Polymeres useful in the recovery and processing of natural resources

Abstract: Water-soluble polymers comprising an N-vinyl lactam are found to be useful in processes wherein the polymer is introduced into a subterranean wellbore. Polymers useful in the recovery of natural resources are prepared by polymerizing an N-Vinyl lactam by free radical initiation with polymerization conducted in an aque­ ous solution polymerization medium preferably containing a mixture of dissolved electrolytes, or in a polymerization medium consisting essentially of a tertiary alkanol. Copoly­ mers of such N-Vinyl lactams with unsaturated amides, and terpolymers prepared by polymerizing an N-Vinyl lactam and an unsaturated amide with a selected termonomer compound are also useful when prepared by these methods. The invention also broadly encompasses utilizing a water soluble polymer comprising at least one of a hydro­ philic vinyl-containing sulfonate and a hydrophilic N-vinyl lactam under hostile conditions.

Description: BACKGROUND Many synthetic polymers have been developed and used in processes for the recovery of natural resources. Generally a desirable property is that such polymers impart to a liquid an increased viscosity when a relatively small quantity of the polymer is added, and preferably at a minimal cost. There is an increasing demand for such polymers which will withstand hostile environments including, e.g. high temperatures, high salinity and high content of multivalent metal cations, commonly known as "hardness ions", as well as the high acidity, temperature and shear conditions encountered in processes such as acid fracturing. ENHANCED OIL RECOVERY Oil accumulated within a subterranean oil-bearing formation is recovered or produced therefrom through wells, called production wells, drilled into the subterranean formation. A large amount of such oil is left in the subterranean formations if produced only by primary depletion, i.e., where only formation energy is used to recover the oil. Where the initial formation energy is inadequate or has become depleted, supplemental operations, often referred to as secondary, tertiary, enhanced or post-primary recovery operations, are employed. The term "enhanced" will be used herein to refer to all such operations. In the most successful and most widely used of these operations, a fluid is injected into the formation by pumping it through one or more injection wells drilled into the formation, oil is displaced within and is moved through the formation, and is produced from one or more production wells drilled into the formation. In a particular recovery operation of this sort, field water or field brine is usually employed as the injection fluid and the operation is referred to as a waterflood. The injection water is often referred to as flooding liquid or flooding water as distinguished from the in situ formation, or connate water. Fluids injected later can be referred to as driving fluids. Although water is the most common, injection and drive fluids can include gaseous fluids such as steam, carbon dioxide, and the like. Steam stimulation is particularly desirable under conditions of a hostile environment. In a steamflood operation crosslinked or uncrosslinked polymeric viscosifiers in an aqueous surfactant solution and steam are injected into subterranean formations to effect permeability correction by transporting foamed surfactant into high permeability zones to divert subsequently injected steam to the relatively oil-rich less permeable zones. The polymeric viscosifier thereby greatly enhances the thermal stability of the foamed surfactant solution thus prolonging the effective time period of the permeability correction operation. In another steam stimulation technique, the steam is injected into the reservoir followed by an extended shut in period of for instance 1-2 weeks. The steam is followed by a hot aqueous surfactant active composition. The well is put back in production immediately and any steam channelling through the surfactant causes it to foam and block the steamflow. The steam finds an alternate lower temperature zone where the heat will be transferred to the oil and formation thus providing a more efficient steam stimulation process. As the steam condenses and the foam collapses, the channels open up to produce oil. The presence of the polymers described herein (gelled or ungelled) with the steam stabilizes the foam. The foam processes to which this invention can be applied are described in U.S. 3,993,133. Although conventional waterflooding is effective in obtaining additional oil from oil-bearing subterranean formations, the technique does exhibit a number of shortcomings. Foremost among these shortcomings is the tendency of flooding water to "finger" through an oil-bearing formation and to thus bypass substantial portions thereof. By fingering is meant the development of unstable water stream fronts which advance toward the production wells more rapidly than the remainder of the flooding water. Furthermore, when fingering is encountered, the water does not normally displace as much oil in the portions of the formations which it contacts as it is potentially capable of displacing. It has been established that waterfloods perform less satisfactorily with the more viscous oils than with relatively nonviscous oils. The fingering and bypassing tendencies of water are related to the ratio of the viscosity of the oil to the viscosity of the flooding water, and also related to fractures and/or high permeability zones in the formation. The viscosity of these oils varies from as low as 1-2·10⁻³ Pas (one or two centipoise) 1 Pas to (1,000 centipoise) or higher. Water generally has a viscosity of about 1 centipoise at room temperature. In order to restrict the mobility of the flooding water to no greater than the mobility of the oil, water thickening agents have been added to increase the viscosity of the water. Suitable agents for increasing the viscosity of the flooding water are water-soluble or water-dispersible, high molecular weight polymers. These polymers may adsorb on the formation surfaces, and accumulate in (or absorb) and reduce permeability through the rock pores. Consequently, the polymers cause the flooding water (which can contain polymer or other agents) injected therebehind to flow into previously uninvaded portions of the formation. However, these polymers are susceptible to adverse effects present in some subterranean formations, such as high temperature and dissolved electrolytes, which cause the polymers to precipitate and/or lose their viscosity-enhancing effectiveness, thus increasing flood water mobility, and generally become less effective as mobility control agents. To maximize the recovery of oil in post-primary oil recovery operations, a substantially uniform permeability should exist throughout the strata. If the formation permeability is heterogeneous, the flooding fluids will seek areas of high water permeability, producing channeling and the passage of excess driving fluid to the producing well. As the more water-permeable strata are depleted of oil, the driving fluid thus has a tendency to follow such channels and further increase water production. reflected in an increased water/oil ratio at the producing well. More uniform flood fronts can be obtained in formations of nonuniform permeability by permeability correction of the more water-permeable strata of the formation. One method for reducing the water permeability of these more permeable strata is the injection of plugging materials into the formation strata to at least partially plug the more water-permeable zones and achieve reduced water permeability in said zones. Plugging materials can be formed in situ in the formation by the injection of one or more reactant substances which chemically react to form bodies of reduced water permeability, particularly polyvalent metal-crosslinked polymeric viscosifiers, alternatively monomers or prepolymers which are polymerizable under formation conditions. DRILLING, WORKOVER AND COMPLETION FLUIDS In the art of drilling wells to tap subterranean deposits of natural resources, such as gas, geothermal steam or oil, especially when drilling by the rotary method or the percussion method wherein cuttings must be removed from the bore hole, it is necessary to use a drilling fluid, as is well known to those skilled in the art. The subject is discussed more fully in U.S. Patent 3,025,234. In addition to having the desirable rheological properties such as viscosity and gel strength, it is very important that such drilling fluids exhibit a low rate of filtration or water loss, that is, the drilling fluid must prevent excessive amounts of fluid, or "filtrate", from flowing from the bore hole into the surrounding formation. The loss of water or other fluid from the drilling fluid is prevented by the formation of a filter cake which deposits from the drilling fluid and seals the wall of the bore hole. To produce an effective drilling mud, the clays mixed with water should disperse to a certain extent, not exceeding an acceptable operating range. That is, the individual clay particles should hydrate and repel each other and will remain in suspension (forming a "mud" or viscous drilling fluid) and filter out to form a relatively less permeable coating on the borehole walls. Excessive flocculation, however, causes larger particles to form, with the result that none of the objects of a drilling mud" are achieved. Numerous formulations, compositions and additives to optimize the performance of drilling fluids for various applications have been developed. For instance, U.S. patent 3,816,308 discloses compositions comprising mixtures of carboxylic acid polymers and soluble metal salts with the object of increasing the "yield" (defined as the number of 159 ℓ units (barrels) of 15-10⁻³ Pas (15 centipoise) mud which can be prepared from one ton of clay) of relatively low-grade bentonite clays. High-yielding bentonite clay, when treated with high molecular weight polyacrylamide and polyacrylate polymers or copolymers of vinyl acetate and maleic anhydride, can be made to produce about the same viscosity as twice the amount of untreated bentonite. See Park et al, Oil & Gas Journal, May 30, 1960, pp. 81-84. Excessive fluid loss from the drilling fluid may contaminate the producing formation, permanently displacing oil and blocking production. If the formation penetrated is of the heaving shale type, such shale may absorb water from the drilling fluid and by a caving or swelling action, common to bentonite materials, close the bore hole around the drill stem, choke off circulation of drilling fluid, and seize the drill string. Similar results may occur simply from the abrupt increase in viscosity of the drilling fluid which is caused by excessive fluid loss. The adverse consequences of excessive fluid loss in the drilling of very deep wells are more severe due to the high temperatures and pressures encountered in such drilling operations. To increase the density of the drilling fluid so that it will exert sufficient hydrostatic pressure on the balls of the borehole, weighting agents such as head insoluble metal salts are added to the fluid. Drilling fluids must be of sufficient viscosity to maintain the weighting agent in suspension, but a relatively small decrease in fluid content may increase such viscosity to the point where the drill string binds. The tendency to lose liquid in a borehole is greatly increased by the high temperatures and pressures encountered. Since most drilling fluids are "non-Newtonian" fluids, the apparent viscosity at given conditions of shear rate and shearing stress may change in a non-linear manner with certain parameters. This property makes it difficult to provide drilling fluids which will perform within acceptable ranges during the entire process of drilling a well. In the mixing of drilling fluids in preparation for drilling operations, agitation at a certain degree of shear for some period of time is normally required to achieve the desired degree of thickening, but excessive agitation may cause the apparent viscosity to decrease. Since the degree of shear achieved in most drilling fluid circulating systems is low, it is important that a minimum of mixing time at a relatively low rate of shear produce the desired thickening, so that maximum thickening is obtained under operating conditions. Measurable variables which may characterize the apparent viscosity of a drilling fluid include the plastic viscosity, yield point and the rate and degree of gelation. The viscosity of a fluid normally decreases with an increase in temperature, but certain polymer additives or deflocculating agents may reduce, or even reverse, this tendency. However, the long-chain polymers which are most effective in achieving this effect are the most vulnerable to breakdown through oxidation, shear and thermal effects, i.e. the duration of exposure to high temperature drilling operations. Also, many such polymers tend to precipitate and/or lose viscosity as well as effectiveness as water loss additives when exposed to dissolved electrolytes, particularly when divalent metal cations such as Ca⁺⁺ and Mg⁺⁺ are present. In drilling fluids, the resulting vulnerability to breakdown is exacerbated by the density of the mud, which is directly related to the weighting agents required for a given formation pressure. The extremely high temperatures encountered in drilling geothermal wells also tend to cause early breakdown of mud additives. Breakdown of water loss control polymers or deflocculants causes a large increase in the fluid loss accompanied by an increase in filter cake thickness. The thickness of filter cake will be determined by the solids content of the mud. High density drilling fluids with large amounts of weighting materials produce very thick filter cakes when fluid loss control is lost. These conditions often result in differential sticking of the drill string. It is desirable to develop additives which will enable drilling fluids to retain their proper viscosity and fluid content over a broader range of conditions. Drilling fluids are used in the drilling of various types of wells. Workover and completion fluids, in contrast, are those fluids used in the completion and servicing of such wells. Completion fluids are those fluids used after drilling is complete and during the steps of completion, or recompletion, of the well. Completion can include cementing the casing, perforating the casing, setting the tubing and pump, etc. Workover fluids are those fluids used during remedial work in the well. This can include removing tubing, replacing a pump, cleaning out sand or other deposits, logging, reperforating, etc. Further with regard to sand consolidation, the polymers described herein are particularly useful because of their stability under hostile environment conditions. Sand consolidation is broadly disclosed in U.S. 3,978,928. The in situ gelation of the polymeric viscosifier can involve crosslinking through the use of polyvalent metal ions such as aluminum or chromium or a sequestered metal system such as aluminum citrate, as described in detail herein. In one embodiment of this invention the polymers disclosed can be used as thickening agents in hydraulic fracturing processes of the type described, for instance, in U.S. 3,727,689 the disclosure of which is hereby incorporated by reference. The use of polymeric viscosifiers comprising N-vinyl-2-pyrrolidone/acrylic amide copolymers such as 50/50 wt/wt poly (N-vinyl-2-pyrrolidone-co-acrylamide) imparts excellent thermal stability to said fracturing fluids even in the presence of hard brines and high temperature, i.e. hostile environments. Other ratios of monomers can also be used, generally from 70:30 to 30:70 weight percent poly(N-vinyl-2-pyrrolidone:acrylamide). Polyvalent metal crosslinking of said copolymers can be effected by a redox couple e.g., sodium dichromate/sodium bisulfite or with aluminum cation sequestered with citrate as further described herein. In one embodiment, this invention is used in fracture plugging of subterranean formations as disclosed in U.S. 3,845,822. In a fracture plugging process the in situ polyvalent metal crosslinking of the polymeric viscosifiers is triggered by the sequential injection of (1) an oxidant composition containing a reducible polyvalent metal such as chromium +6 as sodium dichromate and (2) a water-soluble sulfur-containing reducing agent such as sodium bisulfite (redox system). The stability to hostile environment conditions of the polymers described herein make them particularly suited to use in fracture plugging. Workover also broadly includes steps used in preparing an existing well for secondary or tertiary oil recovery such as polymer additions, micellar flooding or steam injection. Both workover and completion fluids are used in part to control well pressure, to prevent the collapse of casing from overpressure, and to prevent or reduce corrosion of casing. A drilling fluid may be suitable for completion or workover applications in some cases, but not in all cases. When a special workover or completion fluid is used, it is usually a poor or unsuitable drilling fluid. The compositions of workover and completion fluids can differ from the compositions of drilling muds, since workover and completion fluids have functions which differ from those of drilling fluids. A workover or completion fluid differs from a drilling fluid in several ways. A workover fluid does not have to be compatible with drilled solids. Usually, a workover fluid is used in cased holes, and the formation is exposed only at perforations. Whereas a drilling fluid must protect the formation from swelling or disintegration, a workover fluid must not damage the permeability of the formation. Ideally, a workover fluid would contain no solids. If solids must be used, they should be acid soluble. Similarly, the compositions, properties and functions of workover fluids can differ from those of completion fluids. Although there has been considerable progress in the field of workover and completion fluids, there is significant room for further improvement. For example, wells are being completed and serviced in increasingly hostile environments involving, e.g., high temperatures and high levels of salinity and/or hardness in the formation water. Thus, new additives for workover and completion fluids which retain their properties at elevated temperatures and high concentrations of dissolved electrolytes are in demand. POLYMER ADDITIVES In some cases, various polymers have been found useful in more than one application, such as those described above. However, among the most severe applications is enhanced oil recovery, in which polymer additives must form stable and viscous aqueous solutions while exposed to high temperatures and dissolved electrolytes for as long as several years, often requiring retention of a solution viscosity of at least about 10⁻² Pas (10 centipoises) at room temperature, and, must reduce the permeability of rock to the flooding water by adsorbing on the rock in the formation. Many commercial water-soluble polymers have been tested for applicability in enhanced oil recovery, but prior to the present invention no such polymer has fully satisfied the requirements referred to above. Polyacrylamide, for example, provides the desired viscosity and reduces rock permeability in many instances, but it frequently loses viscosity in water containing dissolved electrolytes. Polyvinylpyrrolidone, although stable in the presence of dissolved electrolytes including multivalent cations at the temperatures high enough to cause hydrolysis of polyacrylamide at significant rates (i.e., > 93°C (200° F)), has only been available in grades of low viscosity. Polyvinylpyrrolidone also demonstrates undesirable adsorption on rock, thus an undesirable resistance factor and residual resistance factor. Furthermore, polyvinylpyrrolidone is much more expensive than polyacrylamide and many other commercial polymers. Thus, it is apparent that as the demand for recovery and processing of natural resources increases, improved polymer additives for such processes as enhanced oil recovery will be in demand. See, e.g., Davison and Mentzer, "Polymer Flooding in North Sea Oil Reservoirs," paper SPE 9300, presented at Fall Conference of Society of Petroleum Engineers of AIME, Dallas, TX, Sept. 21-24, 1980 and published in the Society of Petroleum Engineers Journal, June 1982, pp. 353-62. Davison and Mentzer evaluated over 140 polymers (generally classified as polyacrylamides, polyvinylpyrrolidones, hydroxyethyl celluloses, cellulose sulphate esters, guar gums, xanthans and scleroglucans) for viscosity retention and porous media flow performance under high temperature (90° C, 194 F), high salinity, and high pressure conditions. For polymer flooding in North Sea oil reservoirs, the criteria were that a polymer solution should be five times more viscous than sea water and lose less than 20 percent of its viscosity in 500 days at 90° C. Scleroglucan polymers gave the best performance in the tests, producing the required viscosity in polymer solutions of about 500 ppm and retaining most of this viscosity through 500 days' aging at 90° C. Polyacrylamides were "particularly unsuitable", as they precipitated within 60 days in 90° C seawater, apparently due to the presence of calcium and magnesium ions. Polyvinylpyrrolidones were very stable but had to be used in high concentrations (20,000 ppm) to give adequate viscosity. There is no indication that copolymers of vinylpyrrolidones and acrylamides were tested at high temperatures. McCormick et al DOE/BETC/5603-10, p. 5, 117 prepared such copolymers but concluded that they had "low solution viscosity and appear of little value in EOR." Thus they were not tested. Thus, there is a substantial need for polymers which would be useful in the recovery of natural resources in hostile environments, such as in North Sea oil reservoirs, and in various operations for processing natural resources in hostile environments. SUMMARY OF THE INVENTION Accordingly, the invention relates to a process for enhancing oil recovery or for the drilling, workover or completion of wells for the recovery of natural resources in a hostile environment, as defined in claim 1 and the dependent claims. The polymers used in the process of the invention are stable when exposed to water of significant salinity and/or hardness. The polymers can be at least partially dissolved in various fluids, including for example an aqueous fluid, or in a fluid containing at least one composition selected from the group consisting of bases, polymeric viscosifiers, surfactants and cosurfactants, and combinations of any two or more of said compositions. The polymers can be crosslinked with various crosslinking agents. The polymers are water-soluble or water-dispersible. In accordance with this invention a polymer which is not capable of imparting as high a viscosity to water as a polyacrylamide is used under hostile environment conditions where acrylamide polymers are useless because of precipitation. BRIEF DESCRIPTION OF THE DRAWINGS FIGURES 1 and 2 illustrate the degree of hydrolysis of the acrylamide units attained in copolymers used in the process of the invention aged at different temperatures. FIGURE 3 is a plot of cloud point versus multivalent cation concentration. FIGURE 4 is a plot of per cent hydrolysis versus days aged. FIGURE 5 is a plot of precipitation times as a function of temperature and divalent ion concentration. FIGURES 6 and 7 are plots of aged viscosity data on polymers having monomer ratios of components as shown on the triangular graph. DETAILED DESCRIPTION OF THE INVENTION Polymers The copolymers and terpolymers used in the process of this invention appear to be well suited for various applications including enhanced oil recovery (EOR), drilling fluid water loss additives, workover and completion fluid additives, selective plugging of "thief zones", minerals beneficiation, water thickening, cater treatment, and the like. In a presently preferred embodiment, the copolymers and terpolymers, to be described subsequently, are well adapted because of their outstanding viscosity stability in hostile, saline, hard water environments, for polymer-flooding purposes. A hostile environment for the purpose of this application is one in which the temperature, salinity and/or hardness cation content is high enough to cause precipitation, loss of viscosity and/or similar adverse effects within a nominal period of time in conventional polymers otherwise suitable for use in such applications. Such conventional polymers include, for example, polyacrylamides. The advantages of the polymers of this invention are apparent when they are employed in hostile environments of from 77 to 149°C (170 to 300°F) as specifically defined in Figure 5. Brackish and/or hard aqueous fluids having a salinity of at least about 10 grams per kilogram of solution and/or a fraction of divalent hardness ions to total cations of from 500 to 220000 ppm, e.g. at least about 1 weight percent (10000 ppm) and particularly at least about 5 weight percent (50000 ppm) in combination with temperatures of at least 77°C (170°F) are considered hostile environments. Since hardness cations such as Ca⁺² and Mg⁺² are particularly damaging to many such polymers, when the salinity and hardness cation content are relatively high the hostile zone is defined by a relatively lower temperature. A hostile environment, for example, is one wherein the reservoir temperature can be as low as 77°C (170°F) and the electrolyte concentration of dissolved salts in the available water, both injection water (which may be seawater) and formation water, is at least 35,000 ppm (with about 1750 ppm combined calcium and magnesium ions), i.e., about 3.5 weight percent or higher, equivalent to a salinity of about 35 grams per kilogram of solution. At lower reservoir temperatures, from e.g. about 49°C (120°F) up to about 66°C (150°F), a relatively higher salinity and/or content of hardness cations would create such a hostile environment, say, for example a salinity of at least 50-100 grams per kilogram with a fraction of divalent hardness cations to total cations of at least 20 weight percent. At temperatures of at least 49°C (120°F), a hostile environment for polymeric viscosifiers could also be created by a strongly basic environment, e.g., concentrations of at least 5 weight percent of strong base, which accelerates the hydrolysis process in many polymers. Such conditions are encountered in processes comprising: e.g., caustic flooding of oil-bearing subterranean formations. A hostile environment can best be viewed as one in which conventionally used thickening agents are unstable. Polyacrylamides are such conventionally used thickening agents. Polyacrylamides as commonly used for Enhanced Oil Recovery (EOR) hydrolyze at elevated temperatures and will eventually precipitate in the presence of divalent cations. The following is the method by which the limits of a hostile environment are determined using this criteria. That is, the boundary below which this polymer remains in solution indefinitely and above which in days or months it falls out of solution, resulting in loss of polymer viscosity and plugging of the formation defines a hostile environment. Any polyacrylamide in hard brines will eventually turn cloudy (i.e., begin to precipitate if its temperature is raised high enough). Figure 3 shows the cloud point as a function of divalent cation concentration for 1000 ppm by weight originally unhydrolyzed commercial polyacrylamide in various brines. These solutions were thermally hydrolyzed to different levels in 5% saline solution prior to addition of divalent cations (equal amounts of calcium and magnesium in ppm by weight) and making cloud point measurements. In the absence of divalent cations (a condition not found in petroleum reservoirs), this polymer stays in solution up to 204°C (400°F) (the limits of the measurement) regardless of the level of hydrolysis. The presence of divalent cations, on the other hand, affects the cloud point depending on the hydrolysis and hardness level. That is, the higher the hydrolysis level and divalent cation concentration, the lower the cloud point. Figure 4 shows the effects of time and temperature on the hydrolysis of 1000 ppm of the same unhydrolyzed commercial polymer. This figure indicates that at a given temperature the level of hydrolysis increases with time, but eventually reaches an equilibrium. Using a standard thermodynamic treatment of an equilibrium reaction, where K eq is the equilibrium constant, ΔS° and ΔH° are the standard entropy and enthalpy changes for the reaction, R is the gas constant and T is the absolute temperature Fitting this equation to K eq and T values derived from Figure 4 gave values of ΔS° and ΔH°, which were then used to calculate K eq and equilibrium level of hydrolysis for any desired temperature. A standard analysis of the kinetics of hydrolysis gives the following equation where Ao, Ae and A are the amide concentrations at zero time, at equilibrium and at t, respectively, and k f is the rate constant for the forward (hydrolysis) reaction. By fitting amide concentrations to equation (2) k f values were calculated for the five temperatures represented in Figure 4. A fit of these results to the Arrhenius equation k f = Ce -Ea/RT (3) gave values for C, the pre-exponential factor and Ea, the activation energy. The forward rate constant for any desired temperature could then be calculated. Using the k f value for a given temperature and equation (2), the time required to achieve a given degree of hydrolysis can be calculated. This can be done so long as the desired hydrolysis level is lower than the equilibrium level of hydrolysis for that temperature, that is as long as A>Ae in equation (2). For A=Ae this equation predicts time to approach infinity, and for A<Ae time is undefined. In other words the hydrolysis level at any temperature cannot exceed the equilibrium value for that temperature. Figure 3, with appropriate interpolation, can be used to define the hydrolysis level that causes the onset of precipitation for any given temperature and hardness level. Equations (1), (2), and (3) predict the time taken to reach this level of hydrolysis. If the equilibrium hydrolysis level is less than the level causing instability, the time is infinite. In other words, an initially unhydrolyzed polyacrylamide will be indefinitely stable under the chosen conditions. If the equilibrium hydrolysis level is greater than the level causing instability, the polymer will ultimately precipitate and the calculation gives the time to the onset of instability. If the two hydrolysis levels are exactly equal, the stability limit has been defined. By repeated calculations at closely spaced temperatures for many hydrolysis levels, Figure 5 was generated. This gives contour lines of equal precipitation time as a function of temperature and hardness level. Any conditions above and to the right of the infinity line represent hostile environments for polyacrylamides in the sense that the polymer will eventually precipitate. Note that the 100 days line lies very close to the infinity line, indicating that within a practical range of times for EOR projects the actual stability time is not much of an issue. It must be pointed out that Figure 5 is for an unhydrolyzed polymer and the stability times represented are much longer than for already partially hydrolyzed (∼30%), polyacrylamides commonly used in EOR. Furthermore, the polymer used in this study has a moderate molecular weight (MW) and those commonly used in EOR with higher MW will precipitate at lower temperatures under the same hardness and hydrolysis levels. It must also be mentioned that polymer concentration may play a role in precipitation of polymer and Figure 5 represents stability limits for 1000 ppm of polymer. Since there is so little difference between the 100 day curve and the infinity curve, there is no need to make an arbitrary designation of a time limit for the time parameter but rather infinity can be used. Also, since almost all formations where there is an otherwise hostile environment will have at least 400 to 1000 ppm multivalent cations, and since the infinity curve becomes almost flat after about 1000 ppm, the hardness parameter can simply be anything greater than 500-1000 ppm by weight multivalent cations. This leaves the temperature as the significant factor. the temperature being anything over 77°C 170°F at greater that 1000 ppm multivalent cations although, of course, defining the hostile environment as above (i.e. above and to the right) of the infinity line is more precise. Generally the temperature will be within the range of 77 to 204°C (170-400°F), for example 77 to 149°C (170-300°F) and the multivalent cation concentration will be within the range of 500 to 220,000 or more likely 1000 to 10,000 ppm by weight based on the weight of water. Although several biopolymers have been reported to be stable in sea water for extended periods at temperatures up to a range of from about 66°C (150°F) to nearly 93°C (200°F), above about 93°C (200°F) the only water-soluble polymer known to maintain its solution viscosity under these conditions is polyvinylpyrrolidone (PVP). However, PVP is relatively expensive and it requires high concentrations, e.g. about 2 weight percent or more, to obtain suitable viscosities for polymer flooding. The copolymers and terpolymers used in the process of this invention are generally water-soluble and cheaper to prepare than PVP. These polymers can be retained in solution in the aqueous polymerization medium in which they are prepared. When prepared by radiation polymerization in a viscous polymer mass (commonly known as a "gel log") the polymers are also water-soluble. However, when the polymer is separated from such an aqueous medium and dried, it is generally expected to be water-dispersible and/or swellable, but may not be completely water-soluble. On the other hand, the polymers separated from a polymerization medium consisting essentially of a tertiary alkanol and dried appear to be generally water-soluble, which can be an advantage when a granular, water-soluble polymer material is desired. They have been found to provide adequate solution viscosity with exceptional thermal stability and resistance to electrolyte effects, thus are superior to PVP for EOR in hot, saline environments, especially those containing "hardness" or multivalent metal cations such as Ca⁺² or Mg⁺². The terpolymers and most of the copolymers used in the process of this invention contain as comonomer N-vinyl-2-pyrrolidone (NVP or VP) and/or acrylamide (Am), wherein the term acrylamide includes N-methylacrylamide and N,N-dimethylacrylamide (DMAm). The minimum amount of NVP required is that amount necessary to provide the desired polymer properties, e.g. viscosity and stability, under the expected environmental conditions. For example, polymers containing a minor amount, up to about 10 weight percent, of the vinyl lactam could be effective in the recovery and processing of natural resources, such as for example in enhanced oil recovery in and/or formation waters of significant salinity and/or hardness. Polymers of these proportions could also be useful under more adverse conditions if exposed for shorter periods of time. The monomer weight ratios of the copolymers can vary rather widely. Generally, VP:Am ratios in the range from 10:90 to 90:10 are employed depending upon the intended application, but preferably VP:Am weight ratios in the range of 25:75 to 75:25 are employed, more preferably from 40:60 to 70:30. The optimum VP:Am weight ratio may vary according to the application. For example, in EOR the range presently preferred is from 65:35 to 50:50, based on prolonged aging studies conducted with the copolymers. A copolymer presently particularly preferred for certain applications after heat aging at 121°C (250°F) contains 60 weight percent VP and 40 weight percent Am, corresponding to a 1:1 molar ratio. The VP:Am weight ratios of 10:90 to 90:10 correspond to molar ratios of 6:94 to 85:15. After heat aging, copolymers of these 60:40 proportions have been found to retain their viscosity well in hot, saline environments. On the other hand, when the copolymers are to be used without such pre-aging, higher, if less persistent, viscosities have been obtained with copolymers having VP:Am weight ratios in the range of from 45:55 to 55:45, or preferably about 50:50. Since the VP:Am weight ratios are expressed in terms of 100 parts by weight of the copolymer, the weight percentages of the monomer units in the copolymer can be read directly. In the NVP Am copolymers described above up to 10 Wt.% of the total monomers can be replaced by a third monomer selected from the group consisting of hydrophobic compounds, vinyl pyridines and hydroxyalkyl esters of ethylenically-unsaturated carboxylic acids and combinations of any two or more thereof. For convenience, the third monomer will hereinafter be referred to as a termonomer, as distinguished from the first and second monomer units described above, which are referred to as VP and Am for convenience. The hydrophobic compounds suitable for the termonomers are generally selected from the group consisting of monovinyl aromatic hydrocarbons having from 8 to 12 carbon atoms such as styrene, vinyl esters of saturated carboxylic acids having from 3 to 6 total carbon atoms such as vinyl acetate, alkyl esters of ethylenically-unsaturated monocarboxylic acids having from 3 to 22 carbon atoms, such as ethyl acrylate, and ethylenically-unsaturated nitriles having from 3 to 5 total carbon atoms, such as acrylonitrile. Other suitable hydrophobic monomers are N-vinyl acetamide and 2-vinyl quinoline. Also suitable hydrophobic monomers are acryloyl pyrrolidones, diacetoneacrylamide and N- and N,N-alkylacrylamides where the alkyl groups contain more than two carbon atoms. By hydrophobic is meant that if the monomer were homopolymerized it would be water insoluble although in amounts up to 25 percent it can be present herein and the total polymer is still water soluble. Other suitable compounds (hydrophilic but not anionic) include vinyl pyridines such as 4-vinyl pyridine, acryloyl morpholine, methyl vinyl ether, ethyl vinyl ether, dimethylallyl ammonium chloride, dimethylaminoethyl acrylate, N-vinyl urea, acryloyl urea, N,N-diethylaminoethyl acrylate, N-methyl acrylamide, tert-butylaminoethyl acrylate, dimethylaminopropyl methacrylamide, methacrylamidopropyl trimethyl ammonium chloride, and hydroxyalkyl esters of ethylenically-unsaturated monocarboxylic acids having from 3 to 22 carbon atoms, such as hydroxyethyl acrylate. Termonomers which are presently preferred comprise methyl acrylate, butyl acrylate, methyl methacrylate, lauryl methacrylate, acrylonitrile, diacetone acrylamide and styrene for increasing the hydrophobic character of the terpolymers, vinyl pyridines, hydroxypropyl methacrylate and hydroxyethyl methacrylate and hydroxyethyl acrylate as water soluble monomers which increase the hydrophilic character of the terpolymers without introducing termonomers which are sensitive to metal cations (and because good results have been obtained with 4-vinylpyridine and 5-methyl-2-vinylpyridine); and vinyl acetate due to its low cost and ready availability. The first and second monomer units can be present in approximately the range of weight ratios disclosed for the copolymers, constituting the major portion of the terpolymer, with the termonomer providing the remaining minor portion of up to 10 weight percent of the monomer units charged. For example, the terpolymer can consist of 45 weight percent each of the first and second monomers, with 10 weight percent of the termonomer, 49 weight percent each of the first and second monomers with 2 weight percent of the termonomer, and so on. These examples contain the first and second monomer units in weight ratios of 50:50, but as disclosed above, the three monomer units can be combined in any combination, provided the termonomer does not exceed 10 weight percent, but preferably is at least 1 weight percent, and the first and second monomer units are within the range of weight ratios as disclosed for the copolymers. Based on the examples, the termonomer is preferably present as from 2 to 8 weight percent, or more preferably, from 3 to 5 weight percent, based upon total monomers. As the copolymerization reaction produces polymer in near-quantitative yield, the desired ratios of VP to Am can be obtained by controlling the ratios of VP monomer and Am monomer charged to the reactor and the rates at which the monomers are fed into the reactor. Another significant aspect of this invention is described as follows. Polyacrylamide has historically been a standard material for thickening water for oil recovery. At a concentration of, for instance, 0.25 weight percent in sea water, polyacrylamide imparts a viscosity to the resulting solution which is about ten to twenty times the viscosity of sea water at the same temperature. For instance, sea water at room temperature has a viscosity of approximately 1 compared with 10 to 25 for the same water containing a quarter weight percent polyacrylamide and this viscosity remains essentially unchanged on aging at room temperature. At 250°F (121°C) sea water has a viscosity of about 0.3. The same water with 0.25 weight percent acrylamide initially has the viscosity of about 10 but on aging the acrylamide precipitates rendering it totally useless with the resulting sea water not having a viscosity increased any after the precipitation. The following description of Figures 6 and 7 show that in accordance with the invention, significant enhancement of the viscosity of polymer flood water is possible when the water is to be used in reservoirs exhibiting hostile conditions. In Figures 6 and 7 the viscosity data is for polymer aged 7 days at 149°C (300°F) and then the viscosity determined at 121°C (250°F). The 149°C (300°F) aging test is carried out as follows. Synthetic sea water (SSW) is prepared from distilled water to which salts are added as described hereinafter. The polymer is dissolved in the SSW to form a 0.25 weight percent solution. It is then subjected to vacuum and if necessary nitrogen purge to remove oxygen. It is then sealed under 0.69 MPa gauge (100 psig) nitrogen pressure in a glass lined container and aged 7 days at 149°C (300°F). As can be seen from Figure 6, polymer compositions depicted therein have aged viscosities of 0.7 (i.e. better than 2 times sea water) or greater, generally 1.0 (about 3 times sea water) or greater. Thus in accordance with this invention for the first time the psychological barrier has been crossed to utilizing polymers which do not impart the 10 to 20 fold increase in viscosity associated with standard materials such as acrylamide. The inventors have surprisingly discovered that the water soluble polymers described herein because of their resistance to precipitation on aging at high temperatures are effective in spite of their apparent poor performance in standard room temperature viscosity tests. In high temperature applications the only significant factor is the viscosity imparted after aging. The polymers shown in area B of Figure 6 represent compositions which are preferred because of stability even at 121°C (250°F). Those of area E are useless because of precipitation at hostile environment temperatures 77°C of (170°F). Areas D and C represent polymers stable up to at least 77°C (170°F) and 93°C (200°F) respectively. The area encompassed by area B can be increased somewhat by utilizing N,N-disubstituted acrylamide as shown in Figure 7. The area encompassed in region A is less preferred because the viscosity imparted to the sea water is so low that higher concentrations are required to give effective solutions. Such compositions are not useless, however, and can be used if desired with best results obtained using the highest molecular weight polymers obtainable. As stated hereinabove the unaged viscosity at an arbitrary test temperature of 250°F (121°C). for a solution containing 0.25 weight percent polyacrylamide unaged is about 10. For polymers as shown in Figure 6 having aged viscosities of 1 the unaged viscosity is about 1.5. Other polymers depicted as being encompassed by the useful polymers in accordance with this invention can have unaged viscosities at 250°F (121°C) of about 2 or slightly more (some specific compositions are higher than this). Thus the invention in one aspect can be viewed as utilizing a polymer in a hostile environment which polymer in an unaged test at 121°C (250°F) in a concentration of 0.25 weight percent imparts to sea water a viscosity of less than one third (i.e. a viscosity of no more than 2 or no more than 3) the viscosity imparted by the same amount of a standard unaged acrylamide polymer such as N-Hance™ 1027 by Hercules. The 2-acrylamido-2-methylpropane sulfonic acid or sulfonate salt (AMPS) has the formula (shown as sodium salt) sodium-2-acrylamido-2-methylpropane sulfonate (sodium AMPS) These are known monomers and can be produced as is known in the art. The 2-acrylamido-2-methylpropane sulfonic acid is available from Lubrizol under the designation AMPS. Not precipitating after 7 days at 300°F (149°C) is one way of defining stability which has been definitely correlated with long term stability at 121°C (250°F) for NVP/Am polymers. Particularly with the NVP containing polymers, after a modest initial drop in viscosity on aging, the viscosity on continued aging remains essentially unchanged. Because of this enhancement of stability on extended aging these NVP containing polymers are particularly suitable for extremely harsh environments as defined for instance by the area above the 20 day line or even the 5 day line or 1 day line at Figure 5. By NVP containing polymers as used in this context of extremely harsh environment stability is meant polymers having at least 20 weight percent combined NVP and Am, at least half of which is NVP. In certain applications it is believed there is an advantage to polymer compositions having at least 20 weight percent each of AMPS and NVP and 0-40 weight percent of Am. In other instances compositions having at least 10 weight percent of all three monomers (NVP, Am and AMPS) are preferred. Polymer Characterization In contrast to the copolymers of 50-99 mole percent N-vinyl-2-pyrrolidone and 1-50 mole percent acrylamide, with K values of 10 to 140, disclosed in U.S. Patent 3,500,925, the copolymers used in the process of this invention have K values of more than 140 when measured at concentrations of 1 gram/deciliter or less, and can have K values in the range from 150 to at least 250. K values have been used for years to describe the viscosity grades of commercially marketed cellulosic polymers as well as polyvinylpyrrolidones and other polymers. The use of K values has become well established and is retained as a means of expressing relative molecular weight; for example, K values for solutions of homopolymers of vinyl alkyl ethers are reported in Kirk-Othmer, Encyclopedia of Chemical Technology , Second Edition, Volume 21, pp. 419-420. The polymers used in the process of this invention can be further characterized by measuring the cloud point temperature. The polymers are preferably tested for cloud point temperature after heat aging for a period of time which produces an equilibrium cloud point temperature representative of the polymer's performance in, e.g., enhanced oil recovery in reservoirs of equivalent temperatures. The equilibrium cloud points appear to correspond to an equilibrium degree of hydrolysis, as defined elsewhere herein, generally limited to about 70-80 percent, which may partially account for the superior properties of the preferred copolymers. Polymerization The polymers used in the process of this invention can be formed using solution, emulsion, inverse emulsion (water-in-oil) or slurry polymerization processes. For example, a process for producing the polymers comprises carrying out the polymerization in a homogeneous solution process in which the polymerization medium is water containing certain dissolved mixed electrolytes, or presently most preferably, water containing appropriate dissolved salts such as found in sea water, to provide a simulated or synthetic sea water (SSW). Natural sea water and formation brines can also be used in the polymerization media and can be filtered to remove solid material if desired or necessary. Brines containing a high percentage of dissolved solids can be diluted with fresh water to provide an appropriate concentration of dissolved solids. Alternatively, salts can be added, if deemed necessary to obtain the desired salt level. In another embodiment, slurry polymerization is preferably conducted with a polymerization medium consisting essentially of an alcohol, preferably a neat tertiary alkanol which generally has from 4 to 8 carbon atoms, most preferably t-butyl alcohol, since the polymeric product is insoluble in the alcohol and can thus be conveniently separated. Polymerization Initiators The polymers used in the process of this invention can be prepared by processes using various free radical polymerization initiators known to those skilled in the art. Preferred initiators include chemical polymerization initiators, the introduction of electromagnetic or nuclear radiation to generate free radicals, and combinations of both techniques. Monomer Proportions The first and second monomer proportions for copolymers used in the process of this invention can vary widely, as previously disclosed. Generally, NVP:Am weight ratios of 10:90 to 90:10, as applied to the mixture of monomers polymerized, are used, but copolymers having NVP:Am weight ratios as low as 5:95 and as high as 99:1 can be prepared and employed for specialized applications. Generally, the minimum amount of the NVP monomer required to produce copolymers of the desired characteristics will be used. The polymers of AMPS or NVP and Am, if present, can have monomer ratios as shown in Figures 6 and 7 excluding area E. In addition any of the copolymers having a ratio of monomers as shown can also have a termonomer present in an amount up to 10 weight per cent based on the total weight of monomers as discussed hereinbefore. For enhanced oil recovery applications, the preferred copolymers comprise copolymers of N-vinyl-2-pyrrolidone (NVP) and acrylamide (Am) in which the weight ratios of NVP:Am preferably range from 30:70 to 70:30. The higher proportions of NVP are preferred for reservoirs having more "hostile" conditions, e.g., higher temperature, salinity and hardness of the formation water. For example, copolymers for use at over 127°C (260°F) should preferably contain at least about 60 weight percent NVP, while copolymers for use at about 121°C (250°F) can have about 50 weight percent NVP or more. For lower temperatures, copolymers with lower proportions of NVP can be tolerated; e.g., for temperatures of 104 to 121°C (220 to 250°F), about 40% by weight NVP or more should suffice, while for temperatures as low as 93°C (200°F), the copolymers can contain at least about 30 weight percent NVP. Copolymers having NVP:Am monomer weight ratios in the range of from 65:35 to 55:45, or about 60:40, are particularly preferred for use in high temperature EOR as these copolymers will produce the highest viscosity relative to sea water after a short equilibration time in the high temperature reservoir. For applications requiring shorter stability times, greater viscosity can be obtained from copolymers of higher acrylamide content, although these are less stable than the 60:40 compositions. While 60:40 (NVP:Am) copolymers are presently preferred for long-term high temperature applications, 50:50 weight percent copolymers have displayed exceptional thermal stability in aging studies conducted in water, and particularly in SSW, at temperatures ranging from 93 to 149°C (200 to 300°F). For example, such 50:50 copolymers, employed as 2 weight percent solutions in SSW, have given clear solutions after aging at 121°C (250°F) for more than 918 days (487 plus 431) while the solution viscosities remain about the same or somewhat higher than when first tested. Although the majority of testing has involved the 50:50 copolymers, which are presently preferred for use at temperatures of about 116 to 127°C (240-260°F), tests of aged 60:40 (NVP:Am) copolymers show that they are generally superior at temperatures above about 121°C (250°F). Additional tests of the 50:50 copolymers conducted at 149°C (300°F) in SSW have shown that the solutions may turn cloudy without loss of most viscosity after a few days aging, but that the cloudiness disappears upon slight cooling. The cloudiness typically first appears at a temperature between 127 and 138°C (260 and 280°F). Based on these observations, it appears that a preferred upper temperature limit for long-term thermal stability for the preferred 50:50 copolymers is in the range of 138 to 149°C (280-300°F). Cloud points for the 60:40 copolymers are in the range of 143 to 149°C (290-320°F), suggesting 160°C (320°F) as the upper preferred use temperature for these compositions. For certain applications, e.g., drilling fluids, some of the preferred aged or unaged polymers can be subjected to temperatures as high as at least 166°C (300°F) for periods of a few days, or temperatures as high as 204°C (400°F) for periods of a few hours. While preaged copolymers of approximately 60:40 NVP/Am weight ratios are presently preferred for use in high temperature enhanced oil recovery, the copolymers used in the process of this invention can be "designed" and prepared in proportions which result in properties which are optimal for various other applications. Copolymers useful in drilling wells, including use as additives for drilling, workover and completion fluids, can have any desired weight ratio, but generally such weight ratios will be from 30 to 60 weight percent NVP with the balance Am. The exact proportions can be chosen to produce properties comprising high viscosity and resistance to high temperatures, salinity and hardness ions which are optimal for the environment in which the drilling, workover or completion fluid is to be used. As mentioned earlier, the requirements for drilling, workover and completion fluids differ significantly; e.g., drilling fluids are normally thickened with clay, while workover fluids are preferably clay-free. In general, when conditions are less severe, e.g., the fluids are to be exposed to high temperatures, salinity and/or hardness ion concentrations for shorter periods of time, a lower proportion of NVP can be used in the copolymer, thus reducing costs and increasing the viscosity attainable per unit of copolymer. Conversely, for very hostile environments and extended exposures, as in, e.g., the polymer flooding of a North Sea reservoir, a higher proportion of NVP will generally be required for effectiveness, regardless of the relative cost. The terpolymers of this invention can also be tailored for certain applications by adjusting the proportions and types of monomers charged. For simplicity, the term "termonomer" is used herein to mean a monomer or monomers other than the principal monomers of N-vinyl lactam and unsaturated amide, although it is recognized that technically N-vinyl lactam and unsaturated amide are also termonomers. A minor portion of a termonomer, for example a hydrophobic compound, is included to alter characteristics of the polymer such as its tendency to adsorb on or absorb in a rock formation. (Adsorption refers to the attachment of polymer molecules to the rock surface by physical or chemical means, while absorption refers to such larger scale phenomena as imbibing of the polymer solution within the pore structure of the formation rock.) Other polymer characteristics which can be altered by incorporating such a termonomer in the polymer include solubility in water, brine and oils, as well as crosslinking ability. The terpolymers of this invention have been found to be as stable as the copolymers under conditions of high temperature and/or salinity and/or hardness, as shown in Examples XV through XXI, and thus provide stable polymers with various useful properties. The NVP/Am copolymers used in the process of the invention can contain a termonomer in a quantity of not more than 10 weight percent of the total monomers charged. The major portion of the terpolymer consists essentially of the first monomer and second monomer as disclosed for the copolymers, with their relative proportions or weight ratios variable over the same range as in the copolymers to adapt the polymers for various applications. Generally, the terpolymers contain in the range of from 10 to 90 weight percent N-vinyl-2-pyrrolidone (NVP) as a first monomer, with a second monomer of acrylamide (Am) in the range of from 90 to 10 weight percent and the termonomer as disclosed above present as an amount in the range of from 0.1 to 10 weight percent, preferably from 1.0 to 10 weight percent. Preferably, the terpolymers contain 25 to 75 weight percent NVP, 75 to 25 weight percent Am, and 2 to 8 weight percent termonomer. A termonomer content of 3 to 5 weight percent is presently most preferred. For enhanced oil recovery applications at reservoir temperatures of above about 121°C (250°F), it is presently preferred that the proportions of said first monomer and said second monomer be approximately or nearly equal, i.e., that the weight ratio of the first and second monomers be in the range of 45:55 to 65:35. In addition to varying the monomer proportions, the molecular weight of all the polymers used can be varied according to the amount of initiator used or by initiation by gamma irradiation, for example. Thus, a relatively high molecular weight may be suitable for EOR, while for drilling fluids, a lower molecular weight can be used to limit the degree of flocculation of suspended clay. Generally, in carrying out the various processes for recovery of natural resources according to this invention, the polymer is at least partially dissolved in an aqueous fluid, and can be introduced into subterranean formations with a fluid comprising at least one composition selected from the group consisting of bases, polymeric viscosifiers, crosslinking agents, surfactants and cosurfactants, and combinations of any two or more of said compositions. In the various processes, said polymer can be cross-linked with various crosslinking agents. The aqueous fluid to which the polymer is exposed can have a significant salinity and/or hardness, e.g. a salinity of at least about 10 grams per kilogram of solution with a fraction of divalent hardness cations to total cations of at least about 1 weight percent, or particularly, a fraction of divalent hardness ions of at least about 5 weight percent. The polymer can be exposed to various aqueous fluids in the preparation of the polymer and polymer solutions for use in the process, in the introduction into the well bore and/or formation, or in contact with subterranean formation water. The polymers used will hydrolyze, and when heated in solution to a temperature such as at least 66°C (150°F) for a suitable period of time, will reach an equilibrium degree of hydrolysis and an equilibrium cloud point temperature. Generally, an equilibrium degree of hydrolysis for a given temperature (thus indicating long term stability at that temperature) will be obtained by heating at a higher temperature for a short time. For instance, heating at 149°C (300°F) for 7 days gives the equilibrium degree of hydrolysis for 121°C (250°F). Heating at about 121°C (250°F) for at least about 7 days gives the equilibrium degree of hydrolysis and equilibrium cloud point temperature for about 82°C (180°F). Hydrolysis of the polymers to the desired degree can also be obtained by contacting them with a base or acid, optionally while heating, as explained more fully below. The polymer can be at least partially dissolved in a liquid which is circulated in a well bore used in certain processes of the invention, such as for example when said polymer is used as a drilling fluid, a workover fluid, or a completion fluid. In the process of the invention the NVP/Am polymers can be used in conjunction with various other materials, such as bases, surfactants, cosurfactants, polymeric viscosifiers, crosslinking agents and the like, used singly or in combination. For example, the bases can be water-soluble bases selected from the group consisting of alkali and alkaline earth metal hydroxides, ammonium hydroxide, alkali metal carbonates and chemical buffer salts which dissolve with hydrolysis to yield alkaline fluids, such as sodium phosphate, sodium borates and sodium silicates, or combinations of at least two of said bases. Surfactants can be selected from anionic, cationic or nonionic surfactants, suitable anionic surfactants include petroleum sulfonates, alkali metal carboxylates such as sodium oleate, carboxyalkylated or sulfated polyethoxylated alkyl phenols, carboxylated or sulfonated polyethoxylated alkyl phenols, carboxylated, sulfated or sulfonated polyethoxylated alcohols or carboxylic acids, and carboxylated, sulfated or sulfonated polyethoxylated thiols. Suitable cationic surfactants include long chain fatty amines and quaternary ammonium salts of fatty amines. Suitable nonionic surfactants include polyalkoxylated compounds prepared from substrates of long chain alcohols, alkyl phenols, carboxylic acids, amines and thiols. These surfactants can be used in combinations or mixtures. Suitable cosurfactants can be polar organic compounds selected from the group consisting of saturated and unsaturated alcohols having from 3 to about 10 carbon atoms, phenols, amines, esters, mercaptans, aldehydes, ketones, amides, sulfoxides, organic nitro compounds, organic nitriles, sulfones, urea, and polyethoxylated alcohols. These cosurfactants can be used in combinations or mixtures. The polymers, copolymers and terpolymers discussed herein are of applicability in the mobility buffer following a micellar or microemulsion slug of the type disclosed in Hedges et al U.S. 4,265,308. In this embodiment a microemulsion slug is formed in a hostile environment followed by a mobility buffer comprising water and 0.05 to 1 preferably 0.1-.25 wt. percent polymer, followed by drive water. For instance a surfactant system, generally comprising a petroleum sulfonate surfactant and a C₃ - C₆, preferably C₄ - C₅ alcohol cosurfactant, is injected into a reservoir to form a microemulsion in situ. Thereafter the mobility buffer is injected followed by injection of a conventional drive fluid comprising water, generally saline water. Oil is recovered at a production well spaced apart from the injection well as the drive fluid pushes the mobility buffer slug which pushes the microemulsion which sweeps the oil out of the pores in the formation and to the production well. Polymeric viscosifiers can be, for example, biopolysaccharides, cellulose ethers, acrylamide-derived polymers, or mixtures thereof. Crosslinking agents can be selected from various suitable crosslinking agents. Examples include various aldehydes and trivalent metal cations such as Al⁺³, Cr⁺³, and Fe⁺³. Also suitable are multifunctional amines such as diamines. For example, aluminum citrate can be used admixed with the polymer or in slugs alternating with polymer slugs. Soluble compounds of Cr⁺³ or Fe⁺³ can be used, or oxidizable compounds of divalent iron such as FeCl₂ can be used in conjunction with a gaseous oxidant such as air or oxygen. Phenols or phenolic materials such as lignites can be used. Formaldehyde, acetaldehyde, chromium⁺³ and aluminum⁺³ are particularly useful in unsaturated amide and/or N-vinyl lactam polymers. For crosslinking with trivalent metals, some acid must be present. This can come from acid produced through preparation and/or aging because of hydrolysis or acid such as acrylic acid can be added during the preparation. More specifically with regard to bivalent metal/oxygen gelling systems for permeability correction, in a water permeability correction process involving the in situ polyvalent metal crosslinking of polymeric viscosifiers such as polyacrylamide triggered by the sequential injection of (1) an oxidizable bivalent metal such as in a bivalent iron compound (e.g. FeCl₂) and (2) a gaseous oxidant such as air or oxygen, viscosifiers prepared by the reaction of N-vinyl-2-pyrrolidone with one or more ethylenically unsaturated comonomers such as acrylamide, methacrylamide, vinyl acetate, acrylic acid, acrylate esters and the like are used. This system is of particular value under hostile environment conditions. This crosslinking procedure is more specifically described in U.S. 3,658,129, the disclosure of which is hereby incorporated by reference. Also, redox systems such as sodium dichromate and sodium bisulfite as disclosed in U.S. 3,749,172, can be used. Any suitable amount of the polymers can be used in the embodiments of the invention concerning the recovery and processing of natural resources. For example, in the introduction of the polymers into a subterranean well bore and a subterranean formation in processes for enhanced oil recovery, a small but effective amount of polymer should be used to produce the desired viscosity or other properties in the injection fluid. Based upon the properties of the formation and the intended nature and duration of the process, type and amount of the polymer should be selected to achieve the desired effects over the appropriate time period. As a general guide, the amount of polymer used will be in the range of from 500 ppm to 10,000 ppm, preferably 1,000 ppm to 3,000 ppm, based on the weight of the injection fluid. Generally the goal will be to select an economical amount and type of polymer to produce the desired effect for the required time. Those skilled in the art can determine the amount of polymer to be used by suitable experiments carried out in light of this disclosure. In some cases the process of this invention can present particular advantages. For example, because of like charge interchain repulsion (including the polymer-surfactant complex) when the polymers are in an electrolyte solution with a surfactant, these systems should demonstrate increased saline resistance, and thus increased viscosity stability. The process of this invention can be used to improve drilling a borehole in a subterranean formation, by circulating in the borehole a drilling fluid comprising the polymer, so that the high temperature water loss of the drilling fluid is reduced and improved viscosity and/or gel strength are obtained. The drilling fluids can comprise fresh or salt water, clays, weighting agents and other drilling fluid ingredients. The process of the invention is particularly suitable for drilling in formations having high temperatures, salinity content and content of hardness ions, since the drilling fluids tend to retain their viscosity well even when aged at elevated temperatures in saline and/or hard water. In addition when using a drilling fluid additive, the process of this invention can be effectively used in various workover and completion methods, e.g., for reducing the loss of a fluid pumped into a subterranean borehole, by maintaining a suitable viscosity, and improving the fluid's ability to suspend weighting agents. When introduced into a well bore in processes for the drilling, completion or workover of wells, the polymers can be used in small amounts effective to achieve the effects desired, such as reduction of high temperature water loss or suspension of weighting agents. As a general guide, the amount of polymer used will be in the range from 0.28 to 14.3, preferably 1.4 to 5.7 g/ℓ (0.10 to 5, preferably 0.5 to 2 pounds per barrel of fluid). Those skilled in the art can determine the amount of polymer to be used by suitable experiments in light of this disclosure. The polymers are useful in such applications at temperatures up to 204°C (400°F). In one embodiment, the polymers can be added to a workover/completion fluid to provide a fluid which is substantially clay free, with a pH in the range from 7 to 10. Cloud Point Measurements When an aqueous solution of a water-soluble polymer such as an acrylamide-derived polymer is heated, it turns cloudy at higher temperature. This cloudiness disappears upon cooling and reappears as a result of additional heating. The temperature at which such cloudiness first appears is a property related to the solubility of the polymer, and is known as the cloud point. Cloud point corresponds to the lower critical solution temperature described by Billmeyer in his Textbook of Polymer Science, Second Edition (Wiley-Interscience, New York, 1971) at pages 39-43. The lower critical solution temperature is the higher temperature at which a solvent, such as water, in a given single-phase polymer-solvent system, such as NVP-Am in a synthetic sea water, is no longer a good solvent. At this temperature, the single phase system undergoes phase separation, as shown by FIGURE 2-8 in Billmeyer. Such phase separation is often marked by clouding, hazing or precipitation of the polymer. Such phase separation, and thus the lower critical solution temperature or cloud point, can be observed visually or measured by various apparatus, including turbidimetry. Since chemical modification of the polymer or solvent does not necessarily occur at or near the lower critical solution temperature, redissolution of the cloud, suspension or precipitate is noted when the temperature decreases below the lower critical solution temperature. Apparatus has been developed in connection with the research on this invention to measure cloud points at high temperatures (up to 163°C (325°F) or even 204°C (400°F)). Unless otherwise noted, this apparatus and the method described were used to determine the cloud points herein. To determine the cloud point of a given polymer with this apparatus, a solution of the polymer comprising 0.25 or 0.5 gram (as indicated) per deciliter of polymer in SSW is produced and a 35 ml aliquot of this solution is placed in a 45 ml ampule and torch-sealed under vacuum. The ampule is then placed in a protective chamber immersed in a silicone oil bath containing Dow Corning 200™ Fluid. A Brinkman Model PC-801™ probe colorimeter is used to supply a source of light and a detector. The light from the colorimeter is passed through a 30 inch Brinkman fiber optic light guide (No. 2023602-F)™ and then directed through the solution. The transmitted light is passed by another identical fiber optic light guide to the detector. The sample is heated from a temperature where the polymer solution is clear to a temperature where cloudiness exists, and is then allowed to cool. For example, to measure cloud points in the range of 121 to 135°C (250-275°F), the silicone oil bath containing the ampule is heated from 93 to 138°C (200 to 280°F) and cooled back to 93°C (200°F) in approximately one (1) hour with the heating cycle taking about 30 minutes. Use of a pressure cell allows going to 204°C (400°F). To detect the onset of cloudiness, the absorbance of the polymer solution is measured and recorded (on a strip chart recorder) as a function of temperature for the heating-cooling cycle. (Absorbance is outputted by passing the transmittance signal through a logarithmic amplifier and on to the recorder.) The average of the temperatures at which the first trace of cloudiness appears and the last trace of cloudiness disappears employing the above described apparatus and method is the numerical average cloud point temperature, hereinafter "cloud point," as that term is used in the specification and claims unless otherwise indicated. This measurement appears to be quite reproducible to within ±3% with the apparatus presently in use. It has been noted that the cloud points of the copolymer solutions can be correlated with desirable properties comprising the resistance of the copolymers to high temperatures. Generally speaking, the higher the cloud point of a freshly-prepared polymer, the higher the temperature (which can be as much as about 28°C (50°F) or more but generally no more than 2.8°C (10°F) above the cloud point) which the copolymer can be expected to withstand without suffering a significant loss in its capacity to impart viscosity to the test solution. Furthermore, tests to determine cloud point after aging can be used to indicate the prospects of the copolymers withstanding further aging under such conditions, or under less severe conditions. The NVP:Am copolymers and terpolymers used in the process of this invention hydrolyze. As is known, hydrolysis of an amide alters the amide functionality to an acid (or its salts). In the case of acrylamide, acrylic acid or its salts are formed. In the case of polyacrylamide or its copolymers, including NVP-Am, the polymer is altered to contain monomer units of carboxylic acids or their salts, thus introducing ionic character to the polymer. The degree of hydrolysis has been found to increase to a maximum equilibrium value of about 70 to 80 percent at 121°C (250°F) based on the acrylamide content. It has been noted that the cloud point temperature also changes over the same time frame and equilibrates. The inference is that the cloud point temperature reflects the basic polymer nature, and that the stability of the equilibrium cloud point temperature (corresponding to the stability of the degree of hydrolysis of the copolymer) probably indicates a constant polymer makeup. The utility of cloud point measurements as predictors of the performance and/or stability of polymer compositions in high temperature environments is disclosed in U.S. Patent 4,016,932, which states that in surfactant systems for oil recovery comprising at least one anionic and at least one nonionic surfactant, superior results are obtained when the nonionic surfactant is chosen to have a cloud point slightly above the formation temperature. Similarly, measurement of the cloud points of the copolymers suitable for use in the processes of this invention, before and/or after aging at elevated temperatures, facilitates the selection of polymers which will provide superior performance and stability for the various applications disclosed herein. For the best prediction of polymer performance, it is preferred that the cloud points be determined in aqueous solutions similar to the proposed environment for employement, e.g. in salinity and hardness, and at standardized concentrations of the polymer. For use in enhanced oil recovery in hot saline formations, for example, polymers having cloud points in brine of at least as high as the formation temperature after short-term aging at elevated temperature are preferred. Since long-term viscosity stability at high temperatures is required in enhanced oil recovery, and since polymers having relatively high cloud points after aging correlate well with polymers having such stability, polymers with relatively high cloud points are preferred for use in enhanced oil recovery processes. Conversely, polymers used in drilling fluids and the like are subjected to high formation and/or well bore temperatures, salinity and hardness ions for shorter periods of time. Thus, polymers with cloud points relatively lower with regard to formation and/or well bore temperature than those required in polymers selected for, e.g., enhanced oil recovery, can be utilized in drilling fluids, etc. For example, a polymer with a cloud point somewhat lower than the maximum formation and/or well bore temperature may perform adequately and retain the desired properties such as viscosity for a period of use limited to weeks, days or even hours. This is particularly important when drilling or servicing deep and/or hot wells, such as geothermal wells. Based on the relatively stable properties of the polymers suitable for use in the processes of the invention after short-term heat aging, for applications where maximum stability in hot, saline environments is desired, the polymers can be pre-aged or hydrolyzed before use. That is, the polymers are hydrolyzed in solution by heat aging at a suitable temperature until an equilibrium value of hydrolysis is attained. The aging temperature must be less than the decomposition temperature of the polymer. The polymers can be aged in any available aqueous medium, but media similar to the environments in which the polymers are to be employed are presently believed to produce optimum results. Since the aging time and temperature are interdependent, to fully stabilize polymer properties such as viscosity, the polymers must be aged for long enough at the temperature selected to produce an equilibrium degree of hydrolysis. The polymers can also be at least partially hydrolyzed by treatment in solution with a base, an acid, a polyacid such as polyacrylic acid, a polyelectrolyte such as polyvinylpyrrolidone or an electrolyte such as an alkali or alkaline earth metal salt. The degree of hydrolysis can be tested directly by the Dow Color Test, as described in Example 1 herein. The minimum temperature suitable for this pre-aging is a temperature high enough to produce a hydrolysis rate which allows pre-aging to be completed in a reasonable time. As seen in FIGURE 1, temperatures of at least 66°C (150°F), preferably in the range of 121 to 204°C (250°F to 300°F) should generally produce suitable hydrolysis rates for the used polymers. Temperatures higher than 149°C (300°F) can be used, provided suitable equipment is available and the decomposition temperature of the polymer is not exceeded. In the production and pre-aging of a given polymer, the relationship between the times and temperatures appropriate for pre-aging can be readily determined. When a temperature of at least 121°C (250°F) is used, the polymers are preferably aged for at least about 7 days. The invention is further illustrated by the following examples. Unless otherwise noted, all percentages and/or parts are by weight. EXAMPLE 1 Hydrolysis of NVP/Am Copolymers The equilibrium cloud points and resultant properties of the aged copolymers are believed to relate to the degree of hydrolysis of the copolymers. Selected samples of the copolymers were tested for degree of hydrolysis by the Dow color test, described more fully by Foshee, et al, in Paper SPE6202 (New Orleans, 1976). To determine the percent hydrolysis, the concentration of amide surviving the hydrolysis is determined by an iodometric method, converting the amide groups to N-bromoamide, followed by a reaction with potassium iodide to form iodine which is then complexed with starch. The amount of this iodine-starch complex is then spectrophotometrically measured. The degree of hydrolysis can also be determined by the titration of ammonium ions produced as a result of the hydrolysis with sodium hydroxide, but the Dow color test has been found to be more convenient and sufficiently accurate. In FIGURE 1, the effect of aging in SSW on the degree of hydrolysis of a 0.5 weight percent solution of a 50:50 NVP-Am copolymer prepared in SSW is plotted for three different aging temperatures. It is apparent that the hydrolysis process is relatively slow when the polymer is aged at 93°C (200°F) but exceeds the 50 percent point after about 15 days at 121°C (250°F). When the copolymer is aged at 149°C (300°F), 40 percent hydrolysis is attained almost immediately, and 60 percent is exceeded within ten days. However, as seen in FIGURE 2 and as described earlier herein, these copolymers tend to attain an equilibrium degree of hydrolysis eventually, no matter what the aging temperature. As seen in FIGURE 2, samples of a 0.5 weight percent 50:50 copolymer of NVP-Am prepared in SSW and aged in SSW at the temperatures of 121, 138 and 149°C (250, 280 and 300°F) all attain a percent hydrolysis in the range from 65 to 75 percent after about 15 days aging. The general experimental procedure used to prepare the polymers of the following examples involved the charging of monomers and water (either distilled water or saline water) to crown top bottles along with suitable initiators. The reaction mixtures were degassed with an inert gas for approximately 20 minutes before capping and allowing polymerization to take place at a specified temperature depending on the chemical initiator used. For radiation induced polymerizations, no chemical initiator was added and the reaction mixture in the crown top bottles was irradiated with suitable radiation dosages. At the end of the reaction period, the entire reaction mass was usually in the form of a gel. Characterization of reaction products was carried out by addition of sufficient amounts of synthetic North Sea water to the gel to prepare 0.1 weight percent and 0.25 weight percent polymer solutions for viscosity measurements. Relative viscosities of the 0.1 weight percent solutions at 25°C were determined in a capillary viscometer. The unaged viscosities of the 0.25 weight percent polymer solutions were determined by high pressure capillary viscometry. In order to measure the aged viscosity of a polymer solution, the solution was aged in a sealed bomb at 149°C at (300°F) for 7 days as described hereinbefore. The aged viscosity of the sample was then determined by high pressure capillary viscometry. The formation of precipitate in the aging test indicated that the polymer lacked sufficient thermal stability in the hard salinity test medium to merit any further consideration as a mobility control agent in hostile environments (i.e., temperature > 77°C (170°F), hardness cations > 500 ppm). Since the viscosity of the synthetic North Sea water at 121°C (250°F) was found to be on the order of 2.8 · 10⁻⁴ Pas (0.28 centipoise) this value was used to indicate the relative effectiveness of the polymer solutions to mobilize crude oil over that which would be expected using sea water as a flooding medium. The examples presented hereinbelow are representative of the instant teaching. Unless otherwise noted, the compositions were prepared and tested in accordance with the above general experimental procedure. Reaction times were usually on the order of 24 hours and reaction mixtures were usually neither stirred nor tumbled during the polymerizations. The total solids level generally was in the range of 5% to 50% with most of the preparations being carried out in the range of 20% to 35% total solids. EXAMPLE 2 NaAMPS Polymers For Hostile Environments This example presents in summary form representative polymer compositions which are potentially useful as mobility control agents under hostile environment conditions. These samples are characterized by the presence of sodium 2-acrylamido-2-methylpropanesulfonate (NaAMPS) units. Solutions of these polymers in synthetic North Sea water (2500 ppm polymer) at 121°C (250°F) exhibited unaged viscosities in the range of 1.5·10⁻³ to 7.05·10⁻³ Pas (1.50 to 7.05 centipoise). After thermal aging of these solutions in synthetic North Sea water at 204°C (300°F) for 7 days, the aged viscosities of these solutions varied in the range of 1.28·10⁻³ to 4.59·10⁻³ Pas (1.28 to 4.59 centipoise). The viscosity of sea water at 121°C (250°F) is about 2.8·10⁻⁴ (0.28 centipoise). Hostile Environment Polymers Containing Sodium 2-Acrylamido-2-Methylpropanesulfonate (NaAMPS) Units Sample No. Wt.% NaAMPS Wt.% NVP Wt.% Am Wt.% DMAm Inherent Viscosity (dL/g) Viscosity, Pas·10³ (cP) 121°C (250°F) (2500ppm) Unaged Aged VR 1 70 0 0 30 8.90 3.80 2.50 8.9 2 55 30 15 0 9.01 2.19 1.85 6.6 3 55 30 15 0 8.38 2.08 1.40 5.0 4 70 0 0 30 7.85 2.07 1.37 4.9 5 65 35 0 0 6.28 1.50 1.35 4.8 6 25 50 25 0 8.19 1.56 1.28 4.6 Referring to samples 1 and 4, it is apparent that the 30/70 DMAm/NaAMPS copolymer (Sample 1) made with refined grade AMPS material exhibited a higher aged viscosity than did the copolymer prepared from commercial AMPS material (Sample 4). The same conclusion applies to the three component polymer samples, numbers 2 (from refined grade AMPS) and 3 containing 30 weight percent NVP, 15 weight percent acrylamide and 55 weight percent NaAMPS. Sample 6 (NVP/Am/NaAMPS polymer 50/25/25) is another example of a polymer system which exhibited a significant aged viscosity value. In each three component polymer (i.e., samples 2, 3 and 6), the relative weight percent ratio of NVP and Am was 2:1. In the course of this work, the weight ratio of NVP to Am in three component polymer compositions is preferably not less than 1:1. Referring to sample 5, it is evident that copolymers of NVP and NaAMPS are useful in hostile environments for enhanced oil recovery: the aged viscosity at 121°C (250°F) being 4.8 times the viscosity of sea water at 121°C (250°F). Attention is called to the fact that the aged viscosities of samples 1-6 in Table 1 were 4.6 to 16.4 times the viscosity of sea water at 250°F. Polymerfloods with such polymeric viscosifiers under hostile environment conditions would be expected to be significantly more effective in mobilizing crude oil than waterflooding with sea water. EXAMPLE 3 Poly(N-Vinyl-2-Pyrrolidone-co-Sodium-2-acrylamido-2-Methylpropanesulfonate) This example describes the properties of NVP/NaAMPS copolymers containing, respectively, 25/75; 33/67 and 35/65 weight ratios of the respective comonomers. VAZO® 33 was used as the initiator at a level of 0.10 phm (parts per hundred parts of monomer) in the first two runs and in the 35/65 run the initiator was 0.10 phm t-butyl hyponitrite. For the 25/75 copolymer, a 45 g portion of a 50 weight percent solution of NaAMPS (prepared from commercial grade 2-acrylamido-2-methylpropanesulfonic acid), 97.5 g distilled water, 3.0 g NVP and 4.5 g of a stock solution of initiator prepared by dissolving 0.267 g of VAZO® 33 in 40 g NVP was charged to a 10 ounce crown top bottle. After degassing the mixture with argon for 20 minutes, the bottle was capped and stored for 24 hours at ambient temperature. The reaction charge was 20% total solids. The 33/67 and 35/65 copolymers were similarly prepared. The gelled reaction masses were individually mixed with sufficient synthetic North Sea water to give 0.1 weight percent and 0.25 weight percent solutions for viscosity measurements. The results are shown in Table 2. Aging Results on NVP/NaAMPS Copolymers Aged In Synthetic North Sea Water Wt/Wt NVP/NaAMPS Inherent Viscosity (dL/g) Viscosity, Pas·10³ (cP), 121°C (250°F) (2500 ppm) Unaged Aged 25/75 6.93 1.80 1.07 33/67 6.31 1.22 1.23 35/65 6.28 1.50 1.35 Referring to the results in Table 2, it is evident that the aged viscosities of the copolymer solutions at 121°C (250°F) were several times greater than the viscosity of sea water, 2.8·10⁻⁴ Pas (0.28 cP) at 121°C (250°F). These copolymers, therefore, are potential candidates for polymerfloods in hostile environments. EXAMPLE 4 N-Vinyl-2-Pyrrolidone/Acrylamide/Sodium 2-Acrylamido-2-Methylpropanesulfonate Terpolymers This sample describes the properties of polymers of NVP, Am and NaAMPS using VAZO® 33 as the initiator (0.10 phm). Appropriate quantities of monomers were used to prepare NVP/Am/NaAMPS polymers of the following compositions: 33/11/56; 25/10/65; 30/15/55; and 25/15/60. The gelled reaction masses were individually mixed with sufficient synthetic sea water to prepare 0.1 weight percent and 0.25 weight percent solutions for viscosity measurements. The results are summarized in Table 3. Aging Results on NVP/Am/NaAMPS Polymers Aged in Synthetic North Sea Water Wt/Wt/Wt NVP/Am/NaAMPS Inherent Viscosity(dL/g) Viscosity, Pas·10³ (cP), 121°C (250°F) (2500 ppm) Unaged Aged 33/11/56 7.02 1.37 1.08 25/10/65 7.98 1.65 1.20 30/15/55 8.38 2.19 1.85 25/15/60 7.45 1.46 1.05 Referring to the results in Table 3, it is apparent that the NVP/Am/NaAMPS polymers are candidates for mobility control agents in hostile environments because the aged viscosities of the three component polymer solutions of 3.5 to 6.5 times be viscosity of sea water at 121°C (250°F) indicates excellent stability. The weight ratio of NVP to Am in these hostile environment terpolymers varied over the range of 1.66:1 to 3:1 in these 121°C (250°F) tests. At temperatures of 121°C (250°F) and above a ratio of at least 1:1 NVP:Am is preferred. A lower ratio, for instance as low as 0.11:1 can be used in lower temperature applications such as at 77°C (170°F). EXAMPLE 5 This example describes the properties of copolymers and three component polymers of NaAMPS as well as NVP/Am copolymers prepared with tertiary butyl hyponitrite as the chemical initiator. These preparations were carried out in essentially the same manner as the runs using VAZO® 33 and the inherent viscosities of the reaction products were of the same order of magnitude as observed in the VAZO® 33 runs. The aged viscosities of several VP/Am copolymers are shown in Table 4. The results on the 60/40 NVP/Am copolymers in Table 4 indicate that initiation with tertiary butyl hyponitrite gave copolymers which did not precipitate on aging and exhibited aged solution viscosities at 121°C (250°F) which were at least several times the viscosity of sea water at 121°C (250°F). By contrast, a 60/40 wt/wt blend of PVP/PAm homopolymers failed the thermal aging test as evidenced by precipitate formation. Referring to the NaAMPS derived polymers in Table 4, it is evident that the polymers exhibited inherent viscosities which are similar in magnitude to those polymers prepared hereinabove by VAZO® 33 initiation. EXAMPLE 6 Poly(N-Vinyl-2-Pyrrolidone-co-Sodium-2-Acrylamido-2-Methylpropanesulfonate) This example describes the properties of polymers obtained by copolymerization of NaAMPS and NVP initiated by cobalt 60 irradiation. The NaAMPS monomer was prepared by the neutralization of commercial grade 2-acrylamido-2-methylpropanesulfonic acid. A 354 g portion of a 50 weight percent aqueous solution of NaAMPS, 220 g of distilled water and 87 g N-vinyl-2-pyrrolidone were placed in a 728 g (26 ounce) crown top bottle. After degassing the mixture for 20 minutes with argon, the bottle was capped. The reactor charge contained 40 weight % total solids. Polymerization was initiated by using a dose rate of 100 Krad/hour for 0.4 hour (dose of 40 Krad). The viscous reaction mass was dissolved in sufficient synthetic North Sea water to give a 0.25 weight percent solution of copolymer for viscosity measurements. The inherent viscosity of the copolymer solution was 6.05 dL/g at 25°C. The unaged viscosity was 1.3·10⁻³ Pas (1.30 centipoise) and the aged viscosity was 1.2·10⁻³ Pas (1.2 centipoise). This aged viscosity is about 4.3 times the viscosity of sea water at 121°C (250°F). EXAMPLE 7 This example describes the properties of NVP/Am copolymers [poly(N-vinyl-2-pyrrolidone-co-acrylamide] prepared in synthetic sea water with radiation initiation. The samples of 50/50 wt/wt copolymers were prepared at 20% total solids and the samples of 60/40 wt/wt copolymers were prepared at 30% total solids. The reaction mixtures were charged to crown top bottles, degassed with argon and capped. The bottles were exposed to gamma radiation from a Co⁶⁰ source at the intensity and dosage noted in Table 5 below. Polymerization was signaled by warming of the reaction mixture (reaction exotherm) and the thickening of the reaction mass to a gel. The gelled reaction masses were individually dissolved in synthetic sea water to give 1000 ppm copolymer solutions for determining relative and inherent viscosities at 25°C. Additional copolymer solutions were prepared at 2500 ppm for thermal aging study. The relative and inherent viscosities were determined from measurements made in a capillary viscometer. The unaged viscosities of the 2500 ppm copolymer solutions were determined by high pressure capillary viscometry at 121°C (250°F). The copolymer solutions (2500 ppm) were aged for seven days at 149°C (300°F) before determining aged viscosities by high pressure capillary viscometry at 121°C (250°F). Results are summarized in Table 5. Aging Results on VP/Am (Radiation Initiated) Copolymers Aged in Synthetic North Sea Water Wt/Wt NVP/Am % Total Solids K-Value Irradiation Inherent Viscosity (dL/g) Viscosity, Pas·10³ (cP), 121°C (250°F) (2500 ppm) Intensity Krad/hr Dose Krad Unaged Aged 50/50 20 204 24 14 7.46 1.93 0.80 50/50 20 213 100 40 8.13 1.86 0.93 60/40 30 200 50 38 7.17 1.32 0.89 60/40 30 199 50 46 7.14 1.48 0.96 60/40 30 190 80 40 6.48 1.35 0.96 60/40 30 204 80 48 7.44 1.29 0.84 SNSW - - - - - - 0.28 Referring to the aged viscosities in the above table, it is evident that the copolymer solution values were 3 to 3.5 times the viscosity of synthetic sea water at 121°C (250°F). The slightly higher inherent viscosities of the 50/50 copolymers is attributable to the higher percentage of acrylamide units compared to the 60/40 copolymer. The whole range of radiation dosages appear to result in copolymer samples giving approximately the same aged viscosities in the thermal aging tests. EXAMPLE 8 In this example the properties of a series of 60/40 wt/wt N-vinyl-2-pyrrolidone/acrylamide copolymers obtained by low temperature initiation at different solids levels is described. The copolymerization was initiated by VAZO® 33, [2,2'-azobis(2,4-dimethyl-4-methoxyvaleronitirle)] in the range of 0.05 to 0.10 phm. The polymer samples were characterized by determining relative and inherent viscosities of polymer solutions (1000 ppm) in synthetic sea water at 25°C. The unaged viscosities of the polymer (2500 ppm) in synthetic sea water were determined by high pressure capillary viscometer at 121°C (250°F). Polymer solutions (2500 ppm) were aged for 7 days at 149°C (300°F) before determining aged viscosities by high pressure capillary viscometry at 121°C (250°F). Results are summarized in the table below. Aging Results on 60/40 Wt/Wt Copolymers of N-Vinyl-2-Pyrrolidone and Acrylamide in Synthetic North Sea Water (0.05 phm Initiator Level) % Total Solids Relative Viscosity Inherent Viscosity (dL/g) Viscosity, Pas·10³ (cP), 121°C (250°F) (2500 ppm) Unaged Aged 5.0 2.10 7.42 1.57 0.84 9.1 1.99 6.87 0.98 0.87 15.0 1.99 6.87 1.09 0.83 20.0 2.07 7.29 1.17 0.91 25.0 2.05 7.16 1.10 0.85 30.0 1.92 6.55 0.95 0.72 SNSW 1.00 - - 0.28 Referring to the results in the above table, it can be seen that the NVP/Am copolymers performed well in the thermal aging test exhibiting aged viscosities on the order of 2.5 to 3.5 times the viscosity of synthetic sea water at 121°C (250°F). EXAMPLE 9 N-Vinyl-2-Pyrrolidone/N,N-Dimethylacrylamide/Sodium 2-Acrylamido-2-Methylpropanesulfonate Polymers This example describes the properties of polymers obtained NaAMPS, NVP and DMAm using VAZO® 33 as the initiator (0.10 phm). Appropriate quantities of monomers were used to prepare NaAMPS/NVP/DMAm polymers of the following compositions: 25/10/65 and 25/15/60. Reaction time was 24 hours at ambient temperature and the total solids level was 20%. The gelled reaction masses were individually mixed with sufficient synthetic North Sea water to prepare 0.1 weight percent and 0.25 weight percent solutions for viscosity measurements. The results are summarized in Table 7. Aging Results on NaAMPS/NVP/DMAm Polymers Aged in Synthetic North Sea Water Wt/Wt/Wt NVP/DMAm/NaAMPS Inherent Viscosity (dL/g) Viscosity, Pas·10³ (cP) 121°C (250°F) (2500 ppm) Unaged Aged 25/10/65 6.70 1.24 1.05 25/15/60 6.88 1.26 0.95 Referring to the viscosity results in Table 7, it is evident that the polymers would be useful as mobility buffers in hostile environments because the aged viscosities are about 3.3 to 3.8 times the viscosity of sea water at 121°C (250°F). EXAMPLE 10 NVP/DMAm (50/50) and (40/60) Polymers and NVP/Am /DMAm Polymers This example describes testing of N-vinyl-2-pyrrolidone/N,N-dimethylacrylamide copolymers and N-vinyl-2-pyrrolidone/acrylamide/N,N-dimethylacrylamide terpolymers. The polymers were prepared in synthetic North Sea water, respectively, at 9.1% and 20% total solids, with 0.10 phm VAZO® 33 initiator. Two polymers : 47.5/47.5/5 NVP/Am/DMAm and 45/45/10 NVP/Am/DMAm were similarly prepared and tested. The gelled reaction masses were individually mixed with sufficient synthetic sea water to prepare 0.1 weight percent and 0.25 weight percent solutions for viscosity measurements. The results are summarized in Table 8. Aging Results on NVP/DMAm Copolymers and VP/Am/DMAm Terpolymers Aged in Synthetic North Sea Water Wt/Wt/Wt NVP/Am/DMAm Inherent Viscosity(dL/g) Viscosity, Pas·10³ (cP), 121°C (250°F) (2500 ppm) Unaged Aged 40/0/60 6.12 0.60 0.64 50/50/0 8.70 1.78 0.75 47.5/47.5/5 7.96 1.60 0.80 45/45/10 8.10 1.62 0.67 50/0/50 5.83 0.68 0.73 Referring to the results in Table 8, it can be seen that the compositions listed are suitable for use as mobility buffers in hostile environments because the aged viscosities are on the order of 2 to 3 times the viscosity of sea water at 121°C (250°F). EXAMPLE 11 N,N-Dimethylacrylamide/Sodium 2-Acrylamido-2-Methylpropanesulfonate Copolymers This example describes the testing of copolymers of DMAm and NaAMPS using VAZO® 33 as the initiator (0.10 phm). The copolymerizations were carried out in distilled water at ambient temperatures for a period of 24 hours. The following DMAm/NaAMPS copolymers were prepared: 60/40; 70/30; and 80/20. The gelled reaction masses were mixed individually with sufficient synthetic North Sea water to prepare 0.1 weight percent and 0.25 weight percent solutions for viscosity measurements. The results are summarized in Table 9. Aging Results on DMAm/NaAMPS Copolymers Aged in Synthetic North Sea Water Wt/Wt DMAm/NaAMPS Inherent Viscosity(dL/g) Viscosity, Pas·10³ (cP) 121°C (250°F) (2500 ppm) Unaged Aged 40/60 8.48 2.08 0.86 30/70 7.85 2.07 1.37 The results in Table 9 indicate that the DMAm/NaAMPS copolymers are potentially useful as mobility control agents in hostile environments because the aged viscosities of 3 to 5 times the viscosity of sea water at 121°C (250°F) indicates excellent stability. In a related experiment, a 25/75 acrylamide/NaAMPS copolymer failed the thermal aging test (aged viscosity 0.33 cP). However, a 10/90 acrylamide/NaAMPS copolymer solution exhibited an aged viscosity of 5.3·10⁻⁴ Pas (0.53 cP) which is about 2 times the viscosity of sea water at 121°C (250°F). EXAMPLE 12 NVP/AM/NaAMPS Polymers This example presents in tabular form (see Table 10) a variety of NVP/Am/NaAMPS polymer compositions which performed well enough in thermal aging tests to merit consideration as mobility control agents in hostile environments. Aging Results on Representative NVP/Am/NaAMPS Polymers Aged in Synthetic North Sea Water Wt/Wt/Wt NVP/Am/NaAMPS Inherent Viscosity(dL/g) Viscosity, Pas·10³ (cP), 121°C (250°F) (2500 ppm) Unaged Aged 30/15/55 9.01 2.19 1.85 30/15/55 8.38 2.08 1.40 50/25/25 8.19 1.56 1.28 25/10/65 7.98 1.65 1.20 35/25/40 7.97 1.76 1.09 30/23/47 8.05 2.20 1.05 30/20/50 7.98 1.90 0.99 50/45/5 8.70 1.73 0.99 50/43/7 8.19 1.77 0.93 42.5/50/7.5 5.35 1.37 0.34 The last entry in Table 10 is a 42.5/50/7.5 NVP/Am/NaAMPS polymer which performed very poorly in the thermal aging test (aged viscosity 3.4·10⁻⁴ Pas (0.34 cP); the viscosity of sea water at 121°C (250°F) is about 2.8·10⁻⁴ Pas (0.28 cP)). Part of this lack of thermal stability is believed related to the weight ratio of NVP to Am in the polymer. Part is believed related to something which went wrong during the sample preparation. This polymer would be useful in lower temperature applications. It should be noted that in the first nine entries of Table 10 which all performed well in the thermal aging tests the polymers contained >1:1 wt/wt ratio of NVP:Am. The last polymer entry in the table contained <1:1 wt/wt ratio of NVP:Am. EXAMPLE 13 This example describes the properties of poly(N-vinyl-2-pyrrolidone-co-sodium 2-acrylamido-2-methylpropanesulfonate)(NVP/NaAMPS copolymer) and poly(N-vinyl-2-pyrrolidone-co-acrylamide-co-sodium 2-acrylamido-2-methyl-propanesulfonate)(NVP/Am/NaAMPS terpolymer) obtained by inverse emulsion polymerization. The receipes for the polymerizations are summarized in Table 11. Receipes For Polymerizations (Reaction Temperature 5°C; Reaction Time 120 Hours) Sample No. Toluene (g) H₂O(g) Tetronic™ 1102(g) NVP(g) Am(g) 50 Wt% AQ.NaAMPS Wt/Wt/Wt NVP/Am/NaAMPS 1 40 20 5 9 4.5 33 30/15/55 2 40 16.5 5 10 0 40 33/0/67 3 40 6.5 0 0 0 60 0/0/100 The above reaction charges were placed in individual 280 g (10 ounce) crown top bottles to prepare, respectively, NVP/Am/NaAMPS (30/15/55) polymer and NVP/NaAMPS (33/67) polymer by inverse emulsion polymerization. The necessary amount of VAZO® 33 was added as an aliquot of a stock solution of initiator in toluene. The surfactant was dissolved in toluene and added to the reactor bottle followed by the specified amounts of monomers and water. After degassing the reaction mixture for 20 minutes with argon, the bottle was capped and tumbled for about 5 days in a 5°C constant temperature bath. The reaction products were milky fluids. Portions of the milky fluids were individually mixed with sufficient synthetic North Sea water to give 0.1 wt% and 0.25 wt% solutions for viscosity measurements. The results are shown in Table 12. Aging Results in Synthetic North Sea Water With Polymers Prepared by Inverse Emulsion Polymerization Sample No. Wt/Wt/Wt NVP/Am/NaAMPS Inherent Viscosity(dL/g) Viscosity, Pas·10³ (cP), 121°C (250 F) (2500ppm) Unaged Aged 1 30/15/55 9.31 2.66 0.99 2 33/0/67 6.22 1.56 1.06 Referring to the results in Table 12, it is apparent that the disclosed polymers prepared by emulsion polymerization are potential candidates for mobility control agents in hostile environments because of their enhanced thermal stability indicated by the fact that their aged viscosities were on the order of 3 to 4 times the viscosity of seawater at 121°C (250°F)

Claims: A process for enhancing oil recovery or for the drilling, workover or completion of wells for the recovery of natural resources in a hostile environment, comprising introducing an aqueous polymer solution, such as a drilling fluid, a workover fluid, a completion fluid, a flooding liquid or a permeability correction liquid, into a subterranean formation, wherein said polymer is contacted with a hostile environment defined by a temperature of 170-400°F (77 to 204°C) and a concentration of multivalent cations, including calcium and magnesium, of 500 to 220,000 ppm by weight and wherein said polymer is produced from a monomer composition comprising two or more of N-vinyl pyrrolidone (NVP), acrylic amide (AA) ad 2-acrylamido-2-methylpropane sulfonic acid or sulfonate salt (AMPS), said polymer being selected from a) NVP/AA/AMPS terpolymers b) NVP/AA copolymers c) NVP/AMPS copolymers, and d) AA/AMPS copolymers. The process of claim 1, wherein the weight ratio NVP/AA/AMPS in said terpolymer (a) is 30:15:55. The process of claim 1, wherein the weight ratio NVP/AA in said copolymer (b) is 50:50. The process of claim 1, wherein in said polymer (b) up to 10wt% of the total monomers are replaced by a termonomer selected from methyl acrylate, butyl acrylate, methyl methacrylate, lauryl methacrylate, acrylonitrile, hydroxyethyl methacrylate, hydroxypropyl methacrylate, hydroxyethyl acrylate, vinyl pyridines, vinyl acetate and styrene. The process of claim 1, wherein the weight ratio NVP/AA in said copolymer (b) is 10:90. The process of claim 1, wherein the weight ratio NVP/AMPS in said copolymer (c) is 35:65. The process of claim 1, wherein the weight ratio AA/AMPS in said copolymer (d) is 30:70.

Inventors: HSIEH HENRY LIEN, MORADI-ARAGHI AHMAD, STAHL GLENN ALLAN, WESTERMAN IRA JOHN, HSIEH, HENRY LIEN, MORADI- ARAGHI, AHMAD, STAHL, GLENN ALLAN, WESTERMAN, IRA JOHN
Applicants: PHILLIPS PETROLEUM CO, PHILLIPS PETROLEUM COMPANY
Application year: 1984
Main classification: E21B43
IPC codes: C08F226, C09K8, E21B43