Oil Recovery With Water Containing Carbonate Salt and CO.sub.2

The invention relates to an oil recovery process in which oil is displaced by injecting a mixture of CO.sub.2 and aqueous liquid. More particularly, the invention relates to pre-forming such a mixture for coinjection in a manner significantly reducing its corrosivity, by including in the mixture an effective amount of dissolved monovalent cationic salt of carbonic acid.

In one aspect, the present invention provides an improved way of conducting the process of the type described in U.S. Pat. No. 2,875,833. That patent relates to an oil recovery process in which oil is displaced by injecting an aqueous solution which is substantially saturated with respect to carbon dioxide. In the present process, however, the saturated CO.sub.2 -solution can be mixed in any proportion with undissolved CO.sub.2 (e.g., it includes a so-called CO.sub.2 water alternate gas (WAG) process).

As stated in Enhanced Recovery Week (ERW), Sept. 9, 1985, "Carbonated waterflooding was largely dropped as an enhanced oil recovery (EOR) technique after initial investigations in the 1950s and Amoco's projects may be signaling a revival of interest (ERW, 4/29/85)". In the Nov. 25, 1985 ERW, it is indicated that Shell Western E & P plans a carbonated waterflood in the South Wasson Clear Fork Unit of the Wasson 72 field, making it the second company planning a carbonated waterflood. But, it is stated that, "Instead of injecting highly corrosive carbonated water, Shell will alternate small CO.sub.2 slugs with large water slugs, which will combine in the near wellbore reservoir into carbonated water."

The corrosivity of carbonated water is well known. U.S. Pat. No. 2,964,109 describes a utilization of carbonated water for acidizing a wellbore to remove a skin or layer formed during the drilling of the well. In that process carbon dioxide and water are injected into the well and held there under pressure until the pressure in the well begins to drop rapidly indicating a disintegration of the skin. Papers SPE 10685 and Canadian Institute of Mining (CIM) 83-34-17 discuss the dissolution of calcareous sandstones and carbonates by carbonated water.

The National Association of Corrosion Engineers Basic Corrosion Course, 1973, indicates that condenser corrosion is usually the result of dissolved carbon dioxide. It states that, "The CO.sub.2 is released from carbonates in the boiler and being volatile passes through the turbine into the condenser where it dissolves in the water, producing a low pH (acid conditions)." Such conditions cause thinning and grooving of the tubes if protective measures are not taken. And, the usual remedy is indicated to be making the solution alkaline to about pH 8.5 to 8.8 by additions of ammonia-type compounds such as morpholine or cyclohexylamine.

The present invention improves an oil recovery process in which a mixture of CO.sub.2 and aqueous liquid is flowed through conduits that may be corrosion-prone and injected into a subterranean reservoir that itself may be soluble or may contain grain cementing materials which are soluble in carbonic acid, in order to displace the oil. The present invention is thus a process for injecting such a mixture into a subterranean reservoir while reducing its corrosive effects without reducing its beneficial effects. The improvement comprises mixing the CO.sub.2 with an aqueous liquid containing enough dissolved monovalent cationic salt of carbonic acid to provide a pH which is at least about 4 but is insufficient to cause precipitation of multivalent carbonate salts at the pressure and temperature attained by the solution at substantially the depth of the reservoir formation. The CO.sub.2 which is mixed with the aqueous liquid can be all or partly dissolved in that liquid and can include CO.sub.2 in a CO.sub.2 -rich phase of the mixture in which at least some of the CO.sub.2 is gaseous, supercritical or liquid.

FIG. 1 shows a plot of aqueous liquid solution pH with increasing amounts of sodium bicarbonate or sodium carbonate at 170.degree. F. and 2500 psig.

FIG. 2 shows a similar plot at 77.degree. F. and 14.7 psia.

The present invention is at least in part premised on a discovery that the corrosivity of a premixed aqueous solution of carbon dioxide at the pressure and temperature of a subterranean reservoir can be significantly reduced in a relatively simple and economical manner. As indicated by the prior processes mentioned above, solutions of CO.sub.2 in water have sometimes been injected into subterranean reservoirs in spite of their corrosivity; or, in condenser corrosion prevention, have been rendered alkaline by additions of relatively expensive chemicals; or, in EOR, the operators have undertaken the relatively costly and manpower-intensive procedures of (1) alternating injections of slugs of CO.sub.2 and slugs of water at a frequency designed for causing mixing near the injection well and/or (2) adding corrosion inhibitors to production wells.

Although the prior processes are sometimes effective, some reservoir formations are heterogeneous or fractured or have portions which are soluble in carbonic acid as emphasized by the experiences reported in SPE 10685 and CIM 13-34-17, to an extent creating a risk of the CO.sub.2 being wasted. Where the CO.sub.2 is injected alternately with water, it may flow increasingly through the higher permeability zones and poorer volumetric sweep may result. These as well as other reservoirs may also be penentrated by wells containing corrosion-prone conduits.

Applicants have found the corrosivity can be significantly reduced and the likelihood of poor volumetric sweep can be avoided by injecting pre-formed carbonated water containing carbonate salt. In some sandstone reservoirs the present process also advantageously tends to reduce the driving force for clay transformations that might adversely affect oil production and/or reduce the dissolving of carbonate grain cementing material which might cause erosion due to intrusion of unconsolidated sand into the wellbores.

The reactions that take place in an aqueous solution in equilibrium with an excess CO.sub.2 phase are complex. When a carbonate solution contains multivalent cations, solid phases may form. Whether solids precipitate can be determined by comparing the solubility products of the various minerals with the products of the aqueous phase concentrations of the appropriate ions. The least soluble of these is calcium carbonate. When equations for the equilibrium constants for reactions between the various ionic species are combined with a charge balance and stoichiometric relationships, they yield a cubic equation for the concentration of hydrogen ions in solution:

The solution to such an equation can be found, either analytically or by simply evaluating the polynomial as a function of [H.sup.+ ] to determine the pH at which it changes sign. The ions from the salts in the brine do not appear in this equation because their contributions cancel one another. The brine does play a role, however, as it affects the activities of the solutes and the apparent concentration of carbonic acid.

The values of the equilibrium constants and apparent concentration of carbonic acid used in finding the solutions to the above equation are recorded in Table 1. For this example, the brine is modeled as 30% synthetic D-sand water (DSW) because it has nearly the same salinity as seawater (see Table 2), for which the appropriate equilibrium constants have been measured and correlated. These correlations are applied directly to 30% DSW to produce the values shown in Table 1. Although 30% DSW may have more or less total dissolved solids than water available for CO.sub.2 field projects, the calculations presented here should reflect aqueous carbonate equilibria in reservoir brines.

FIG. 1 displays the pH of a solution of 30% D-sand water in equilibrium with a free CO.sub.2 phase at 170.degree. F., 2500 psig as a function of Na.sub.2 CO.sub.3 or NaHCO.sub.3 content. This is representative of such a solution under reservoir conditions as a function of the amount of Na.sub.2 CO.sub.3 or NaHCO.sub.3 added. The pH rises quickly when Na.sub.2 CO.sub.3 is included. This is because Na.sup.+ is being substituted for H.sup.+ in satisfying the charge balance. Whether Na.sub.2 CO.sub.3 or NaHCO.sub.3 is incorporated, however, makes little difference on the pH of the system; it is the equivalents of Na.sup.+ that counts. Thus, the ratio of NaHCO.sub.3 to Na.sub.2 CO.sub.3 needed to achieve a given pH is equal to twice the ratio of the molecular weights.

There is one difference between Na.sub.2 CO.sub.3 and NaHCO.sub.3. The solution takes up CO.sub.2 to maintain equilibrium with the free CO.sub.2 phase when Na.sub.2 CO.sub.3 is added. By contrast, CO.sub.2 evolves from the solution when NaHCO.sub.3 is used. In either case, the amount of CO.sub.2 is small, corresponding to less than 5 SCF/bbl of solution for the concentration range depicted in FIG. 1.

For this example, the solubility product of CaCO.sub.3 is exceeded when the concentrations of Na.sub.2 CO.sub.3 and NaHCO.sub.3 reach approximately 0.42 wt% and 0.67 wt%, respectively. To keep CaCO.sub.3 from precipitating, the concentrations of the additives must be below these values. The amounts that can be added decrease as the hardness increases.

The equilibrium state differs greatly at surface conditions, e.g., 77.degree. F. and low pressure. In particular, calcium carbonate precipitates from the solution at lower levels of Na.sub.2 CO.sub.3 or NaHCO.sub.3.

If a free CO.sub.2 phase (or a CO.sub.2 -rich phase) is not present, as would ordinarily be the case in surface facilities, CaCO.sub.3 drops out of the 30% DSW solution, at a pH slightly below 9, when only 0.0012 wt% Na.sub.2 CO.sub.3 has been added. The case of adding NaHCO.sub.3 is somewhat better: 0.0168 wt% can be incorporated before CaCO.sub.3 precipitates (solution pH of 7.5). Nevertheless, neither of these chemicals can be added in quantities sufficient to raise the solution pH appreciably under reservoir conditions, as indicated in FIG. 1.

A way to keep calcium carbonate from precipitating in surface facilities is to store the solution under a blanket of CO.sub.2. The partial pressure of the CO.sub.2 can be relatively low. FIG. 2 displays the calculation of solution pH as a function of the Na.sub.2 CO.sub.3 or NaHCO.sub.3 content when the partial pressure of CO.sub.2 is one atmosphere. 0.15 wt% Na.sub.2 CO.sub.3 or 0.24 wt% NaHCO.sub.3 can be added to the brine before CaCO.sub.3 drops out. (Even more Na.sub.2 CO.sub.3 or NaHCO.sub.3 can be included if the partial pressure of CO.sub.2 is higher.) These amounts give a pH of about 4.5 under reservoir conditions (see FIG. 1).

The saline aqueous solution (or water or brine) which is used in the present process can be substantially any which can be flowed through the reservoir to be treated without significant change due to dilution and/or increases in salinity due to diffusion and/or ion-exchange effects within the reservoir. Such a brine is preferably the brine produced from the reservoir to be treated or produced from a nearby reservoir. When the reservoir has been waterflooded with a brine less saline than the reservoir brine, the brine used in the present process preferably has a salinity which is substantially equivalent in the effective ratio of monovalent to multivalent cations relative to the brine used in the waterflood after it reached a state of equilibrium with the rocks in the reservoir.

The monovalent cationic salt of carbonic acid which is used in the present process can comprise substantially any alkali metal or ammonium salt. Sodium carbonate, sodium bicarbonate, or mixtures of them, are particularly preferred for such use.