GB2132664A - Enhanced oil recovery using alkaline/polymer flooding - Google Patents

Abstract

Residual oil remaining in geological deposits is recovered by pumping through the deposit an aqueous solution comprising a polymeric material, such as polyacrylamide, and alkali, such as soda ash (Na2CO3). The concentration of the polymeric material is such that the viscosity of the aqueous solution is at least about 50% the viscosity of oil. The concentration of alkali is adjusted to a value which will produce an approximate minimum value for the interfacial tension between the aqueous solution and crude oil which is less than 0.1 dyne/cm.

Description

SPECIFICATION Enhanced oil recovery using alkaline/polymer flooding The present invention relates to enhanced oil recovery from geological formations using an aqueous solution of polymer and alkali.

It is broadly known in the art to use polymer flooding, alkali flooding, and combined alkali/polymer flooding of geological formations to recovery residual oil contained therein. Generally, when polymer flooding is used, it is also known that the viscosity of the "pusher fluid" containing the polymer should be adjusted to a value of from about equal to the viscosity of the oil in place in the producing strata to about 1/2 the viscosity of such oil (e.g., see U.S. No. 3,039,529 at Col. 3, lines 27-30 and U.S. No. 4,254,249 at Col. 3, lines 49-53).

In regard to the interfacial tension characteristics of alkaline pusher fluids, it has been suggested by certain investigations that if the interfacial tension between the fluid and crude oil is low enough, oil displacement will occur. However, a more recent investigator has concluded that although initial displacement may be possible, a rapid rise in tension will preclude a sustained displacement thereby suggesting that low-tension oil recovery cannot be operative in alkaline waterflooding (see E. Rubin et al., Chemical Engineering Science, Vol. 35, 1136, 1 980).

It has also been suggested to use alkali/polymer flooding in which the interfacial tension between the pusher fluid and residual oil is lowered by the presence of the alkali. The concentration of alkali suggested for use, however, produced an interfacial tension value higher than the values obtainable using differing (i.e., lower) alkali concentrations. For example, the interfacial tension between alkali and crude was only in the range of from about 0.1-0.2 dynes/cm at the alkali concentration used. The recovery of residual oil (% OIP) ranged from about 17% to about 34% depending upon the type of alkali and polymer used (Product Information Bulletin for FLOCON Bipolymer 4800, published by Pfizer, August 1982).

Summary of the present invention The present invention is a process for the recovery of residual oil from geological formations by pumping an aqueous alkali/polymer solution through such formations and is also the aqueous alkali/polymer solution used in that process. The solution has a polymer content that gives the solution a viscosity that is at least 50% the viscosity of the oil, and the concentration of the alkali is such that the interfacial tension between the oil and alkali solution is less than about 0.1 dyne/cm.

Description of the figures The present invention is further illustrated by means of the Drawings wherein: Figure 1 is a schematic diagram of the apparatus used in the coreflood procedures described in the Examples; Figures 2-6 inclusive, present the pressure data or resistance factors for the corefloods in Examples 1-5, respectively; and Figure 7 is a plot of the interfacial tension between various alkaline solutions and the crude oil.

Detailed description of the invention The aqueous alkali/polymer solution which is used in the present invention comprises those alkali and water-soluble polymer ingredients which individually and in combination are useful in the recovery of residual oil from geological formations by pumping aqueous solutions containing them through the formation.

Various types of polymers can be used in conjunction with the present invention include acrylamide polymers, polysaccharides, cellulosics, acrylic polymers, and polyalkylene oxides.

Representative examples of acrylamide polymers include partially hydrolyzed (e.g. 1 5-35% degree of hydrolysis) poiyacrylamides, especially those sold under the trademark Cyanatrol by American Cyanamid, starch-acrylamide graft copolymers, copolymers of N,N-dimethylacrylamide, acrylamide, and 2-a cryla mide-2-methylpropane sulfonate/acryla mide copolymers. One type of polysaccharide which can be employed is xanthan gum (Xanthomonas campestris). Scleroglucan, which is produced by fermentation of glucose with a species of sclerotium fungus can be used. Such cellulosics as hydroxylethyl cellulose, carboxymethyl cellulose, sodium and cellulose sulfate ester polymers are others which can be employed.

The polymer that is used is preferably contained in the aqueous solution used in the present invention in an amount sufficient to give a Brookfield viscosity to the aqueous solution that is at least 50% the corresponding viscosity of the residual oil in place in the geological formation. Viscosities for the aqueous solution which exceed that of the viscosity of the oil can be used (e.g., viscosities of up to about 1 50% that of the oil), but are not preferred for economic reasons. Preferably, the viscosity of the polymer containing slug will approximate that of the crude oil. Generally, concentrations of from about 1000 to about 5000 ppm of polymer per million parts by weight of water will suffice depending upon the type of polymer, type of oil, and temperature in the geological formation.The amount can be 3500--4000 ppm for the polyacrylamide as in the Examples.

The alkali materials which can be used are those water soluble materials which serve to release hydroxyl ions in water solution and which exhibit a sufficient alkali response with the oil to result in a substantial lowering of the interfacial tension between the residual oil and the aqueous pusher fluid containing the alkali and polymer. Preferred are the alkali metal containing compounds, such as those containing sodium or potassium as cations. Representative alkali materials include Na2CO3, K2CO3 NaOH, KOH, Na4SiO4 and K4SiO4.Sodium carbonate is preferred for use in the present invention since it has been found to give superior injectivity (e.g., producing less resistance to flow) when in the geological formation as compared to the normal level of improvement in interfacial tension generally observed due to alkali addition as compared to polymer addition only.

In determining the amount of alkali to use in the aqueous solution of the present invention, an interfacial plot similar to the one shown in Figure 7 can be generated. The plot presents the interfacial tension between alkaline solutions of varying concentration and can be generated by known means.

The interfacial minima between the alkali containing solution and the crude oil of interest can be determined by conventional means using a tensiometer, e.g., either by the pendant drop or the spinning drop method as mentioned in U.S. No. 4,004,637 at Col. 3, lines 57-62.

The plot shown in Figure 7 was generated in conjunction with the Examples presented herein for a certain number of varying concentrations of sodium hydroxide, sodium carbonate, and sodium orthosilicate. It forms a rough approximation by which the approximate interfacial characteristics of the various alkali to the particular crude oil might be determined. Based upon this plot, initial alkali concentrations are chosen so as to fall at or adjacent to the perceived interfacial minima generated by the plot. It is entirely possible that additional data points could change the shape of the "trough" area of the curve adjacent the minima shown in Figure 7 so that the plot, in most cases, merely approximates the minima.In the Examples, the following concentrations of alkali were chosen for use and, according to the plot, produced the following approximate interfacial tension readings when present in an alkaline solution in contact with the crude oil: (Weight Oil Inteffacial Alkali Alkali tension (0.5 wt.% Na2O) concentration {dynes/cmJ Sodium hydroxide 0.640 0.055 Sodium carbonate 0.850 0.05 Sodium orthosilicate 0.764 0.04 In regard to the present invention, the alkali concentration chosen for use in the present invention should be that concentration supplied to the geological formation (when combined with water and polymer) which would produce an interfacial tension of less than 0.1 dyne/cm, preferably less than 0.07 dyne/cm, if tested as an alkaline solution against the type of crude oil in place in formation.

In selecting the level of alkali to use in the aqueous "pusher" fluid of the present invention, it may be necessary to take into account any consumption of the alkali which might occur due to its injection into the geological formation. Consumption can occur in various ways. For example, one form is actual consumption by the rock in the formation through appropriate bonding or ion exchange mechanisms.

Data for such a phenomenon is known from the literature for the alkali consumption (vs. time and temperature) for certain types of rock (e.g., sandstone, dolomite, clay minerals, gypsum, anhydrite, etc.). One exemplary literature reference of this type is R. Ehrlich, "Interrelation of Crude Oil and Rock Properties with the Recovery of Oil by Caustic Waterf!ooding", Society of Petroleum Engineers Journal, August, 1977, pp. 263-270. Rock consumption of alkali can be determined by static jar tests or by pulsed flow tests according to known techniques. In such tests the alkali is brought into cdntact with the formation rock and/or specific minerals at the temperature existing in the formation.

Another form of consumption is the precipitation of certain anion species of the alkali due to the presence of dissolved cations (e.g., Ca+2, Mg+2, etc.) present in the connate water of the geological formation. In order to determine the consumption due to precipitation of multivalent ions, the produced water from prior waterflood injections can be examined for the degree of precipitation caused when they are added to the alkali solution of interest in the present invention.

In some cases, it may not be necessary to supply enough alkali to the rock formation for the desired interfacial minima conditions (e.g., less than 0.1 dyne/cm, preferably less than 0.07 dyne/cm by the alkaline/crude oil test of Figure 7) to pertain throughout the entire geological formation. An interfacial minima condition can exist in a sufficiently large portion of the rock formation so as to form an initial oil bank which is then capable of mobilizing the remaining oil in the remainder of the formation. This initial oil bank would then function as an efficient pusher for such remaining oil even though the amount of alkali supplied to the entire formation is only sufficient to bring about approximate interfacial tension minima conditions in that portion of the formation where the oil bank is formed.

The aqueous alkali/polymer solution described above having the aforesaid viscosity and minimum interfacial tension characteristics can then be injected into the geological formation, e.g., at temperatures of from about 350C to about 950C. in amounts sufficient to mobilize the oil (e.g., from about 0.1 to about 1.0 pore volumes (PV) based on the pore volume of the formation) to result in a removal of residual oil from the geological formation. If desired, the injection of the alkali/polymer solution of the present invention into the formation can be preceded and/or followed by other conventional enhanced oil recovery techniques, e.g., waterflooding, etc. This technique is preferably used in tertiary recovery (e.g., after primary pumping and secondary waterflood recovery).

The Examples which follow serve to illustrate certain embodiments of the present invention.

Examples 1-5 A series of corefloods was performed with Long Beach Oil Development crude to illustrate the type of recoveries obtained with the composition and process of the present invention. Examples 2-5 illustrate the present invention with Example 1 (using polymer alone) being presented for comparison only.

Samples used in corefloods Core-A series of 2 inch by 2 foot long Berea sandstone cores were cut from a singie block of stone so as to achieve optimum data reproducibility. The properties of these cores are listed in Table 1, which follows. For the corefloods, the cores were encased in high temperature epoxy with pressure taps mounted through the epoxy to the surface of the core. The two internal pressure taps were positioned in order to divide the core into three equal length sections for pressure measurement.

Table 1 Core properties Example number 1 2 3 4 5 Pore volume (ml) 281.4 271.5 263.9 283.7 269.2 Porosity (frac) 0.22 0.22 0.22 0.23 0.22 Permeability to water (mud)* Front 596 468 552 604 544 Middle 668 607 552 587 532 Rear 333 253 563 639 453 Overall 485 387 555 609 506 *md=millidarcy units In addition to the foregoing a representative sample of the cores employed herein were found to possess a surface area of about 2 m2/gm. Emission spectography indicated that the major elements were silicon, calcium and aluminum with significnat levels of iron, magnesium, potassium, sodium and titanium also being detected. Scanning electron microscopy showed irregularly shaped particles 100 microns to 400 micron in diameter with smaller particles of 0.2-1 0 microns intermixed.

OiI-1 250 F., 0.8 y filtered acidic crude oil was used in all corefloods. The crude oil properties are listed in Table 2 which follows.

Table 2 Crude oil properties Viscosity, cps. 465 at 750 F.

(Brookfield, UL 295 at 850 F.

adapter) 200 at 95"F.

144 at 1050F.

66 at 125"F.

48 at 145"F.

API gravity, deg: 20.8 (hydrometer) Total acid number, 2.80 mg KOH/g: (ASTM D664) Water-Water analyses and formulations used for lab makeup are listed in Tables 3 and 4 for the fresh and reservoir (or produced) waters, respectively. All alkaline and polymer samples were blended in the fresh water. Tables 3 and 4 follow.

Table 3 Simulated brine composition (Fresh water-FW) Water Designation: Softened 3:1 Fresh water: Injection water pH: 7.6 lon ppm met// Ammonium 39.2 2.173 Calcium 0.5 0.025 Magnesium 0.5 0.041 Potassium 2.9 0.074 Sodium 2946.7 127.849 Sulfate 133.6 2.782 Chloride 4403.5 124.207 Carbonate (calculated) 4.0 0.134 Bicarbonate (calculated) 185.5 3.041 Nitrate 1.1 0.0165 Borate 23.8 0.306 lodide 1.0 0.007 Iron 0.0 0.000 Barium 0.0 0.000 Fluoride 0.7 0.037 Total dissolved solids 7764.1 Table 3 (cont.).

gms per litter Chemical of brine Ammonium chloride 0.1163 Sodium bicarbonate 0.2554 Sodium carbonate 0.0071 Calcium chloridex2H20 0.0018 Magnesium chloridex6 H20 0.0042 Potassium chloride 0.0055 Sodium chloride 7.1238 Sodium sulfate 0.1975 Sodium iodide 0.0010 Sodium borate 0.0308 Sodium nitrate 0.0014 Sodium fluoride 0.0015 Table 4 Simulated brine composition (Produced water-PW) Water Designation: Plant Injection Water, Carbonate-Bicarbonate Free Form pH: 6.8 lon ppm meq/l Ammonium 157.0 8.704 Calcium 450.0 22.455 Magnesium 430.0 35.373 Potassium 0.0 0.000 Sodium 10356.0 448.025 Sulfate 78.0 1.624 Chloride 18185.1 512.934 Carbonate (calculated) 0.0 0.000 Bicarbonate (calculated) 0.0 0.000 Nitrate Borate 95.0 1.224 lodide 4.0 0.0032 Iron 0.0 0.000 Barium 0.0 0.000 Fluoride Total dissolved solids 29755.1 Table 4 (cont.).

gms per liter Chemical of brine Ammonium chloride 0.4656 Sodium bicarbonate Sodium carbonate Calcium chloridex2 H20 1.6506 Magnesium chloridex6 H20 3.5959 Potassium chloride Sodium chloride 26.0889 Sodium sulfate 0.11 53 Sodium iodide 0.0047 Sodium borate 0.1232 Sodium nitrate Sodium fluoride Alkaline agents-Products and procedures used are as follow: (all references to Na2O are for total Na2O content) NaOH A weight percent dilution of 50% caustic soda was made to 0.5 wt.% Na2O for Example 4.

NaCO3 A weight percent addition of soda ash (Stauffer Dense Soda Ash) was made to the injection water. A concentration of 0.5 wt.% Na2O was used in Examples 2 and 3.

Na4SiO4 A 10% stock solution of sodium orthosilicate was prepared as outlined in SPE 1 0734: Sodium silicate: PQ Corp. N Brand (SiO2:Na20 ratio -3.22:1) 11.35% Sodium hydroxide (50% solution) 15.10% Deionized water 73.55% 100.00% Dilution to 0.5 wt.% Na2O was made gravimetrically by addition of injection water for Sample 5.

Polymer Partially hydrolyzed polyacrylamide (Cyanatrol 940S brand from American Cyanamid) was used for all corefloods. A 5000 ppm polymer solution (in fresh water) was blended with a 10% alkaline solution (in fresh water) so that the resulting solution was at the desired alkali concentration. The resulting solution was diluted with fresh water containing the desired concentration of alkali until the proper polymer concentration was achieved. The target viscosity during makeup of the polymer solutions was 50 cps. The viscosity was noted to increase with time for all of the alkali/polymer combinations due to presumed hydrolysis of the polyacrylamide. Viscosities as high as 55-60 centipoise may have been present during later phases of slug injection. This would not be expected to have significantly altered the results of the corefloods.

Corefloods A schematic diagram of the coreflooding apparatus is shown in Figure 1.

A positive displacement Ruska pump was used in conjunction with a constant temperature chamber. The core and fluids were elevated to reservoir temperature prior to initiation of injection.

Reservoir water saturation was achieved by pulling a vacuum on the core for about 1 2 hours. The core was then injected with reservoir crude oil until no further water was produced. This injection was done at a high rate (10 ft/day) in order to insure maximum oil saturation.

Primary and secondary recoveries were simulated in a combined manner by injection of reservoir water at a frontal advance rate of 2.0 fit'day until the oil cut or saturation reached a predetermined level. A 20:1 water/oil ratio was used as the waterflood end point.

The generalized waterflood and tertiary sequence was as follows: Frontal velocity Pore (ft/day) volumes a. inject reservoir water 1.0 7-8 b. inject reservoir water 1.0 to stable AP c. inject injection water 1.0 0.25 d. inject chemical slug 1.0 1.0 e. inject injection water 10.0 0.1 f. inject reservoir water 10.0 3.5 Incremental samples were collected only during steps d through f. These samples were used to determine the oil cut response versus pore volumes of injected fluid. Analyses of the samples were also completed in order to determine the produced levels of calcium, magnesium and silicon (by atomic absorption spectroscopy) and pH. Atitration with 0.1 N HCI was completed in order to quantify the concentration of alkali in each sample.

The exact fluid injected volumes are listed in the injected fluids summary (Table 5) which follows.

The various viscosities are expressed in centipoises (cp) and the pore volume figure (PV) is the fraction of the total core pore volume of fluid that was injected. The numerals "940" stand for the specific type of polyacrylamide used in Examples 1-5 (Cyanatrol 940S brand).

Table 5 Injected fluids summary Example number 1 2 3 4 5 Produced water Viscosity at 1250F. (cp.) 0.5923 0.5923 0.5923 0.5923 0.5923 Crude oil Viscosity at 1 250F (cp) 66.5 66.5 66.5 66.5 66.5 Produced water Volume injected (PV) 0.88 0.95 2.08 1.86 1.96 Fresh water Viscosity at 1250F(cp) 0.5514 0.5514 0.5514 0.5514 0.5514 Volume injected (PV) 0.25 0.25 0.25 0.25 0.32 Chemical slug Type 940 Na2CO3/940 Na2CO3/940 NaOH/940 Na4SiO4/940 Alkali concentration (wt.%) 0.850 0.850 0.640 0.764 Polymer concentration (ppm) 3200 3853 3828 3800 3850 Viscosity (cp) 50.5 50.5 48.5 48.5 50.5 Volume injected (PV) 1.01 1.02 1.00 1.00 1.00 Fresh water Volume injected (PV) 0.09 0.10 0.10 0.10 0.10 Produced water Volume injected (PV) 3.46 3.47 3.52 3.33 3.55 Interfacial tension measurements Interfacial tension (IFT) measurements between the crude oil and each alkaline agent were made.

Concentrations of alkali in the injection water ranging from 0--2.0 wt.% available Na2O were tested.

For all values less than 1.0 dyne/cm, a constant temperature, constant rate, spinning drop interfacial tensiometer was used. All measurements were taken at 1250 F., 3600 rpm after five minutes of oil/alkali contact. This period of time appeared to yield the minimum value for IFT with time for these systems.

If evaluation by spinning drop proved unsuccessful due to resulting IFTs of greater than 1.0 dyne/cm, a duNouy ring instrument was used (at 70"F) to make the measurement.

Three of the four alkaline agents tested demonstrate reduction of IFT from 1 7.6 dyne/cm (in the absence of alkali) to levels adequate for mobilization of tertiary oil. Only the sodium bicarbonate was deemed ineffective as an IFT reducing agent for the particular crude oil used in these Examples. The minimum IFT values and concentration of each alkaline agent required is shown below: Alkaline IFT agent wt% pH ldynelcmJ Na2CO3 0.34 10.40 0.042 Na4SiO4 0.16 11.92 0.023 NaOH 0.65 12.54 0.058 NaHCO3 4.0 8.94 7.6 Recovery efficiencies-Tables 6 and 7, which follow, are descriptions of the recovery efficiencies of each coreflood assuming either the fresh water preflush is part of the tertiary or waterflood, respectively.In Tables 6 and 7 the core permeability, i.e., effective permeability to oil with residual water (Korw), and effective permeability to water with residual oil (two) is given in millidarcys. The oil recovery values set forth the initial oil saturation (So@) values, waterflood recovery (% Soj) waterflood residual (Sor), tertiary recovery using the aqueous alkali/polymer composition of this invention (% Sor), residual saturation (Sof) remaining in the core and total recovery (waterflood recovery plus tertiary recovery). PV in the table gives the pore volume amounts of fluid injected or recovered, as appropriate.

Table 6* Performance summary Example number Units 1 2 3 4 5 Run temperature OF 125 125 125 125 125 Core properties Pore volume ml 281.4 271.5 263.9 283.7 269.2 Porosity frac 0.22 0.22 0.22 0.23 0.22 Perm (overall) md 485 387 555 609 506 Eff perm (KOrw) md 447 437 421 511 493 Eft per (two) md 31.3 17.2 17.3 45.9 59.9 Fluid injected Waterflood PV 0.88 0.95 2.08 1.86 1.96 FW Preflush PV 0.25 0.25 0.25 0.25 0.32 Slug type 940 Na2CO3/940 Na2CO3/940 NaOH/940 Na4SiOJ940 Alkali conc. wt% 0.850 0.850 0.640 0.764 Polymer conc. ppm 3200 3853 3828 3800 3850 Slug size PV 1.01 1.02 1.00 1.00 1.00 FWPostflush PV 0.09 0.10 0.10 0.10 0.10 PW Postflush PV 3.46 3.47 3.52 3.33 3.55 Oil recovery Initial oil sat (soy) ml 207.0 188.0 207.0 215.0 207.0 PV 0.736 0.692 0.784 0.758 0.769 Waterflood recovery ml 87.0 81.0 91.8 93.3 93.0 PV 0.309 0.298 0.348 0.329 0.346 %oi 42.0 43.1 44.4 43.4 44.9 Waterflood resid (sox) ml 120.0 107.0 115.2 121.7 114.0 PV 0.426 0.394 0.437 0.429 0.424 Tertiary recovery ml 22.4 102.2 95.2 101.8 105.1 PV 0.080 0.376 0.361 0.359 0.390 %Sor 18.7 95.5 82.6 83.7 92.2 Residual sat (Sof) ml 97.6 4.8 20.0 19.9 8.9 PV 0.347 0.018 0.076 0.070 0.033 Total recovery ml 109.4 183.2 187.0 195.1 198.1 PV 0.389 0.675 0.709 0.688 0.736 %oi 52.9 97.4 90.3 90.7 95.7 * preflush as tertiary Table 7* Performance summary Example number Units 1 2 3 4 5 Run temperature F 125 125 125 125 125 Core properties Pore volume ml 281.4 271.5 263.9 283.7 269.2 Porosity frac 0.22 0.22 0.22 0.23 0.22 Perm (overall) md 485 487 555 609 506 Eff perm (Korw) md 447 437 421 511 493 Eff perm (two) md 31.3 17.2 17.3 45.9 59.9 Fluid injected Waterflood PV 0.88 0.95 2.08 1.86 1.96 FW Preflush PV 0.25 0.25 0.25 0.25 0.32 Slug type 940 Na2CO3/940 Na2CO3/940 NaOH/940 Na4SiO4/940 Alkali conc. wt% 0.850 0.850 0.640 0.764 Polymer conc. ppm 3200 3853 3828 3800 3850 Slug size PV 1.01 1.02 1.00 1.00 1.00 FWPostflush PV 0.09 0.10 0.10 0.10 0.10 PW Postflush PV 3.46 3.47 3.52 3.33 3.55 Oil recovery Initial oil sat (SOl) ml 207.0 188.0 207.0 215.0 207.0 PV 0.736 0.692 0.784 0.758 0.769 Waterflood recovery ml 88.0 82.2 92.7 94.4 94.2 PV 0.313 0.303 0.351 0.333 0.350 %SOI 42.5 43.7 44.8 43.9 45.5 Waterflood resid (So) ml 119.0 105.8 114.3 120.6 112.8 PV 0.423 0.390 0.433 0.425 0.419 Tertiary recovery ml 21.4 101.0 94.3 100.7 103.9 PV 0.076 0.372 0.357 0.355 0.386 tor 18.0 95.5 82.5 83.5 92.1 Residual sat (Sof) ml 97.6 4.8 20.0 19.9 8.9 PV 0.347 0.018 0.076 0.070 0.044 Total recovery ml 109.4 183.2 187.0 195.1 198.1 PV 0.389 0.675 0.709 0.688 0.736 %Soi 52.9 97.4 90.3 90.7 95.7 * preflush was waterflood The following Table uses the data generated in Tables 6 and 7 to calculate the percent recovery of original oil in place (OIP) due to the tertiary recovery. The values were obtained by dividing the tertiary recovery values (e.g., PV values) by the corresponding values for initial oil saturation (Soj) Table 6 Tertiary recovery Example No. % OIP 1* 10.9 2 54.3 3 46.0 4 47.4 5 50.7 * polymer alone, not the present invention.

Table 7 Tertiary recovery Example No. %OIP 1* 10.3 2 53.8 3 45.5 4 46.8 5 50.2 * polymer alone, not the present invention.

Because the amount of oil produced during each of the fresh water preflushes was minimal, little difference can be seen in the results listed in Table 6 as compared to those in Table 7. The results listed in Table 6 will be used in the following discussion.

Example 1 involved injection of a 50 centipoise slug of Cyanatrol 940S polymer (3200 ppm) in the absence of any alkaline agent and is presented for comparative purposes only. The 18.7% Sor recovery is comparable to or better than the tertiary recoveries achieved with alkaline agents, alone, in some prior work which does not form a part of the present invention. Concurrent with the change in rate from 1.0 ft/day to 10.0 ft/day as part of the postflush sequence, additional oil production increase occurred. This phenomenon was not apparent in earlier tests using alkali without polymer. It would appear that in the presence of the improved mobility environment due to residual polymer in the core, the rate change and subsequent increase in pressure is sufficient to mobilize additional oil.The relative change in pressure on increasing the rate was actually lower in the polymer runs (average 3.7 fold increase) as compared to earlier non-polymer runs (average 4.8 fold increase). The actual higher pressures, though, may be the more significant parameter. For example, in Example 1, the change to 10.0 ft/day resulted in an overall core pressure of 1 98 psi as compared to an earlier run with the highest non-polymer, high rate pressure at 12.7 psi.

The absolute significance of this phenomenon is difficult to establish based on the existing data, but it should be safe to assume that comparisons of the various polymer-containing systems can be made directly, as the production spike occurs in all cases.

Examples 2 and 3 are duplicate injection sequences with the core's performance in Example 2 being generally superior to that in Example 3. The waterflood is considerably more efficient in Example 2, indicating a more homogeneous core, yielding better sweep efficiency. Also of note is the abnormally low initial oil saturation (0.692 PV) in Example 2, as compared with others in these Examples (0.736-0.784 PV). The 0.692 PV is not out of line with values for the previous corefloods (0.649-0.750). With the inherent core variability, the range of recoveries for Examples 2 and 3 would appear to be representative of the reproducibility for the polymer systems.

The 95.5 and 82.6% Sor recoveries for these two corefloods are in the range that generally is seen only with micellar/polymer systems in chemical flooding. The vast improvement of these systems over alkaline or polymer, alone, is the most significant result of the work presented here.

Examples 4 and 5, with Cyanatrol 940S brand polymer combined with sodium hydroxide and sodium orthosilicate, respectively, again show dramatic increases in recovery over their independent chemical counterparts previously tested. The initial oil saturation and waterflood performances of these runs are very similar, falling between the Example 2 and Example 3 situations. Because the cores for Examples 4 and 5, do appear comparable, the sodium orthosilicate system can be said to be superior to the sodium hydroxide, although, again, both systems are extremely efficient.

In all of the polymer and alkaline/polymer systems tested, very good mobility control was evidenced by the clean, high oil cut (~60%) samples produced prior to any injection chemical breakthrough.

Resistance Factors-Figures 2-6 list the pressure data for the corefloods.

This presssure data was obtained by measuring the differential pressures across the front, middle and rear sections of the core and was converted to corresponding resistance factors RF1-RF2 according to the following formula: P2 Q2 RF= P1 Q, P,=pressure dop at end of waterflood (psi) P2=pressure drop at given point during tertiary (psi) 01=flow rate at end of waterflood (ml/sec) Q2=flow rate at time of P2 measurement (ml/sec) RFt represents the cumulative resistance factor reading.

The resistance factors in Example 1 (Figure 2) with polymer alone, are considerably higher than those for the alkaline/polymer systems.

Comparing resistance factor responses for the various alkaline/polymer systems, it can be seen that the NaCO3/940S systems yield much lower values than either the NaOH/940S or Na4SiO4/940S systems. The middle section resistance factor (RF2) response during Example 4 (Figure 5) is not as significant as it appears. Due to an unusually low waterflood baseline pressure, the middle section resistance factors are calculated to be abnormally high, despite comparable pressure levels in all sections. The lower resistance factors with the Na2CO3/940S systems indicate potential for superior injection characteristics.

Produced Fluid Analysis-Greatly reduced divalent cation levels were found concurrent with alkali production. For Example 1, divalent cation levels dropped as a result of the fresh solvent water for the polymer being produced.

The alkali consumption data is listed in the following table. The measurements appear to be affected somewhat by the presence of polymer: Alk Meq Meq Meq Run injected injected produced retained 1 - - 1.94 -1.94 2 0.850 wt.% Na2CO3 44.31 29.79 14.52 3 0.850 wt.% Na2CO3 42.22 32.23 9.99 4 0.640 wt.% NaOH 45.39 27.77 17.62 5 0.764 wt.% Na4SiO4 44.69 22.13 22.56 Higher retention values are seen than were reported earlier, most likely due to the improved sweep efficiency allowing a greater surface area of rock to consume alkali.

Based on the results of the reported evaluations, the following conclusions can be made: The data demonstrate the superior recovery of residual oil obtainable by using alkali/polymer flooding under the viscosity and interfacial tension lowering characteristics required by the present invention. In a preferred embodiment, it has also been shown the use of Na2CO3 as the alkali (with polymer) produces a lower resistance factor in the coreflood than the use of either NaOH or Na4SiO4 as alkali with polymer. This yields an aqueous pusher fluid having superior injectivity characteristics.

In summary, the terminology "approximate interfacial tension minima" as used herein is intended to indicate very low interfacial tension values equal to or close to the absolute minima values obtainable. Such values fall within the "trough" area of the interfacial minima plot generated by comparing the tension values between alkaline solutions of varying concentration and the crude oil of interest. On such interfacial tension minima plots, these values correspond to interfacial tension values of less than 0.1 dyne/cm, preferably less than 0.07 dyne/cm.

The foregoing illustrate certain embodiments of the present invention and should not be construed in a limiting sense. The scope of protection desired is set forth in the claims which follow.

Claims (14)

Claims

1. An aqueous solution, adapted to be used in the recovery of crude oil from a geological formation, comprising alkali and polymer, which has a viscosity at least 50% of the viscosity of the oil to be recovered, and which produces an approximate minimum interfacial tension between it and the crude oil when injected into the formation, the alkali concentration being such that the interfacial tension between an aqueous solution of the alkali and the crude oil is less than 0.1 dyne/cm.

2. A solution as claimed in Claim 1 in which the polymer is present at from 1000 to 5000 ppm per million parts by weight of the water

3. A solution as claimed in Claim 1 or Claim 2 in which the polymer is an acrylamide polymer.

4. A solution as claimed in Claim 1 or Claim 2 in which the polymer is a polysaccharide.

5. A solution as claimed in Claim 1 or Claim 2 in which the polymer is a cellulosic polymer.

6. A solution as claimed in Claim 1 or Claim 2 in which the polymer is partially hydrolyzed polyacrylamide.

7. A solution as claimed in any of Claims 1 to 6 in which the alkali is selected from Na2CO3, NaOH and Na4SiO4.

8. A solution as claimed in any of Claims 1 to 7 in which the alkali is present at from 0.01% to 5%, by weight of the water.

9. A solution as claimed in any of Claims 1 to 7 in which the alkali is present at from 0.1% to 2%, by weight of the water.

10. A solution as claimed in Claim 1 in which the polymer is a partially hydrolyzed polyacrylamide and is present at from 1000 to 5000 ppm per million parts by weight of water and the alkali is Na2CO3 and is present at from 0.1% to 2%, by weight of the water.

11. A solution as claimed in Claim 1 substantially as herein described with reference to the Examples.

12. A process for recovery of crude oil from a geological formation which comprises injecting into the formation an aqueous solution as claimed in any of Claims 1 to 11.

13. A process as claimed in Claim 12 in which the polymer is a partially hydrolyzed polyacrylamide and is present at from 1000 to 5000 ppm per million parts by weight of water and the alkali is Na2CO3 and is present at from 0.1% to 2%, by weight of the water.

14. A process as claimed in Claim 1 2 substantially as herein described with reference to the Examples.

1 5. Crude oil when recovered from a geological formation by a process as claimed in any of Claims 12 to 14.