Determining residual oil saturation by injecting CO.sub.2 and base generating reactant

Residual oil saturation is determined by injecting water containing dissolved CO.sub.2 and subsequently active base generating reactant into an oil and water containing reservoir and chromatographically analyzing the patterns of the concentrations of in situ reaction-depleted CO.sub.2 and reaction-increased bicarbonate salt in fluid produced from the reservoir.

RELATED APPLICATION 
The present application is related to my commonly assigned and concurrently 
filed patent application Ser. No. 800,849, relating to determining 
residual oil saturation by injecting salts of carbonic and halocarboxylic 
acids. The disclosures of that application are incorporated herein by 
reference. 
BACKGROUND OF THE INVENTION 
This invention relates to determining the relative concentrations of fluids 
within subterranean reservoirs by measuring the chromatographic separation 
of tracers having distinctly different partitioning coefficients with 
mobile and immobile phases (such as water and oil phases) of fluids within 
the reservoirs. More particularly, the present invention relates to 
improving a process for making such determinations by injecting an aqueous 
solution of reactants which form tracers inclusive of one which is 
significantly partitioned between such mobile and immobile phases and one 
which is substantially completely dissolved in the mobile phase. 
In 1969 a method for determining the relative amounts of mobile and 
immobile fluid phases within a subterranean reservoir by injecting carrier 
fluid containing a reactant capable of forming within the formation at 
least two tracers which have different partitioning coefficients between 
the carrier fluid and the immobile fluid phase (exemplified by the tracers 
formed by a hydrolyzable organic ester) and measuring the separation of 
the tracers, was described in U.S. Pat. No. 3,623,842. U.S. Pat. No. 
3,751,226 by R. J. Hesse and R. F. Farmer relates to improving such a 
process by injecting a solution in which the tracer forming reactant is a 
hydrolyzable beta-keto ester such as ethylacetoacetate. U.S. Pat. No. 
3,847,548 relates to improving such a process by injecting carrier fluid 
containing tracers which partition differently in respect to temperature 
changes and injecting that fluid at a temperature different from the 
reservoir temperature. U.S. Pat. No. 3,856,468 relates to improving such a 
process by injecting carrier fluid containing both a precursor which forms 
a tracer material that partitions between the fluid phases and a tracer 
material which is inert and substantially completely dissolved in a mobile 
phase. U.S. Pat. No. 3,990,298 relates to improving such a process by 
injecting a carrier fluid containing a plurality of precursors each of 
which forms a tracer which has a distinctive partition coefficient with at 
least one immobile fluid phase within the reservoir. U.S. Pat. Nos. 
4,099,565 and 4,168,746 relate to uses of such a fluid saturation 
determining process in the course of evaluating the effectiveness of a 
design process for recovering oil. 
SUMMARY OF THE INVENTION 
The present invention relates to a process for determining relative 
concentrations of a substantially immobile oil phase fluid and a 
relatively mobile water phase fluid within a subterranean reservoir 
formation. The reservoir is injected with fluid which consists essentially 
of a slug of aqueous solution which at least soon after entering the 
reservoir formation, contains at least a concentration of dissolved 
CO.sub.2 and a concentration of subsequently active and water-soluble and 
oil insoluble pH-increasing reactive material which, at the temperature of 
the reservoir formation, is sufficient to convert at least a significant 
proportion of the dissolved CO.sub.2 to dissolved bicarbonate ions, 
followed by at least a slug of an aqueous solution which contains at least 
a detectible concentration of dissolved CO.sub.2 and is free of 
pH-increasing reactant. The injected fluid is kept within the reservoir 
formation long enough to allow an occurrence of the pH-increasing 
reaction. The injected fluid is then produced by backflowing it while 
measuring variations in the concentration with amount produced of both 
dissolved CO.sub.2 and dissolved bicarbonate ion. Determinations based on 
the chromatographic separation between the occurrence of the reduction in 
the concentration of dissolved CO.sub.2 and the occurrence of the increase 
in concentration of dissolved bicarbonate ion are made of the relative 
concentrations of the oil phase and water phase fluids in the reservoir.

DESCRIPTION OF THE INVENTION 
It appears that in conventional testing operations the only tracer-forming 
reactants and procedures which have been successfully used have been those 
described in U.S. Pat. No. 3,623,842, using hydrolyzable lower alkyl 
carboxylic acid esters or beta-ketoalkyl carboxylic acid esters. With such 
esters an unreacted ester or ketone is the tracer which is partitioning 
between the water and oil (or other mobile and immobile phases) and an 
alcohol or other reaction product which is substantially completely 
dissolved in the water phase is the tracer for the water. 
Such prior processes have received wide industry acceptance, as the "single 
well tracer method", and more than a hundred jobs have been done. But, in 
general, the dependance upon organic esters has limited the use of the 
method to reservoirs having relatively low temperatures. 
In general, the present invention comprises a process for determining 
relative concentrations of fluids in the reservoir which method is 
suitable for substantially any of the uses proposed for the prior methods 
mentioned above and is suitable for use at much higher temperatures. The 
present invention is improved relative to those prior processes by (1) 
using carbon dioxide as the tracer that partitions between the immobile 
oil phase and the mobile water phase and (2) using a reaction-induced 
depression of the dissolved CO.sub.2 concentration and a 
concurrently-induced elevation of dissolved bicarbonate ion concentration 
as the markers of the chromatographic separation by which the relative 
amounts of the fluid phases within the reservoir can be determined. 
The present use of a depression rather than an elevation in the 
concentration of an oil phase tracer material as a marker for determining 
the extent of chromatographic separation, appears to be novel. It involves 
a mechanism which is or appears to be, the following: as the pH of the 
injected fluid containing both a pH-increasing reactant and dissolved 
CO.sub.2 is increased, the carbonic acid, which is inherently in 
equilibrium with the dissolved CO.sub.2 is neutralized to form dissolved 
bicarbonate ion. This shifts the equilibrium and results in converting 
additional dissolved CO.sub.2 to dissolved bicarbonate ion. When the 
resultant CO.sub.2 -depleted and bicarbonate ion-enchanced solution is 
flowed through the reservoir formation, the transport of the wave of 
depleted CO.sub.2 concentration is delayed relative to that of the wave of 
increased bicarbonate ion concentration, due to the leaching or eluting of 
CO.sub.2 from the oil. When a relatively CO.sub.2 -rich oil is contacted 
by the relatively CO.sub.2 -poor aqueous fluid, it transfers CO.sub.2 into 
that fluid so that the wave of CO.sub.2 depression is delayed relative to 
the wave of the increased bicarbonate ion concentration. With the 
bicarbonate ions no such transfer can take place because of zero 
solubility of bicarbonate salts in oil. Such concentration changes become 
separated in a manner similar to that of the separation between a wave of 
increased concentration of and oil-tracer tracer and an increased 
concentration of non-partitioning water-tracer. As known in the art, the 
calculations involved in using such a CO.sub.2 concentration-depression as 
the marker of the extent of chromatographic separation are the same type 
as those involved in using an increase in a tracer concentration for that 
purpose. 
COMISON OF TRACER CAPABILITIES 
(1) Temperature Range 
In typical prior processes an organic ester which is partially soluble in 
oil serves as the oil phase tracer which is injected at the wellbore and 
displaced to the desired distance from the wellbore by an inert fluid. A 
soak period then allows time for a hydrolysis reaction to take place and 
produce a significant amount of alcohol. The alcohol is not soluble in the 
oil and thus serves as the water phase tracer. 
The hydrolyses step must not be too fast since it is undesirable for the 
alcohol to be produced during the placement step and also, some unreacted 
ester must remain after the soak period as it is the oil phase tracer. At 
the end of the soak period, both tracers are produced back to the 
wellbore. The amount of chromatographic separation of the two tracers is 
measured and used to calculate residual oil saturation. 
If the reservoir temperature is above about 200.degree. F., the hydrolysis 
rate of most, if not all, known esters is so fast that the above 
requirements cannot be met. Therefore, the prior processes have been 
limited to reservoirs of about 200.degree. F. or less. 
A very large number of choices are available for selection of the "Base 
Generators" (i.e., pH-increasing reactants). A few examples are given in 
Table I, along with a best estimate of the applicable temperature range 
for each listed Base Generator: 
TABLE I 
______________________________________ 
BASE GENERATOR TEMPERATURE RANGE .degree.F. 
______________________________________ 
KOCN 70 to 110 
UREA 200 to 250 
NaNO.sub.2 210 to 280 
______________________________________ 
(2) Deeper Penetration (depth of investigation) from the Wellbore 
The reactions by which a base is formed by typical base generating 
reactants suitable for use in the present process are listed in Table II 
TABLE II 
______________________________________ 
COMPOUND BASE 
______________________________________ 
Urea CO(NH.sub.2).sub.2 + 
NH.sub.4 HCO.sub.3 + 
3H.sub.2 O NH.sub.4 OH 
Potassium Cyanate 
KOCN + NH.sub.4 HCO.sub.3 + 
3H.sub.2 O KOH 
Sodium Nitrite 
3NaNO.sub.2 + 
NaNO.sub.3 + 2NO + 
3H.sub.2 O 2NaOH 
Urea and Sodium Nitrite 
2NaNO.sub.2 + 
2N.sub.2 + NaHCO.sub.3 + 
CO(NH.sub.2).sub.2 + 
NaOH 
H.sub.2 O 
Propylene Oxide 
##STR1## CH.sub.3 CHOHCH.sub.2 Cl + NaOH 
______________________________________ 
In commonly used processes the oil phase tracer is ethylacetate which is 
injected with an aqueous carrier fluid. It partitions between the oil in 
the reservoir and the water of the carrier fluid. The effect is to retard 
the advance of the ester front into the reservoir. In most cases the ester 
will reach a distance corresponding to a volume of only about one-third 
that of the volume of the total fluid injected. 
In the present process the situation is different. The oil phase tracer is 
a reaction-induced dip in the concentration of CO.sub.2 dissolved in an 
aqueous carrier fluid. Some reservoirs contain CO.sub.2 which is 
partitioned to an equilibrated extent between the water and the oil phase 
fluids within the reservoir. When the fluid produced from such a reservoir 
is used as the aqueous solution containing CO.sub.2 injected in accordance 
with the present process, the injection causes no further CO.sub.2 
partitioning. In other reservoirs a portion of water containing dissolved 
CO.sub.2 but no dissolved base generating reactant is preferably injected 
ahead of the solution containing both dissolved CO.sub.2 and dissolved 
Base Generating reactant. This ensures that CO.sub.2 is present at the 
distance from the well in which the reservoir is to be tested. The 
CO.sub.2 and base generating reactant-containing solution is displaced to 
the selected distance by injecting an aqueous fluid which contains at 
least about the same amount of dissolved CO.sub.2 but is free of the base 
generating reactant. Since the base generating reactant is selectively 
water miscible, the subsequently formed depressed concentration of 
CO.sub.2, i.e., the oil phase tracer of the present system, will penetrate 
farther into the formation than an ester system tracer (for a given volume 
of treatment) and will provide a residual oil measurement over about 3 
times the volume of reservoir sampled by the prior system. 
(3) Distribution Coefficient 
The distribution coefficient, Ki, (ratio of concentration of tracer in the 
oil phase to that in the water phase) of esters is about 6 in most cases. 
Ki for CO.sub.2 is about 2. 
The CO.sub.2 value for Ki is much more optimum from a test sensitivity 
point of view in most cases, since more of it is present in the water 
phase, which comprises substantially all of the produced fluid. 
Also, the present type of tracer will be produced back to the wellbore much 
sooner than an equivalent ester tracer would be. If this property is 
combined with the smaller volumes needed for sampling the reservoir, 
because of deeper penetrating capability of the present tracer, only small 
jobs may be necessary. In this case, several small tests could be run on 
different wells instead of the one large ester test as currently 
practiced. This would give better overall reservoir values for Sor 
(residual oil saturation) than is currently possible. 
(4) Drift During Soak Period 
In most reservoirs, fluid injected into a well will drift with the overall 
reservoir fluids when the pumps are shut down. This may be as much as a 
few feet per day. 
In the ester system, long soak periods are frequently required. This makes 
drift an important source of error, for which corrections must be made. 
Also, considerable accuracy and sensitivity is lost in the process. 
In the present system, the wide choice of base generators which react at 
different rates at different temperatures coupled with more rapid backflow 
will greatly diminish the effect of drift in many cases. This is because 
base generators can be more optimally selected to correspond to the 
reservoir temperature involved. Also, the water tracer and oil tracer will 
stay much closer together in the reservoir and hence cancel much of the 
errors introduced by the reservoir drift velocity. 
(5) Miscellaneous 
(a) A more precise positioning of the CO.sub.2 -depleting base generator in 
the reservoir may make it possible to use frontal analysis techniques on 
the tracers instead of band analyses used for the ester. Frontal analyses 
should be more accurate. 
(b) In some cases, very small amounts of CO.sub.2 may be sufficient due to 
the high sensitivity and stability of the analyses systems. 
(c) If drift is minimal, simple methods of analyzing the data and 
calculating the residual oil saturation may be possible. 
In general, with modifications apparent to those skilled in the art, the 
present process can be utilized in substantially any of the reservoir 
situations of fluid saturation determining processes for which the prior 
processes were suitable. 
Table III lists results of testing various base generators at various 
temperatures and pH's. In each case, the solution was maintained at a 
pressure of 50 psig during the test. The pH of the solution was maintained 
substantially constant by adding portions at 0.1 mol/liter sodium 
bicarbonate solution to the system while the hydrolysis was proceeding. 
Each base generator solution consisted of water containing 0.5 mol/liter 
sodium chloride and 0.05 mols/liter of the base generator. 
TABLE III 
______________________________________ 
Hydrolysis Data - Screening Tests 
Conditions: 
(1) Pressure, 50 PSIG 
(2) .5 M/L NaCl Present in all Solutions 
Temp. Half Life,*.sup.1 t1/2 
Test Base Generator 
.degree.F. pH hours 
______________________________________ 
1 Urea 210 6.2 12.3 
2 " 208 5.5 8.4 
3 " 208 7.0 45.2 
4 " 211 8.0 15.9 
5 Succinimide 177 7.0 28.4 
6 " 177 6.0 184.1 
7 " 206 6.0 31.3 
8 Maleimide 206 6.0 too fast 
9 " 140 6.0 18.4 
10 " 96 6.0 53.6 
11 " 76 6.0 450.1 
12 Maleimide 109 6.0 92.0 
13 " 109 7.0 35.0 
14 " 110 6.5 43.8 
15 " 110 5.5 439.0 
16 KOCN 78 6.0 19.6 
17 " 78 6.5 68.6 
18 " 78 7.0 206.4 
19 KOCN 99 7.0 .about.94.0 
20 " 99 7.5 .about.223.0 
21 " 116 8.0 .about.223.0 
22 NaNO.sub.2 212 6.0 80.0 
23 " 279 6.0 49.2 
24 " 279 5.5 17.5 
25 NaNO.sub.2 279 7.0 141.4 
26 " 280 6.5 84.9 
27 " 296 6.5 73.2 
28 Urea + NaNO.sub.2 
138 6.5 no reaction 
29 Urea + NaNO.sub.2 
184 6.5 41.0 
30 Urea + NaNO.sub.2 
180 6.0 52.3 
31 Urea + NaNO.sub.2 
190 6.0 19.3 
32 Propylene oxide 
106 6.0 26.5 
33 " 122 6.0 26.0 
34 " 122 7.0 35.6 
35 " 76 7.0 86.1 
______________________________________ 
*.sup.1 This is the time, in hours, required for the base generator to be 
1/2 reacted. This is a convenient way to measure the speed of a reaction. 
The patterns of the concentrations of dissolved CO.sub.2 and dissolved 
bicarbonate with amounts of fluid produced from the reservoir being tested 
(and/or concentrations with time where the production rate is 
substantially constant) can be measured by currently known and available 
methods and apparatus. It is a distinctive advantage of the present 
process that known and available relatively simple procedures, such as 
titrometric and/or thermetric analyses, can be utilized to measure the 
chromatographic separation between the CO.sub.2 partitioned between the 
phases and the acid anions dissolved substantially completely in the 
mobile phase of the reservoir fluid. 
In a preferred procedure for measuring residual oil saturation, water 
produced from (or equivalent to) the water in the reservoir is used as the 
injected aqueous fluid. Where that water is substantially free of 
dissolved CO.sub.2, a selected amount, such as about 0.001 M/L to 0.100 
M/L is dissolved in the water. While injecting that solution, a base 
generating reactant is incorporated in the inflowed water in a 
concentration of about 0.0005 M/L to 0.0500 M/L and a volume sufficient to 
form a slug occupying the desired pore volume of the reservoir. The base 
generating reactant-containing solution is displaced a selected distance, 
such as about 5 to 25 feet from the well, by injecting the CO.sub.2 
-containing water while omitting the base generating reactant. After time 
enough for the depletion of a significant proportion, or all, of the 
CO.sub.2 in the base generating reactant-containing fluid, the injected 
fluid is backflowed and analyzed. 
In general, it is preferable to select the base generating reactant 
relative to a pumping grate to be used the distance from the well at which 
the measurement is to be made and the temperature to be encountered within 
the reservoir. This indicates the time temperature exposure to be 
encountered by the base generating reactant during the inflowing of the 
solution containing it. Relative to the exposure to be encountered, the 
reactant can be selected so that no more than about 20-30 percent or in 
the order of about 1/3 of the reactant will be spent while the fluid 
containing it is being pumped into the reservoir. In such a situation the 
soak period for the completion of the reaction need only be about 3 times 
as long as the pump-in time.