water or
brine vehicle prior to injection of the gas. The surfactant should
have sufficient foaming ability and stability to satisfactorily
2QO~479
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reduce mobility of the gas, thereby reducing its tendency to
channel through highly permeable fissures, cracks, or strata, and
directing the gas toward previously unswept portions of the
formation. The surfactant should also be chemically and thermally
stable and soluble in the aqueous phase present under reservoir
conditions.
It is an object of this invention to provide an improved gas
foam flooding surfactant by which lower residual oil saturation
levels are achieved. Another object of this invention is to
provide an improved gas foam flooding surfactant which achieves
sweep efficiencies better than those which may be obtained through
use of commercially available olefin sulfonate surfactants.
To this end the present invention relates to a process for
recovering oil from a reservoir penetrated by at least one
injection well comprising injecting into the reservoir a gas-foam
forming mixture comprising an aqueous surfactant solution and a gas
mixture including a noncondensible gas, displacing within the
reservoir the gas foam-forming mixture, and withdrawing oil from
the reservoir, wherein the surfactant contains at least 25 wt%
olefin disulfonate.
The process according to the invention is applicable to gas
soak operations, wherein injection of gas foam-forming mixture and
subsequent production of oil from the reservoir are done using the
same injection well(s).
The process according to the invention is applicable to steam
drive operations, wherein injection of gas foam-forming mixture is
done using injection well(s), and wherein production oil from the
reservoir is done using at least one separate production well. To
this end the reservoir is further penetrated by at least one
production well.
Relative to conventional olefin sulfonate surfactants,
disulfonate-enriched surfactants with properly selected carbon
number ranges produce a lower interfacial tension in the presence
of oil, provide a foam of comparable strength, propagate at least
as quickly, and reduce residual oil saturation to lower levels.
2Q0~9
Surfactants enriched in olefin disulfonate include those which are
specifically prepared to contain high concentrations of
disulfonates, as well as formulations or mixtures of disulfonate
and other olefin-derived surfactants.
Disulfonate-enriched gas foam mixtures include an aqueous
surfactant solution, a substantially noncondensible gas, and
optionally include an aqueous solution of electrolyte, with each of
the components being present in amounts effective for gas foam
formation in the presence of reservoir oil. The use of
disulfonate-enriched gas foam surfactants and foamable mixtures in
gas foam flooding operations is also described.
The present invention is, at least in part, based on a
discovery that the presently described novel olefin
disulfonate-enriched gas foam surfactants provide unobvious and
beneficial advantages in a gas foam drive process. For example,
where the gas foam mixture contains a disulfonate-enriched
surfactant, a noncondensible gas and an electrolyte, in proportions
near optimum for foam formation in the presence of oil, the new
surfactants, relative to previously known, commercially available
olefin sulfonate surfactants, provide lower interfacial tension
with oil, move substantially as quickly through the reservoir, and
form a gas foam of comparable strength. Also, the presently
described surfactants provide significantly lower residual oil
saturation, at concentrations which are comparable to those
required for equal mobility control by the surfactants which have
been considered to be among the best available for such purpose.
The novel gas foam mixtures described are useful for both a
gas drive and a gas soak process. Of particular interest in this
respect are gas foam mixtures containing (a) a surfactant component
present in the liquid phase of the mixture in an amount between
about 0.01 and about 10 wt~ (calculated on the weight of the liquid
phase), said surfactant component comprising in substantial part
olefin disulfonate, and (b) a noncondensible gas. Suitably the
amount of surfactant is between 0.05 and 5.0 wt~. Preferably, an
2Q05479
electrolyte may be present in the liquid phase of the mixture in an
amount between about 0.01 and about 15 wt% or more.
The present surfactant compositions are significantly
different from those prepared by conventional manufacturing
processes for alpha or internal olefin sulfonates because their
surfactant component is substantially enriched in olefin
disulfonates. Although increased disulfonate concentration for a
given carbon chain length can result in a less effective steam foam
surfactant, the combination of an increase in carbon chain length
(such as an increase in median carbon number from 17 to 22), and an
increase in disulfonate concentration, has been found to result in
an improved gas foam surfactant. Because of this, the present
compositions are capable of forming gas foams which reduce gas
mobility significantly more, and produce residual oil saturations
significantly less, than commercially available gas foam
surfactants.
The surfactant component of the mixture is an olefin
sulfonate, prepared or formulated to have a disulfonate content
higher than what is currently typical in commercially available
olefin sulfonate compositions. In the past, standard commercially
available alpha olefin sulfonates have contained up to 15 wt%
disulfonates. However, since the presence of disulfonates has been
viewed as undesirable in these surfactants, manufacturers have
consciously reduced the disulfonate concentrations in alpha olefin
sulfonate products, and currently available alpha olefin sulfonates
typically contain no more than 5-7 wt% disulfonates.
The olefin sulfonates suitable for use in the present
invention are preferably derived from a particular class of
olefins, which may be defined for present purposes in terms of the
number of carbon atoms in their molecular structure. These olefins
have a carbon number in the range of from about 16 to about 40,
preferably in the range of from about 18 to about 36, more
preferably in the range of from about 20 to about 32, and most
preferably in the range of from about 20 to about 28. Either
alpha, internal, or vinylidene olefins are considered suitable for
200~;479
use in the invention. Particularly suitable for purposes of the
~ invention is an olefin sulfonate derived from substantially linear
alpha-olefins or internal olefins. Olefin sulfonates derived from
branched chain alpha-olefins or internal olefins are also suitable
for purposes of the invention, provided the chain branches are no
more than about two carbon atoms in length.
For preparation of olefin sulfonates, the olefins as described
above are subJected to reaction with sulfur trioxide (S03). The
term "sulfur trioxide" is intended to include any compounds or
complexes which contain or yield S03 for a sulfonation reaction as
well as S03 per se. This reaction may be conducted according to
methods well known in the chemical arts, typically by contact of a
flow of dilute S0 vapor with a thin film of liquid olefin at a
temperature in the range of about 35~ to about 75~C. The
sulfonation reaction between the S0 and the olefin yields a crude
product, cont~inine alkene sulfonic acids, and an intermediate,
believed to be in the nature of a sultone. The sultone is
subsequently hydrolyzed by reaction with water and neutralized by
reaction with base, preferably an alkali or alkaline earth metal
hydroxide, oxide, or carbonate. Although the composition of the
sulfonate product varies somewhat depending on a number of factors,
particularly the nature of the olefin and the sulfonation reaction
conditions, where sodium hydroxide is used as the base, the four
principal components are usually alkene sulfonic acid sodium salts
(about 50 to 70 wt%), hydroxy-alkane sulfonic acid sodium salts
(20-40 wt%), and alkene and hydroxy-alkane disulfonic acid disodium
salts (5-15 wt%). The two sulfonic acid sodium salts may be
characterized as monosulfonates, and the two disulfonic disodium
salts may be characterized as disulfonates. Conventional
manufacture typically yields as the surfactant product an aqueous
solution of the olefin sulfonates, for example, a 30 wt~ solution
in water. Such solutions, after dilution with water or brine, may
be directly applied to the preparation of gas foam mixtures for
purposes of this invention.
2QO~479
The disulfonate content of the surfactant product can be
increased by increasing the ratio of dilute S03 vapor to liquid
olefin in the sulfonation reaction. Typical olefin sulfonate
processes employ an S03/olefin mole ratio of 0.90 to 1.15.
S03/olefin ratios greater than 1.15 can be used to prepare olefin
sulfonate mixtures that are suitably enriched in disulfonates. In
a commercial facility, it may be desirable to recycle the unreacted
dilute S03 vapor. Also, recycle of the sulfonated olefin product
back through the sulfonation process will provide enriched
disulfonate compositions at lower S03/olefin ratios in the reaction
step. Olefin sulfonate compositions suitable for use in the
present invention have a disulfonate content of from about 25 to
about 100 wt%, preferably from about 30 to about 100 wt%, more
preferably from about 40 to about 100 wt%, and most preferably from
about 50 to about 100 wt%.
The water used in the present compositions and/or process can
be any aqueous liquid that is compatible with, and does not
significantly inhibit, the foam-forming properties of the gas foam
mixtures of the present invention. Fresh water may be used, but
where large quantities of water are to be injected, brine is
preferred, particularly a brine produced from the same reservoir.
Ideally, the quantity of water present should be sufficient to
allow the surfactant solution to form a foam when mixed with the
gas. The water can contain salts and other additives which enhance
its properties, such as scale inhibitors and the like.
In general, the noncondensible gas used in a gas foam mixture
of the present invention can comprise substantially any gas which
(a) undergoes little or no condensation under reservoir conditions,
and (b) is substantially inert to and compatible with the
surfactant and other components injected along with the gas. Such
a gas is preferably nitrogen, but can comprise other gases, such as
air, carbon dioxide, carbon monoxide, ethane, methane, flue gas,
fuel gas, or the like. The noncondensible gas may be present in
the gas foam mixture at a concentration of from about l to about
100 mol% of the gaseous phase of the mixture.
2QO~479
The presence in the gas foam mixture of an electrolyte may
enhance the formation of a foam capable of reducing residual oil
saturation. Some or all of the electrolyte can comprise an
inorganic salt, preferably an alkali metal salt, more preferably an
alkali metal hslide, and most preferably sodium chloride. Other
inorganic salts, for example, halides, sulfates, carbonates,
bicarbonates, nitrates, and phosphates, in the form of salts of
alkali metals or alkaline earth metals, can be used. The presence
o~ an added electrolyte may be unnecessary where the water
injected, or the connate waters present in the reservoir, contain
enough electrolyte to form an effective foam.
The gas foam mixture is formed by co-injecting noncondensible
gas and surfactant solution cont~ining a concentration of from
about O.01 wt% to about 10 wt% active surfactant into an injection
well. Preferably, the surfactant solution contains a concentration
of from about 0.05 wt% to about 5 wt% active surfactant, and more
preferably, the surfactant solution contains a concentration of
from about 0.05 wt% to about 2 wt% active surfactant. Most
preferably, the surfactant is injected in as small an amount as
possible to adequately enhance oil recovery. As an alternative,
the gas foam mixture may be formed by sequentially injecting
surfactant solution followed by noncondensible gas. An aqueous
electrolyte solution may be incorporated into the gas foam mixture,
preferably by combining the electrolyte solution with the
surfactant solution.
Any standard method of creating a gas foam is suitable for use
in the invention. Sufficient water or brine must be included in
the gas foam mixture and/or present in the formation to produce an
effective gas foam within the reservoir. Under some circumstances,
a sand-filled line may be used to initiate foam. The gas foam
mixture is injected into the reservoir at a rate determined by
reservoir characteristics and well pattern area. The injection and
production wells can be arranged in any pattern. Preferably, the
injection well is surrounded by production wells, however, the
invention is also applicable to a gas soak (single well) process.
20054~9
- 8
Following injection of the gas foam mixture, a combination of
aqueous and/or gaseous drive fluids are injected. The aqueous
drive fluid may be water or brine or the like. The gaseous drive
fluid may be any noncondensible gas. In one possible mode of the
present process, injection of the gas foam mixture is followed by
displacement with additional gas. Alternatively, in;ection of the
gas foam mixture may be followed by injection of additional water
or brine, and subsequently followed by injection of additional
noncondensible gas. Alternating slugs of gas and water or brine
may also be used for displacement.
In a gas foam drive process, the in;ection and initial
displacement of the gas foam mixture within the reservoir creates a
foam which is driven through the formation and towards a production
well. Oil and other produced fluids are recovered from production
wells until the gas/oil recovery ratio becomes uneconomically high.
The amount of displacement fluid injected relative to the amount of
gas foam mixture injected is determined by reservoir size, well
spacing, and various reservoir properties.
In a gas foam soak process, injection and production occur at
a single well. Injection of the gas foam mixture is followed by a
soak phase, in which the well is shut in to allow the gas present
in the foam to contact and swell the oil and/or reduce its
viscosity. Preferably, the gas used is at least partially miscible
with the oil present in the reservoir under reservoir conditions.
After the soak period, the well is placed in production to recover
oil and other fluids from the reservoir. Optionally, initial
injection of the gas foam mixture may be followed by injection of a
drive fluid to displace the gas foam mixture some additional
distance from the well before the soak phase occurs.
Having discussed the invention with reference to certain of
its preferred embodiments, it is pointed out that the embodiments
discussed are illustrative rather than limiting in nature, and that
many variations and modifications are possible within the scope of
the invention. Many such variations and modifications may be
considered obvious and desirable to those skilled in the art based
2QO~479
upon a review of the foregoing description of preferred embodiments
and the following experimental results.
Experiments were conducted to measure (l) interfacial tension
(to be referred to as IFT) of surfactant mixtures against oil, (2)
relative foam strength, (3) surfactant propagation, or transport
rate, and (4) residual oil saturation (to be referred to as ROS)
after low rate nitrogen flooding, all with surfactant mixtures
cont~inine various combinations of monosulfonated and disulfonated
olefins.
The surfactants evaluated are listed in Table l. Three
methods were used to prepare disulfonate-enriched surfactants for
laboratory evaluation: (l) high SO3/olefin ratio, (2)
filtration/separation, and (3) blending.
Some disulfonate-enriched surfactants were formed by
increasing the SO3/olefin ratio in the sulfonation reaction step.
Sulfonation reactions have been performed at SO3/olefin ratios as
high as 7.0, and products cont~ining as much as about 84 wt~
disulfonate resulted. However, limited data suggest that an
increase in SO3/olefin ratio above about l.8 may not provide
substantial further improvement in surfactant characteristics,
apparently due to the presence of small amounts of byproducts
formed at higher SO3/olefin ratios. Commercial scale production of
surfactants may require somewhat different SO3/olefin ratios to
produce surfactants with a given wt% disulfonate.
The isolation of high purity alpha olefin disulfonates from
alpha olefin sulfonates (to be referred to as AOS) can be
accomplished by physically separating (by filtration) the liquid
and semi-solid emulsion phases of the AOS product, where the median
carbon number range is greater than 20. A sample of AOS 2024, with
a nominal carbon number range of 20 to 24 and which overall
contained 17 wt~ disulfonate, was found to contain 98 wt~
disulfonate in the liquid phase, but only about 2 wt% disulfonate
in the semi-solid emulsion phase of the surfactant. Internal
olefin sulfonate surfactants, and alpha olefin sulfonates with
carbon numbers less than 20, were found to have no such distinction
between the liquid and semi-solid emulsion phases. Another
ZO(~5479
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disulfonate enriched surfactant was formed by blending the 98 wt~
disulfonate surfactant with the original AOS 2024 to give a
surfactant with 65 wt~ disulfonate (to be referred to as AODS
2024).
The base case surfactant used for comparison in all
experiments was ENORDET (Registered Trade Mark) AOS 1618, a
co~mercially manufactured AOS available from Shell Chemical
Company, with a nominal carbon number range of 16 to 18. A few
experiments were also conducted with CHASER (Registered Trade Mark)
SD1000, a commercially manufactured AOS dimer available from
Chevron Chemical Company, with a n~ inAl carbon number range of 22
to 32, and with a weight ratio of monomer AOS to dimer AOS of
48/52. The CHASER (Registered Trade Mark) product is derived from
alpha olefins in a reaction sequence that is different from that
used to produce AOS. The AOS dimers are produced by sulfonating
alpha olefins using typical olefin sulfonation conditions, heating
the sulfonated product to cause dimerization in a separate reaction
step, and then neutralizing the dimerized product. This process is
described in U. S. Pat. No. 3,721,707.
2(:~0~,~79
TABLE 1
SURFACTANT COMPOSITION
Sulfonation Additional Average Approximate Wt%
SO3/Olefin Preparation Molecular Monosulfonate/
Surfactant Mole Ratio Steps WeightDisulfonate
ENORDET ) AOS 1618 1.15 None 356 89/11
AOS 2024S 1.15 Filtration 427 98/2
AOS 2024T 1.15 None 407 95/5
AOS 2024R 1.15 None 413 93/7
AOS 2024 1.15 None 441 83/17
AOS 2024E 1.8 None 469 58/42
AOS 2024C 1.15 Filtration 455 58/42
AOS 1618E 2.3 None 402 39/61
AOS 2024B 1.15 Filtration 476 35/65
and Blending
AODS 2024 1.15 Filtration 526 2/98
CHASER ) SDlO00 1) Dimerization 616
1) U. S. Pat. No. 3,721,707 specifies a ratio of 1.2.
2) Registered Trade Mark
The IFT experiments were conducted with the use of a
University of Texas Model 500 Spinning Drop Interfacial
Tensiometer. The tests were conducted at 75~C, using 0.5 wt%
surfactant solutions, with and without 3 or 4 wt% NaCl. The oil
phase was either decane (a refined oil), Patricia Lease crude from
the Kern River field, Kernridge crude from the South Belridge
field, or crude from the Midway Sunset field (all heavy California
crude oils). It has been found that stable readings for crude oils
may be obtained over a shorter time period if the aqueous phase
(containing surfactant, with or without salt) and oil phase are
equilibrated under the test conditions prior to determination of
the IFT. Consequently, when crude oils were used as the oil phase,
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the oil and surfactant solutions were first equilibrated overnight.
For decane, the tensiometer tube was first filled with the
surfactant mixture, and then 3 microliters of oil were added. For
crude oils, first the tensiometer tube was rinsed with the
surfactant mixture (to prevent the viscous oil from sticking to the
tube), next 0.005 grams of oil was weighed into the tube, and then
the tube was filled with the surfactant mixture. Once the oil
droplets were stabilized in the tensiometer, measurements were made
to allow calculation of the IFT.
One atmosphere foaming experiments were used as an indication
of relative foam strength. The tests were conducted at a
temperature of 75~C, using 0.25 wt% surfactant solutions in
deionized water. The surfactant solution (10 cc) was placed in a
25 cc graduated cylinder, and then the hydrocarbon phase (3 cc) was
added. Hydrocarbons used included decane, and a 3:1 volume blend
of decane and toluene. The headspace of the cylinder was flushed
with nitrogen, the cylinder was then sealed and shaken, and then
the samples were equilibrated at the test temperature for 24 hours.
After temperature equilibrium, samples were carefully shaken for
one minute. Foam volume (cc) was then determined as a function of
elapsed time from the end of foam generation.
Foam propagation and ROS experiments were conducted by flowing
a gas foam mixture through an oil-cont~ining sand pack. A typical
sand pack test apparatus consists of a cylindrical tube, about 1.0
inch in diameter by 12 inches long. Such a sand pack may be
oriented either horizontally or vertically. The sand pack is
provided with at least two pressure taps, which are positioned so
as to divide the pack approximately into thirds. At the inlet end,
the sand pack is preferably arranged to receive separate streams of
noncondensible gas and one or more aqueous liquid solutions
containing a surfactant to be tested and/or a dissolved
electrolyte. Some or all of those components are injected at
constant mass flow rates, proportioned so that the mixture will be
homogeneous substantially as soon as it enters the face of the sand
pack. The permeability of the sand pack and foam debilitating
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properties of the oil in the sand pack should be at least
substantially equivalent to those of the reservoir to be treated.
By means of such tests, determinations can be made of the
proportions of surfactant, noncondensible gas, and electrolyte
components which are needed in order to provide the desired
treatment.
For the experiments described below, the sand packs were
prepared by flooding them with Kernridge oil, a heavy California
c'rude, at a temperature of about 300~F, to provide oil saturations
in the order of 80 to 90% of the pack pore volume. Waterfloods
were conducted to reduce the oil saturations to residuals of about
30% of the pack pore volume. For the surfactant propagation
experiments, the sand packs were flooded with synthetic connate
water. For the ROS experiments, distilled water was used for the
waterflood. The surfactant propagation experiments were conducted
with sand packs containing Kernridge sands at 280~F and a
backpressure of 100 psig (the corresponding steam saturation
temperature at this pressure is 338~F). Surfactant was injected
continuously into the pack at 1.6 ft/day, without co-injection of
gas. The ROS experiments were conducted in sand packs cont~inine
Ottawa sands, at a temperature of 280~F with a backpressure of 70
psig, and at a temperature of 300~F and a backpressure of 110 psig.
Surfactants which provide low IFT, and hence greater oil
recovery, are desirable. Results from the IFT experiments,
compared with a base case of ENORDET (Registered Trade Mark) AOS
1618, are shown in Table 2 and may be summarized as follows. The
IFT values for ENORDET (Registered Trade Mark) AOS 1618 decreased
with the addition of NaCl, in place of fresh water, and are lower
for Patricia crude from the Kern River field than for decane. The
IFT of AOS 2024 (about 17 wt% disulfonate), under similar
conditions, was lower. This reflects the fact that as carbon
number increases, IFT will decrease. IFT of AODS 2024 (about 98
wt% disulfonate) was also lower than the values for ENORDET
(Registered Trade Mark) AOS 1618, but slightly higher than the
values for AOS 2024. This shows that at constant carbon number,
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the IFT increases with increased disulfonate. It is concluded from
these results that an increase in carbon number can more than
offset the IFT reduction caused by significantly increasing the
disulfonate content of the sur~actant.
TABLE 2
INTERFACIAL TENSION (IFT) STUDIES )
Aqueous Oil IFT
Surfactant Phase Phase dynes/cm
ENORDET ) AOS 1618 fresh waterdecane 4.7
ENORDET ) AOS 1618 3~ NaCl decane 1.9
ENORDET ) AOS 1618 3% NaClKern River ) 0.6
AOS 2024S fresh water decane 3.3
AOS 2024T 4% NaCl Kern River ) 0.10
AOS 2024T 4% NaCl So. Belridge ) 0.08
AOS 2024T 4% NaCl Midway Sunset 0.06
AOS 2024 fresh water decane 3.2
AOS 2024 3% NaCl decane 0.59
AOS 2024E 3% NaCl Kern River ) 0.3
AOS 2024E 4% NaCl Kern River ) 0.55
AODS 2024 fresh water decane 3.8
AODS 2024 3% NaCl decane 1.3
AODS 2024 3% NaCl Kern River ) 0.17
CHASER ) SD 1000 fresh water decane 6.8
CHASER ) SD 1000 3% NaCl decane 4.0
CHASER ) SD 1000 fresh water Kern River ) 1.9
CHASER ) SD 1000 3% NaCl Kern River ) 0.77
1) All tests were conducted at 75~C.
2) Patricia Lease crude.
3) Kernridge crude.
4) Registered Trade Mark.
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.,
- 15 -
Surfactants which provide a strong foam are effective at
reducing gas mobility, and may also produce a lower ROS in the
reservoir. Foam height values, obtained from simple shAking
experiments, can be used as an indication of foam strength.
Results from the foam height experiments, compared with a base case
of ENORDET (Registered Trade Mark) AOS 1618, are shown in Table 3.
These experiments were conducted at a representative reservoir
temperature of 75~C.
The results shown in Table 3 may be summarized as follows. In
the presence of no oil, the foam strength of the disulfonate-
enriched surfactants is clearly better than that of ENORDET
(Registered Trade Mark) AOS 1618. In particular, AOS 2024E (42 wt%
disulfonate) still has a foam volume of 15.2 cc after 10 minutes,
compared with an ENORDET (Registered Trade Mark) AOS 1618 foam
volume of 5 cc. In the presence of a highly aliphatic oil phase
(decane), the AOS 2024E (42 wt% disulfonate) has both a higher
initial foam volume (18 cc), and a higher volume at 10 minutes (9
cc), than the ENORDET (Registered Trade Mark) AOS 1618 (16.8 cc and
6.8 cc).
In the presence of an aromatic oil phase, the initial value
(17.4 cc) for AOS 2024E (42 wt% disulfonate) is comparable to that
for ENORDET (Registered Trade Mark) AOS 1618 (17.6 cc). However,
subsequent values indicate that the ENORDET (Registered Trade Mark)
AOS 1618 may have a stronger foam in the presence of aromatic oils
than the AOS 2024E (42 wt% disulfonate). These results demonstrate
that the type of oil present in the reservoir must be considered
when selecting an appropriate gas foam surfactant.
It may be concluded that, in reservoir sections with low
residual oil levels, where gas foam must have its greatest
strength, the AOS 2024E (42 wt~ disulfonate) should form a stronger
foam than ENORDET (Registered Trade Mark) AOS 1618.
Z ~ O J 4 ~ 9
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TABLE 3
RELATIVE FOAM STRENGTH STUDIES
Oil Foam Volume after X minutes, X -
Surfactant Phase1.0 5.0 10.0 30.0
ENORDET ) AOS 1618 None 18.4 16.0 5.0 0.0
AOS 2024R None17.4 16.2 13.2 3.2
AOS 2024 None16.4 15.2 12.2 2.0
AOS 2024E None18.4 17.2 15.2 2.0
ENORDET ) AOS 1618 Decane 16.8 14.8 6.8 1.4
AOS 2024R Decane 15.4 14.6 12.2 4.8
AOS 2024 Decane 16.2 9.2 1.6 0.4
AOS 2024E Decane 18.0 14.0 9.0 1.2
ENORDET ) AOS 1618 D/Tl) 17 6 16.8 15.8 3.4
AOS 2024R D/T )15.6 14.8 12.6 4.8
AOS 2024 D/T )9.8 9.6 6.4 1.8
AOS 2024E D/T )17.4 13.8 8.4 0.8
1) Mixture of 3 volumes decane to 1 volume toluene.
2) Registered Trade Mark
Surfactants which exhibit a fast rate of propagation, or
transport, through the reservoir can be effective at sustAinine the
gas foam in a gas foam drive operation. Results from the
surfactant propagation rate experiments, compared with a base case
of ENORDET (Registered Trade Mark) AOS 1618, are shown in Table 4.
The sand pack effluent was analyzed for surfactant, calcium, and
chloride. Surfactant retention was calculated from an integration
of the surfactant and chloride breakthrough curves. These
experimentally determined surfactant retentions, in pore volumes
2~0~479
(PV), were used in the calculations to determine surfactant
propagation rates which surfactant propagation rate is l/(Sw +
surfactant retention). The normalized surfactant propagation rate
is obtained by dividing the surfactant propagation rate by the base
case surfactant propagation rate in which Su 0.30 (or 30% of the
pore volume) and the surfactant retention is 0.80 (or 80% of the
pore volume). The normalized surfactant propagation rate is thus
(0.30 + 0.80)/(Sw + surfactant retention). In the experiments Sw =
0.30 for the Kern River field. It may be assumed that foam
propagation rate is comparable to the surfactant propagation rate.
The results given in Table 4 can be summarized as follows. At
about 0.5 wt% surfactant concentration and 4 wt% sodium chloride,
the AOS 2024E (42 wt% disulfonate) propagated more rapidly than the
ENORDET (Registered Trade Mark) AOS 1618 (11 wt% disulfonate),
despite the higher carbon number range of AOS 2024E. By
interpolation, the AOS 2024E, at a concentration of about 0.44 wt%
with 4 percent sodium chloride, would propagate as fast as a 0.5
wt% ENORDET (Registered Trade Mark) AOS 1618 composition. It can
be concluded that the disulfon&te-enriched surfactants with
increased carbon number can propagate through the reservoir
substantially as quickly as the base case ENORDET (Registered Trade
Mark) AOS 1618.
ZQ0~479
- 18 -
TABLE 4
SURFACTANT PROPAGATION EXPERIMENTS WITH
KERNRIDGE SAND PACKS
Normalized
Wt~ Wt% Surfactant Pro-
Surfactant Surfactant NaCl pa~ation Rate
ENORDET ) AOS 1618 0.50 4 1.63
AOS 2024 0.50 2 0.69
AOS 2024E 0.35 4 1.11
AOS 2024E 0.50 4 1.92
AOS 1618E 0.50 4 1.54
AOS 2024B 0.20 4 0.83
AOS 2024B 0.50 4 1.32
1) Registered Trade Mark
Low rate nitrogen foam experiments were performed to determine
whether foam formed at high flow rates near the wellbore could
propagate at much lower flow rates far away from the injection
point, and to determine ROS values after gas flooding. The first
experiment was conducted at 280~F with a backpressure of 70 psig.
An Ottawa sand pack was initially saturated with Kernridge crude
and then waterflooded to an ROS of 26 percent. Two pore volumes of
0.5 wt% of AOS 2024E (42 wt% disulfonate) with 4 wt% NaCl were
injected. Nitrogen and additional surfactant formulation were
injected through an oil-free sand-filled line (used to enhance foam
generation) and then into the sand pack. For most of the
experiment, gas and liquid superficial velocities were 21 and 0.66
ft/day, respectively, in the sand pack and 144 times larger in the
sand filled line. Gas fractional flow was near 0.97.
Results of this experiment can be summarized as follows. Foam
generated at high rates in sand filled lines propagated at much
lower rates in the sand pack. This was evidenced by the rise in
Z0~5~79
pressure gradient with time. Even at these low flow rates, foam
produced a very high pressure gradient inside the sand pack. At
the end of the experiment, after opening the sand pack and
extracting the oil from the sands, it was found that foam had
propagated five inches into the 12-inch long sand pack, and that a
two-inch oil bank was ahead of the foam. Oil saturation was 0% in
the foam-swept region, 22% in the oil bank, and 15% ahead of the
oil bank. The average residual oil saturation was reduced from 26%
t~ 11% within the sand pack.
Additional experiments were conducted at 300~F with a
backpressure of 110 psig and a superficial gas velocity of 12
ft/day to simulate conditions far away from the wellbore. The
Ottawa sand packs were again saturated with Kernridge crude, then
waterflooded to an ROS of 26%. No sand-filled line was used.
The results of these experiments, shown in Table 5, may be
summarized as follows. At a concentration of about 0.5 wt%
surfactant, the AOS 2024E (about 42 wt% disulfonate) achieved a ROS
of 4.5%, significantly lower than the 13.5% achieved with the
ENORDET (Registered Trade Mark) AOS 1618 at 0.5 wt%. Increasing
the AOS 2024E concentration to 1.27 wt% provided no further ROS
reduction. This indicates that the disulfonate-enriched
surfactants can achieve lower ROS values than typical alpha olefin
sulfonate surfactants.
TABLE 5
ROS IN LOW RATE NITROGEN FOAM EXPERIMENTS
Wt% Wt% ROS
Surfactant Surfactant NaCl % PV
ENORDET ) AOS 1618 0.50 4 13.5
AOS 2024E 0.51 4 4.5
AOS 2024E 1.27 4 4.5
1) Registered Trade Mark
