Oil recovery process for stratified high salinity reservoirs

There is provided a process for improving oil recovery from stratified reservoirs by (1) injecting low saline water to reduce the salinity in high permeability zones, (2) injecting a surfactant solution into the high permeability zones, (3) injecting high salinity water into the reservoir, thereby forming a surfactant/water/oil emulsion which reduces effective brine permeability in the high permeability zones, and (4) continuing to inject high salinity water into the reservoir, whereby water is diverted to low permeability zones and oil is recovered from the low permeability zones. Low salinity water may then be injected to break-up or release the emulsion in the high permeability zones and to recover oil from the high permeability zones.

BACKGROUND OF THE INVENTION 
This invention relates to a process for improving oil recovery from 
stratified reservoirs. 
Brine-tolerant surfactants may be injected at a salinity such that viscous 
emulsions or microemulsions are promoted by mixing of surfactant solution 
with crude oil and formation brine. (Note U.S. Pat. Nos. 4,160,480; 
4,161,218; 4,161,982; 4,161,983; 4,165,785; 4,184,549; 4,194,564; and 
4,307,782, the entire disclosures of which are expressly incorporated 
herein by reference.) For example, U.S. Pat. No. 4,307,782 teaches 
injection of surfactant solution at a salinity 5 to 20 percent below that 
necessary for partitioning greater than 50 percent of surfactant from 
brine solutions into an oil phase, or into an oil-water interface. In the 
process, the partitioning occurs when the lower salinity surfactant 
solution mixes with the higher salinity formation brine. It has been 
observed that these surfactants and emulsions formed from them are very 
difficult to propagate at salinities conducive to forming the 
microemulsion phases. The method proposed in U.S. Pat. No. 4,307,782 
depends upon injection of lower salinity brine to release phase trapped 
surfactant and emulsions--advancing them by a series of steps in which 
emulsions are formed in the front mixing zone, trapped, released by lower 
salinity drive, advanced, reformed by front mixing, etc. 
When brine tolerant surfactants, e.g., alkyl- and 
alkylarylpolyethoxysulfonates or sulfates, sometimes in combination with 
non-ionic surfactants or petroleum sulfonates, are injected into 
stratified reservoirs according to the teachings of the above-mentioned 
patents, emulsion phases are immediately formed which increase flow 
resistance in strata penetrated by them. Because high permeability strata 
accept relatively more of injected fluids, and because such surfactants 
and emulsion phases propagate more readily in high permeability zones, 
flow resistances are increased relatively more in the high permeability 
zones. 
An objective of this invention is to provide salinity control measures to 
(1) improve the rate and depth of penetration by surfactant/polymer 
solutions into high permeability zones, and (2) to retain viscous 
emulsions within the high permeability zones while subsequently injected 
waters are diverted into the lower permeability zones. 
SUMMARY OF THE INVENTION 
According to one aspect of the invention, there is provided an improved 
method for recovering oil from a subterranean formation having at least 
one high permeability zone and at least one low permeability zone, 
whereby, when water is injected into said formation through an injection 
means in a waterflood process, said water tends to channel through said 
high permeability zone or zones to a recovery means avoiding said low 
permeability zone or zones and leaving non-displaced oil in said low 
permeability zone or zones, the improvement for recovering oil comprising 
the steps of: 
(i) injecting into said formation a sufficient amount of relatively low 
salinity water having a sufficiently low salinity to reduce the salinity 
of the formation fluids of said high permeability zone or zones; 
(ii) injecting into said formation treated according to step (i) a 
surfactant slug, the salinity of said surfactant slug being sufficient to 
permit said surfactant to permeate into said high permeability zone or 
zones; and 
(iii) injecting into said formation treated according to step (ii) a 
relatively high salinity water slug having a salinity higher than the 
salinity of the surfactant slug of step (ii), whereby the following takes 
place: 
(a) the interaction of fluids in the high permeability zone or zones causes 
the high permeability zone or zones to become less permeable to said 
relatively high salinity water of step (iii), whereby such relatively high 
salinity water is diverted to said low permeability zone or zones; and 
(b) oil in said low permeability zone or zones is displaced towards a 
recovery means by said relatively high salinity water and is recovered at 
said recovery means. 
According to another aspect of the invention, there is provided a method 
for recovering oil from a subterranean formation by injecting fluid 
through an injection means and recovering oil-containing fluid through a 
recovery means, said formation having at least one high permeability zone 
and at least one low permeability zone, said method comprising the steps 
of: 
(i) decreasing the salinity of the formation fluid in said high 
permeability zone or zones by injecting into said formation a sufficient 
amount of surfactant-free water having a salinity less than the salinity 
of the formation fluid in said high permeability zone or zones; 
(ii) permeating said high permeability zone or zones with a microemulsion 
surfactant slug by injecting said microemulsion surfactant slug into the 
formation treated according to step (i), the interaction of formation 
fluids with said surfactant slug being insufficient to generate 
substantial permeability reducing macroemulsion in said high permeability 
zone or zones, provided that such generation of permeability reducing 
macroemulsion would have occurred if step (i) was omitted; 
(iii) generating substantial permeability reducing macroemulsion in said 
high permeability zone or zones by injecting a sufficient amount of 
relatively high salinity water into said formation treated according to 
step (ii), whereby said relatively high salinity water is diverted to said 
low permeability zone or zones; 
(iv) recovering oil from said low permeability zone or zones by continuing 
to inject a sufficient amount of relatively high salinity water into the 
formation treated according to step (iii), whereby oil in said low 
permeability zone or zones is displaced through said recovery means; 
(v) recovering oil from said high permeability zone or zones by injecting 
relatively low salinity water into said formation treated according to 
step (iv), whereby phase trapped emulsions are released and oil is 
displaced through said recovery means. 
According to another aspect of the invention, there is provided a process 
for recovering petroleum from an underground permeable reservoir having at 
least one high permeability zone and at least one low permeability zone, 
wherein the reservoir is penetrated by at least one injection well and at 
least one spaced-apart production well, said wells being in fluid 
communication with said reservoir, and wherein the reservoir contains a 
brine with from 50 to 220 kg/m.sup.3 salinity, said process comprising the 
steps of: 
(i) injecting into said reservoir a sufficient amount of relatively low 
salinity, surfactant-free water having a sufficiently low salinity to 
reduce the salinity of the reservoir fluids of said high permeability zone 
or zones; 
(ii) injecting into said reservoir treated according to step (i) a 
surfactant solution wherein the surfactant is selected from the group 
consisting of an alkylarylpolyalkoxy sulfate, an alkylarylpolyalkoxyalkyl 
sulfonate, an alkylpolyalkoxy sulfate, an alkylpolyalkoxyalkyl sulfonate, 
and mixtures thereof, said surfactant being of the formula 
EQU R.sub.1 (OR.sub.2).sub.m OSO.sub.3.sup.- M.sup.+ (I) 
and/or 
EQU R.sub.1 (OR.sub.2).sub.m OR.sub.3 SO.sub.3.sup.- M.sup.+ (II) 
where R.sub.1 is a C.sub.8 to C.sub.22 alkyl or an alkylaryl selected from 
the group consisting of alkylbenzene, dialkylbenzene, trialkylbenzene, 
alkyl toluene and dialkyl toluene with each alkyl group containing from 6 
to 18 carbon atoms, OR.sub.2 is ethoxy, propoxy or mixtures thereof (e.g., 
a mixture of ethoxy and propoxy with relatively more ethoxy than propoxy), 
m is a number from 1 to 12, R.sub.3 is a C.sub.1 to C.sub.6 alkyl 
(substituted or unsubstituted) and M.sup.+ is a cation, said surfactant 
exhibiting phase stability when mixed with small amounts of crude oil or 
distilled fractions thereof and a brine, said surfactant solution having a 
salinity less than that of the reservoir brine and comprising from about 
0.05 to 10.0 percent by weight of said surfactant of formula I and/or II, 
the salinity of the surfactant solution being from 5 to 20 percent less 
than the salinity required to produce partitioning of from 40 to 60 
percent of the surfactant solution out of the aqueous phase and into the 
oil and emulsion phases; 
(iii) injecting into said reservoir treated according to step (ii) a 
sufficient amount of relatively high salinity water sufficient to produce 
partitioning of at least 40 percent of the surfactant solution in the 
reservoir out of the aqueous phase and into the oil and emulsion phases 
and to recover petroleum via the production well from said low 
permeability zone or zones; and 
(iv) injecting into said reservoir treated according to step (iii) 
relatively low salinity water having a salinity of less than or equal to 
the salinity of the surfactant solution of step (ii) to recover petroleum 
from the high permeability zone or zones via the production well.

DETAILED DESCRIPTION 
The individual stratum associated with various sedimentary deposits within 
facies can have a wide degree of variability with respect to permeability 
by waterflooding. Consequently, water may tend to channel through high 
permeability strata or stringers. When a thin section of low permeability 
strata is sandwiched in between relatively thick sections of high 
permeability strata, oil may be displaced during waterflood from the thin 
section of low permeability strata by crossflow between the high 
permeability strata. However, such cross flow may not occur to an 
appreciable extent if the section of low permeability strata is 
sufficiently thick. Furthermore, when relatively thick sections of low 
permeability strata, e.g., the entire thickness of a particular facies, 
sandwich a central section, e.g., also corresponding to an entire facies, 
of high permeability strata, injected water will tend to channel through 
the central high permeability strata, substantially avoiding the outer low 
permeability strata. 
Accordingly, it will be understood that the term "zone" as used herein 
shall refer to individual stratum or adjacent strata composites. Thus, a 
zone may be as thin as an individual stratum or stringer or may be, e.g., 
as thick as an entire facies. 
The process of the present invention utilizes surfactant solutions to 
increase flow resistance in high permeability strata, thereby diverting 
subsequently injected fluids (e.g., water) to low permeability zones to 
improve reservoir conformance or volumetric sweep efficiency. The process 
also utilizes control over injection water salinity to control advance and 
retention of surfactant solutions in the high permeability zones. 
The process of the present invention is expected to be used principally to 
improve oil recovery by secondary waterflooding from highly stratified oil 
reservoirs where volumetric sweep efficiency is poor. 
An example of a process disclosed herein utilizes (1) a pre-flush of the 
higher permeability strata with low salinity brine to reduce the rate of 
mixing of surfactant solution with higher salinity formation brine, 
thereby improving rate and depth of penetration of surfactant/polymer into 
high permeability zones; (2) injection of surfactant/polymer solutions in 
the lower range of salinity at which emulsion formation is promoted; (3) 
injection of higher salinity brine to promote mixing, emulsification and 
trapping of surfactant emulsions in the high permeability zones, wherein 
high salinity brine injection is continued long enough to waterflood oil 
from low permeability zones; and (4) injection of lower salinity brine or 
polymer solution to release phase trapped emulsions and displace remaining 
oil from high permeability zones. Optionally, Steps 2-4 may be repeated. 
Also optionally, polymer may be omitted in Step 2 if the salinity of the 
surfactant solution is further reduced. 
By way of illustration, reference is made to FIG. 1, which summarizes phase 
behavior and interfacial tensions at 176.degree. F. for a particular 
surfactant which could be utilized as a surfactant in a reservoir. This 
surfactant is octylphenoxytriethoxypropane sulfonate, sodium salt. The 
salinity scale in FIG. 1 refers to mixed brines obtained by mixing high 
salinity formation brine (24 percent TDS) and low salinity injection brine 
(2.2 percent TDS) in different proportions. Compositions of these brines 
are shown in Table I. 
TABLE I 
______________________________________ 
Brine Compositions (mg/l) 
LOW SALINITY 
HIGH SALINITY 
BRINE BRINE 
______________________________________ 
NaCl 16,300 168,500 
CaCl.sub.2 
3,500 62,900 
MgCl.sub.2 
900 10,200 
Na.sub.2 SO.sub.4 
1,500 300 
TDS 22,200 241,900 
______________________________________ 
The phase map and interfacial tension data show that surfactant is 
partitioned into the oil-water interface at salinities higher than about 
11 percent TDS, that strong stable emulsions are promoted in a salinity 
range from about 11 to 15 percent, that dispersed liquid crystals exist in 
the aqueous surfactant over the salinity range about 14 to 19 percent, and 
that water is expelled from the surfactant brine solution to form a 
condensed surfactant-rich phase above about 20 percent salinity. This 
surfactant does not partition into the oil to form an upper-phase 
microemulsion. 
Experimental core floods have shown that octylphenoxytriethoxypropane 
sulfonate, sodium salt surfactant/pentanol solutions, containing 1% by 
weight surfactant and 0.3% by weight n-pentanol, displace oil effectively 
when injected at salinities between 15 and 20 percent, as expected from 
phase behavior and interfacial tensions. Flow resistances developed via 
surfactant/polymer injection increase with salinity, indicating increased 
trapping of emulsion and microemulsion phases, as expected and as desired 
for a floodwater diverting process. However, these experimental core 
floods show that surfactant transport at 19.8 percent salinity is not 
practical because of phase trapping, and that a mobility drive polymer 
(e.g., 0.1% by weight of a xanthan polysaccharide biopolymer) would be 
required to effectively transport the surfactant at 15.4 percent salinity, 
even in high permeability strata. 
Transporting the surfactant under salinity conditions in which 
emulsification is strongly promoted is particularly difficult in the 
absence of a polymeric mobility control agent. 
A remedy for this problem is to transport surfactant solution under low 
salinity conditions under which emulsification is not promoted, and rely 
upon mixing with more saline brines deep within the reservoir to promote 
emulsification--and increase flow resistances in the most permeable 
strata. 
The present process, therefore, for improving volumetric sweep efficiency 
in a stratified high salinity oil reservoir, may involve the following 
steps: 
(1) Preflush with enough low salinity brine to reduce the salinity in high 
permeability strata below that in which strong emulsification or 
partitioning of the surfactant to be used occurs. With an example 
reservoir and octylphenoxytriethoxypropane sulfonate, sodium salt 
surfactant, the preflush brine should be lower in salinity than about 11 
percent TDS; as indicated by the phase behavior, IFT data in FIG. 1. 
Desirably, the preflush salinity should be low enough that, when mixed 
with an equal volume of connate brine, the resulting salinity would be 
about equal the salinity needed for emulsification and IFT lowering. The 
volume of the preflush will depend upon the permeability contrast, 
vertical permeability and salinity contrast between preflush brine and 
connate brine. Practically, the preflush should be at least 50 percent of 
the composite pore volume of all strata with permeability greater than 100 
md, within the reservoir region being flooded, and would desirably be 
greater than 100 percent of this high permeability pore volume (HPPV). 
(2) Inject surfactant/polymer solution at a salinity in the lower half of 
the salinity range in which emulsification and partitioning occurs. In the 
above example, the surfactant/polymer should be injected at a salinity 
between about 11 and 16 percent, desirably near the lower end of this 
range. Surfactant concentration should be in the range 0.1 to 5 percent by 
weight, desirably 0.5 to 2 percent. Water soluble polymer concentration 
should be high enough to provide a viscosity of 10 to 100 cp at the 
reservoir temperature. For a xanthan polysaccharide biopolymer, the 
concentration would generally be 1000 to 3000 ppm. Volume of the 
surfactant/polymer solution should be at least 25 percent of the composite 
high permeability pore volume, and would desirably be 50 to 100 percent of 
this HPPV. 
Alternative Step (2) 
If no polymer is used to aid transport of surfactant into the high 
permeability strata, salinity of the surfactant solution should be within 
the range of about +20 percent of the salinity at which surfactant begins 
to partition into or emulsify the oil (that is, in the range of about 9 to 
13 percent salinity in this example) where 11 percent salinity is taken as 
the salinity for onset of partitioning into the oil/brine interface. 
Surfactant concentration and slug volumes are similar to those employed in 
Step 2, which included polymer in the slug. 
(3) Inject brine within the salinity range needed for emulsification or 
partitioning (in the range 11 to 20 percent salinity in this example, 
desirably within the range of 12 to 16 percent) and continue long enough 
to displace oil from lower permeability strata by floodwater diversion. It 
is noted that cross flow of high salinity formation brine from low 
permeability zones to high permeability zones promotes desired salinity 
conditions for further emulsification and phase trapping in the high 
permeability zones. Normally, economic factors (producing oil/water 
ratios, especially) will dictate duration of high salinity brine 
injection. 
(4) Inject low salinity brine or polymer solution to release phase trapped 
emulsions and displace oil from the high permeability strata. Salinity of 
this final drive should be lower than that required for partitioning of 
surfactant into oil/water interfaces or emulsification (less than 11 
percent salinity in this example), and desirably lower than 50 percent of 
this salinity. 
The present invention may be carried out utilizing injection and production 
systems as defined by any suitable arrangement of spaced apart injection 
and recovery wells in fluid communication with one another. One well 
arrangement commonly used in waterflooding operations and suitable for use 
in carrying out the present invention is an integrated five-spot pattern 
of the type illustrated in U.S. Pat. No. 3,927,716 to Burdyn et al. Other 
well arrangements may be used in carrying out the present invention, 
examples of which are set forth in the Burdyn et al patent. By the term 
"pore volume" as used herein, is meant that volume of the portion of the 
formation underlying the well pattern employed, which is described in 
greater detail in the Burdyn et al patent. 
Examples of suitable surfactants may be selected from the group consisting 
of an alkylarylpolyalkoxy sulfate, an alkylarylpolyalkoxyalkyl sulfonate, 
an alkylpolyalkoxy sulfate, an alkylpolyalkoxyalkyl sulfonate, and 
mixtures thereof, said surfactant being of the formula 
EQU R.sub.1 (OR.sub.2).sub.m OSO.sub.3.sup.- M.sup.+ (I) 
and/or 
EQU R.sub.1 (OR.sub.2).sub.m OR.sub.3 SO.sub.3.sup.- M.sup.+ (II) 
where R.sub.1 is a C.sub.8 to C.sub.22 alkyl or an alkylaryl selected from 
the group consisting of alkylbenzene, dialkylbenzene, trialkylbenzene, 
alkyl toluene and dialkyl toluene with each alkyl group containing from 6 
to 18 carbon atoms, OR.sub.2 is ethoxy, propoxy or mixtures thereof, m is 
a number from 1 to 12, R.sub.3 is a C.sub.1 to C.sub.6 alkyl and M.sup.+ 
is a cation. However, other surfactants may be used such as substituted 
derivatives of the above. The injected surfactant solution may also 
contain other additives such as viscosifiers and cosurfactants including 
petroleum sulfonates, lignosulfates, and alcohols. For example, from about 
0.5 to about 10.0 percent by weight of a petroleum sulfonate and/or 
lignosulfonate cosurfactant may be included. The surfactant solution may 
also contain a minimal amount of crude oil or distilled fractions thereof 
sufficient to stabilize the solution.