Patent Publication Number: US-2017362493-A1

Title: Process and composition for alkaline surfactant polymer flooding

Description:
The present application claims priority to U.S. Provisional Application No. 61/092,001, filed Dec. 15, 2014, the disclosure of which is incorporated by reference herein. 
    
    
     FIELD OF THE INVENTION 
     The present invention is directed to a method for producing oil from a formation, in particular, the present invention is directed to a method of enhanced oil recovery from a formation. 
     BACKGROUND OF THE INVENTION 
     In the recovery of oil from a subterranean formation, it is possible to recover only a portion of the oil in the formation using primary recovery methods utilizing the natural formation pressure to produce the oil. A portion of the oil that cannot be produced from the formation using primary recovery methods may be produced by improved or enhanced oil recovery (EOR) methods. 
     One enhanced oil recovery method utilizes an alkaline-surfactant-polymer (“ASP”) flood in an oil-bearing formation to increase the amount of oil recovered from the formation. An aqueous dispersion of an alkaline component, a surfactant, and a polymer is injected into an oil-bearing formation to increase recovery of oil from the formation, either after primary recovery or after a secondary recovery waterflood. The ASP flood enhances recovery of oil from the formation by lowering interfacial tension between oil and water phases in the formation, thereby mobilizing the oil for production. Interfacial tension between the oil and water phases in the formation is reduced by the surfactant of the ASP flood and by the formation of soaps by alkali interaction with acids in the oil. The polymer increases the viscosity of the ASP fluid, typically to the same order of magnitude as the oil in the formation, so the mobilized oil may be forced through the formation for production by the ASP flood. 
     Use of ASP enhanced oil recovery to recover oil from subsea oil-bearing formations may be constrained by the amount of space available on an offshore oil recovery platform and by the weight limitations of the platform. Storage facilities must be provided for the polymer, the surfactant, and for the alkaline component. In some instances the offshore platform space and weight limitations preclude the use of ASP enhanced oil recovery since there is not enough room to store all of the components of the ASP flood on the platform or the weight of the components of the ASP flood is prohibitive for use on an offshore oil recovery platform. Alternatively, a floating vessel next to the offshore platform can be used for mixing chemicals but this is commercially unattractive due to expense. 
     Alkalis most commonly used as the alkaline component in ASP EOR processes include alkali hydroxides and alkali carbonates, and the most common alkaline component utilized in an ASP EOR process is sodium carbonate. Offshore oil recovery platform limitations on space and weight may render an alkali carbonate ASP enhanced oil recovery process untenable for recovering oil from a subsea formation due to the relatively large storage space required for the alkali carbonate storage, the large space required for mixing facilities, and the relatively heavy weight of the alkali carbonate solution. 
     Liquid ammonia may be utilized in place of an alkali carbonate or an alkali hydroxide as the alkaline component of an ASP EOR process to reduce the space requirements of a system for conducting the ASP EOR process. Anhydrous liquid ammonia yields 6.2 times the alkalinity of an equivalent weight amount of sodium carbonate, so the weight requirement of the alkaline component of an ASP flood utilizing anhydrous liquid ammonia may be reduced by 6.2 times relative to sodium carbonate while providing the same relative alkalinity. Less space and weight, therefore, are required to store the ammonia alkaline component relative to alkali carbonates or alkali hydroxides since less of the ammonia alkaline component may be used to provide equivalent levels of alkalinity. On an offshore platform used for recovery of oil from a subsea oil-bearing formation, space and weight savings provided by substituting liquid ammonia for commonly used alkali carbonates may be the determining factor of the feasibility of using an ASP EOR process on the platform and in the formation. 
     Use of ammonia as the alkaline component in an ASP EOR process and system, however, is limited to utilization with calcium tolerant surfactants. Calcium ions present in the oil and water of the formation and attached to formation surfaces are not precipitated when ammonia is used as the alkaline component of an ASP EOR flood instead of an alkali carbonate since calcium hydroxide, the calcium precipitate formed when utilizing liquid ammonia as the alkali in an ASP EOR process, will only precipitate at Ca 2+  concentrations above 8.8% at 25° C.—above the Ca 2+  concentration in most oil-bearing formations. Therefore, only calcium-tolerant surfactants—those surfactants that are not precipitated in the presence of significant quantities of calcium cations—may be utilized in ASP EOR process having ammonia as the alkaline component without substantial loss of surfactant to calcium precipitation. The most commercially practical calcium-tolerant surfactants useful in an ASP EOR process, however, are the ethylene oxide sulfate, propylene oxide sulfate, and ethylene oxide-propylene oxide sulfate surfactants that hydrolyze at an unacceptable rate above 60° C. Therefore, ASP EOR processes utilizing ammonia as the alkaline component are not particularly commercially practical in formations having significant concentrations of calcium ions therein and a formation temperature of at least 60° C., and ASP EOR processes in offshore formations having these characteristics may be commercially impractical. 
     An alkali metal carbonate or an alkali metal bicarbonate may be used in conjunction with ammonia to form the alkaline component in an ASP EOR process and system using a calcium sensitive surfactant, where sufficient alkali metal carbonate may be used in the ASP formulation to interact with calcium in the formation to inhibit significant precipitation of the surfactant while ammonia is utilized as the bulk of the alkaline component of the ASP formulation. This mixed alkali/ammonia ASP formulation provides the benefit of reducing the overall weight and space requirements for the alkaline component relative to alkaline components formed of alkalis only while permitting the use of calcium sensitive surfactants. These mixed alkali/ammonia ASP formulations, however, may induce significant precipitation of calcium carbonate in formations having a significant quantities of calcium therein, potentially blocking the flow of the ASP formulation through the formation. Also, mixed alkali solutions can cause calcium carbonate scale in production wells as carbonate solution mixes with calcium containing reservoir brine from lower permeability reservoir strata. 
     Improvements to existing ASP enhanced oil recovery processes and compositions are desirable. In particular, processes and compositions effective to further enable utilization of ASP-based enhanced oil recovery in subsea oil-bearing sandstone formations having significant concentrations of calcium ions and formation temperatures of at least 50° C. or at least 60° C. are desirable. 
     SUMMARY OF THE INVENTION 
     In one aspect, the invention is directed to a process for recovering oil from an oil-bearing formation, comprising: 
     mixing a surfactant, water, a polymer, a chelating agent, and ammonia liquid comprising at most 10 wt. % water to form an oil recovery formulation; 
     introducing the oil recovery formulation into the oil-bearing formation; 
     contacting the oil recovery formulation with oil in the oil-bearing formation; and 
     producing oil from the oil-bearing formation after introduction of the oil recovery formulation into the oil-bearing formation. 
     In another aspect, the invention is directed to an enhanced oil recovery formulation composition comprising a surfactant, a polymer, a chelating agent, ammonia, and water. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is an illustration of an oil production system that may be utilized to recover oil by a process in accordance with the present invention. 
         FIG. 2  is an illustration of an oil production system that may be utilized to recover oil by a process in accordance with the present invention. 
         FIG. 3  is a diagram of a well pattern for production of oil in accordance with a process of the present invention. 
         FIG. 4  is a diagram of a well pattern for production of oil in accordance with a process of the present invention. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     The present invention is directed to a process for enhanced oil recovery from an oil-bearing formation utilizing an oil recovery formulation that is comprised of a surfactant, water, a polymer, a chelating agent, an ammonia liquid comprising at most 10 wt. % water; and is also directed to an oil recovery formulation composition comprising a surfactant, a polymer, a chelating agent, ammonia, and water. In the process of the present invention, the surfactant, water, polymer, chelating agent, and ammonia liquid may be mixed together to form the oil recovery formulation which is introduced into an oil-bearing formation to enhance recovery of oil from the formation. The surfactant and the ammonia may mobilize the oil in the formation by reducing interfacial tension between oil and water in the formation, the polymer may provide a viscosity sufficient to drive the mobilized oil through the formation for production from the formation, and the chelating agent may inhibit reaction of calcium and magnesium cations in the formation with the surfactant of the oil recovery formulation thereby inhibiting calcium and magnesium induced precipitation of the surfactant. 
     Use of ammonia is favorable for reducing space and weight requirements of an ASP EOR process relative to conventionally used alkali metal carbonates. For example, anhydrous liquid ammonia yields 6.2 times the alkalinity of an equivalent weight amount of sodium carbonate, so the weight requirement of the alkali component of an ASP flood system utilizing anhydrous liquid ammonia may be reduced by 6.2 times relative to sodium carbonate while providing the same relative alkalinity. Less space and weight, therefore, are required to store the ammonia alkali component relative to conventionally used alkali-carbonate alkali components since less must be used to provide equivalent levels of alkalinity. On an offshore platform used for recovery of oil from a subsea oil-bearing formation, space and weight savings provided by substituting liquid ammonia for conventionally used alkali components may be a determining factor of the feasibility of using an ASP EOR process on the platform. 
     Sufficient chelating agent may be included in the oil recovery formulation to sequester calcium and/or magnesium cations encountered in the formation as the slug of oil recovery formulation moves through the formation, permitting the use of commercially practical surfactants in the oil recovery formulation that are stable at formation temperatures above 60° C. but are susceptible to precipitation in the presence of calcium and/or magnesium cations. Preferably, only small quantities of chelating agent are provided in the oil recovery formulation utilized in the process of the present invention, thereby realizing the space and weight savings provided by using ammonia as an alkaline component of the oil recovery formulation while enabling the use of calcium and magnesium intolerant surfactants in the oil recovery formulation. 
     The oil recovery formulation composition of the present invention that may be used in the process of the present invention is comprised of a surfactant, a polymer, a chelating agent, ammonia, and water. The water may be fresh water or a brine solution. The water may have a total dissolved solids (TDS) content of from 100 ppm to 200000 ppm. The water may be provided from a water source, where the water source may be a fresh water source having a TDS content of less than 10000 ppm selected from the group consisting of a river, a lake, a fresh water sea, an aquifier, and formation water having a TDS content of less than 10000 ppm, or the water source may be a saline water source having a TDS content of 10000 ppm or greater selected from the group consisting of seawater, estuarine water, brackish water, an aquifer, a brine solution provided by processing a saline water source, and formation water having a TDS content of 10000 ppm or greater. 
     When the ASP EOR process utilizing the oil recovery formulation is conducted offshore to recover oil from a subsea oil-bearing formation, the water may be seawater treated to reduce the salinity of the seawater to a desired TDS content. The salinity of the seawater may be reduced by conventional desalination processes, for example, by passing the seawater through one or more nanofiltration, reverse osmosis, and/or forward osmosis membranes or an ion exchange material. 
     The TDS content of the oil recovery formulation water may be adjusted to optimize the salinity of the water for the production of a middle phase, type III, microemulsion of the oil recovery formulation in combination with oil and formation water in the formation and thereby minimize interfacial tension between oil and water in the formation to maximize mobilization, and therefore, production, of the oil from the formation. The TDS content of the oil recovery formulation water may also be adjusted to optimize the viscosity of the oil recovery formulation, since the viscosity of the oil recovery formulation is dependent in part on the viscosity of the polymer in the formulation, which may be dependent on the salinity of the formulation. Determination of the optimum salinity of the oil recovery formulation water for minimizing interfacial tension of the oil and water in the oil-bearing formation and for providing a viscosity on the same order of magnitude as the oil in the formation may be conducted according to methods conventional and known to those skilled in the art. One such method is described in WO Pub. No. 2011/090921. Salinity optimization of the water may be conducted in accordance with methods conventional and known to those skilled in the art, for example, salt concentrations may be decreased by ionic filtration using one or more nanofiltration membrane units, one or more reverse osmosis membrane units, and/or one or more forward osmosis membrane units; salt concentrations may be increased by adding one or more salts to the water; salt concentrations may be decreased by ion exchange with an ionic exchange material that releases hydrogen and hydroxide ions in exchange for ions in the water, and salt concentrations may be increased or decreased by blending of the resulting permeates and retentates of ionic filtration to provide optimum salinity. 
     The oil recovery formulation may also be comprised of a co-solvent miscible with water, where the co-solvent may be a low molecular weight alcohol including, but not limited to, methanol, ethanol, and propanol, isobutyl alcohol, secondary butyl alcohol, n-butyl alcohol, t-butyl alcohol, or a glycol including, but not limited to, ethylene glycol, 1,3-propanediol, 1,2-propandiol, diethylene glycol butyl ether, triethylene glycol butyl ether, or a sulfosuccinate including, but not limited to, sodium dihexyl sulfosuccinate. The co-solvent may be utilized for the purpose of adjusting the salinity of the oil recovery formulation fluid to optimize the salinity of the fluid for maximum reduction of interfacial tension between oil and water in the formation, and, optionally, for assisting in prevention of formation of a viscous emulsion upon conducting the EOR process. If present, the co-solvent may comprise from 100 ppm to 50000 ppm, or from 500 ppm to 5000 ppm of the oil recovery formulation. A co-solvent may be absent from the oil recovery formulation, and the oil recovery formulation may be free of a co-solvent. 
     The oil recovery formulation further comprises ammonia, where the ammonia may interact with oil in the formation to form a soap effective to reduce the interfacial tension between oil and water in the formation. The ammonia may also reduce surfactant adsorption on the reservoir rock surfaces. An ammonia liquid may be mixed with other components of the enhanced oil recovery formulation to form the enhanced oil recovery formulation, where the ammonia liquid may be mixed with the other enhanced oil recovery formulation components 1) prior to introduction of the enhanced oil recovery formulation to the oil-bearing formation, or 2) after one or more of the enhanced oil recovery formulation components have been individually introduced into the formation, or 3) simultaneously with introduction of one or more of the enhanced oil recovery formulation components into the formation, but separate from at least one of the components. The ammonia liquid mixed with the other components of the oil recovery formulation to form the oil recovery formulation utilized in the ASP EOR process of the present invention, and to form the composition of the present invention, may be an ammonia liquid comprising at most 10 wt. % water, or at most 5 wt. % water, or at most 1 wt. % water and at least 90 wt. % ammonia. Most preferably, the ammonia liquid is anhydrous liquid ammonia to minimize the weight and space requirements for storing and utilizing the liquid ammonia in the ASP EOR process of the present invention. 
     The ammonia liquid is mixed with the other components of the oil recovery formulation, or is present in the oil recovery formulation, in an amount to provide the oil recovery formulation with a pH of at least 10. The ammonia liquid mixed with the other components of the oil recovery formulation, or the ammonia present in the oil recovery formulation, may provide relatively highly buffered alkalinity to the oil recovery formulation due to ammonia&#39;s dissociation constant, enabling the oil recovery formulation to have a relatively low but useful pH for an alkaline solution used in an ASP EOR process. A relatively low alkaline pH ASP oil recovery formulation may be desirable for use in certain oil-bearing formations to prevent dissolution of formation minerals by strong alkalinity—for example, formations containing significant quantities of silica quartz. Furthermore, the relatively highly buffered alkalinity provided to the oil recovery formulation by the ammonia may decrease the time required and the amount of oil recovery formulation required for the oil recovery formulation to breakthrough from an injection well to a production well in the ASP EOR process of the present invention; alkalis that are not highly buffered react with the formation, increasing the amount of oil recovery formulation and time required for the oil recovery formulation to breakthrough from an injection well to a production well. Preferably the ammonia liquid is mixed with the other components of the oil recovery formulation, or is present in the oil recovery formulation, in an amount sufficient to provide the oil recovery formulation with an initial pH of from 10 to 12. The ammonia liquid may be mixed with the other components of the oil recovery formulation, or may be present in the oil recovery formulation, in an amount to provide ammonia in a concentration in the oil recovery formulation of from 0.01M to 2M, or from 0.1M to 1 M. 
     The oil recovery formulation composition further comprises a chelating agent, where the chelating agent is effective to chelate divalent cations, including calcium and/or magnesium cations, encountered by the oil recovery formulation in the oil-bearing formation. The chelating agent is preferably selected from the group consisting of aminocarboxylic acids/aminocarboxylates and phosphonic acids/phosphonates. Preferred chelating agents may be selected from the group consisting of ethylenediamine(tetraacetic acid) (“EDTA”), ethylenediamine, diethylenetriamine(pentaacetic acid) (“DTPA”), tri(carboxylmethyl)amine, triethylenetetraamine, aminotris(methylenephosphonic acid)(“ATMP”), ethyelenediaminetetra(methylenephosphonic acid)(“EDTMP”), diethyelenetriaminepenta(methylenephosphonic acid)(“DTPMP”), nitrilotris(methylene phosphonic acid)(“NTMP”), tetramethylenediamine tetra(methylenephosphonic acid)(“TDTMP”), hexamethylenediaminetetra(methylenephosphonic acid)(“HDTMP”), iminodiacetic acid (“IDA”), nitrilotriacetic acid (“NTA”), ethyleneglycoltetraacetic acid (“EGTA”), and mixtures thereof. The chelating agent may be mixed with other components of the oil recovery formulation to form the oil recovery formulation, where the chelating agent may be mixed with the other oil recovery formulation components 1) prior to introduction of the oil recovery formulation to the oil-bearing formation, or 2) after one or more of the oil recovery formulation components have been individually introduced into the formation, or 3) simultaneously with introduction of one or more of the oil recovery formulation components into the formation, but separate from at least one of the components. 
     The oil recovery formulation composition may contain an amount of the chelating agent effective to chelate a substantial portion of divalent cations contacted by the oil recovery formulation in the oil-bearing formation. The chelating agent may be present in the oil recovery formulation in at least an amount sufficient to sequester a significant amount of calcium cations instantaneously contacted by the oil recovery formulation in the formation, preferably at least 50%, or at least 75%, or at least 90%, or at least 95%, or at least 99%, or substantially all, or 100% of the calcium cations instantaneously contacted by the oil recovery formulation in the formation. Preferably, the amount of chelating agent mixed with other components of the oil recovery formulation, or present in the oil recovery formulation, is limited to an amount of at most 10 times, or at most 5 times, or at most 1 times that required to sequester 100% of calcium cations in the formation that may be instantaneously contacted with the oil recovery formulation. The amount of chelating agent mixed with other components of the oil recovery formulation, or present in the oil recovery formulation, may be from 0.001 wt. % to 1 wt. %, or from 0.01 wt. % to 0.5 wt. %, or from 0.05 wt. % to 0.1 wt. % of the total combined weight of the surfactant, polymer, chelating agent, ammonia liquid, and water of the oil recovery formulation. 
     The amount of chelating agent sufficient to sequester 100% of the calcium cations in the formation instantaneously contacted by the oil recovery formulation in the formation may be directly reasonably approximated. When the formation contains connate water or formation brine containing significant quantities of calcium, calcium cations present in the formation that may be instantaneously contacted by the oil recovery formation are primarily located on cation binding ion exchange sites within the formation. Since a negligible amount of multivalent cations having a valency of 3 or greater are present in a formation relative to monovalent and divalent cations, a reasonable approximation of the concentration of calcium cations on cation binding sites in a formation may be determined. The concentration of all monovalent cations and all divalent cations (in equivalents) present in the formation water may be measured, and the fraction of formation rock ion exchange sites that are binding divalent cations and that are to be swept by the oil recovery formulation may be determined by first calculating the monovalent fraction from equations 1 and 2, and then the divalent fraction by (++) r =1−(+) r . 
     
       
         
           
             
               
                 
                   
                     
                       ( 
                       + 
                       ) 
                     
                     r 
                   
                   = 
                   
                     
                       
                         
                           - 
                           k 
                         
                         + 
                         
                           
                             
                               k 
                               2 
                             
                             + 
                             
                               4 
                                
                               Qvk 
                             
                           
                         
                       
                       2 
                     
                      
                     
                         
                     
                      
                     where 
                   
                 
               
               
                 
                   ( 
                   
                     equation 
                      
                     
                         
                     
                      
                     1 
                   
                   ) 
                 
               
             
             
               
                 
                   k 
                   = 
                   
                     
                       [ 
                       
                         
                           
                             [ 
                             + 
                             ] 
                           
                           w 
                           2 
                         
                         
                           
                             [ 
                             ++ 
                             ] 
                           
                           w 
                         
                       
                       ] 
                     
                     * 
                     
                       0.3 
                       . 
                     
                   
                 
               
               
                 
                   ( 
                   
                     equation 
                      
                     
                         
                     
                      
                     2 
                   
                   ) 
                 
               
             
           
         
       
         
         
           
             where subscript (w) indicates an ion in formation water and subscript (r) indicates a formation rock site occupied by a ion, and [+] w  indicates monovalent cation concentration (in equivalents) in formation water, [++] w  indicates divalent cation concentration (in equivalents) in formation water, and (+) r  indicates monovalent cation fraction on the rock, and Q v  is the cation exchange capacity (CEC) per ml of pore space (meq/ml) of the formation rock, and where 
           
         
       
    
     
       
         
           
             
               
                 ( 
                 ++ 
                 ) 
               
               r 
             
             = 
             
               
                 
                   
                     ( 
                     
                       equivalents 
                       ++ 
                     
                     ) 
                   
                   r 
                 
                 
                   { 
                   
                     
                       
                         ( 
                         
                           equivalents 
                           ++ 
                         
                         ) 
                       
                       r 
                     
                     + 
                     
                       
                         ( 
                         
                           equivalents 
                           + 
                         
                         ) 
                       
                       r 
                     
                   
                   } 
                 
               
               . 
             
           
         
       
     
     The fraction of calcium cations present on cation binding sites of formation rock that are to be swept by oil recovery formulation may be calculated by measuring the concentration of calcium ions in the formation water, calculating the ratio of calcium ion concentration in the formation water to total divalent cation concentration in the formation water, and multiplying the calculated fraction of formation rock ion exchange sites to be swept by the oil recovery formulation that are binding divalent cations by the calculated ratio of calcium cations in the formation water to the total divalent cations in the formation water as shown in equation (3): 
       (Ca 2+ ) r =(++) r *([Ca 2+ ] w ,[++] w )  (equation 3).
 
     The concentration of calcium cations per volume of the formation may be determined by measuring the grain density, the porosity, and the cation exchange capacity (CEC) of the formation, calculating the volume of pore space in the formation rock according to equation (4) 
     
       
         
           
             
               
                 
                   
                     
                       V 
                       
                         pore 
                          
                         
                             
                         
                          
                         space 
                          
                         
                             
                         
                          
                         per 
                          
                         
                             
                         
                          
                         100 
                          
                         
                             
                         
                          
                         grams 
                          
                         
                             
                         
                          
                         foundation 
                          
                         
                             
                         
                          
                         rock 
                       
                     
                     = 
                     
                       
                         ( 
                         
                           
                             100 
                              
                             
                                 
                             
                              
                             g 
                           
                           
                             Grain 
                              
                             
                                 
                             
                              
                             Density 
                           
                         
                         ) 
                       
                       * 
                       
                         ( 
                         
                           Porosity 
                           
                             1 
                             - 
                             Porosity 
                           
                         
                         ) 
                       
                     
                   
                   , 
                 
               
               
                 
                   ( 
                   
                     equation 
                      
                     
                         
                     
                      
                     4 
                   
                   ) 
                 
               
             
           
         
       
     
     calculating the cation exchange capacity of the formation per volume of the formation (Qv) according to equation (5) 
     
       
         
           
             
               
                 
                   
                     
                       Qv 
                       
                         ( 
                         
                           
                             meq 
                             / 
                             ml 
                           
                            
                           
                               
                           
                            
                           of 
                            
                           
                               
                           
                            
                           pore 
                            
                           
                               
                           
                            
                           space 
                         
                         ) 
                       
                     
                     = 
                     
                       
                         
                           CEC 
                           formation 
                         
                          
                         
                           ( 
                           
                             meq 
                             
                               100 
                                
                               
                                   
                               
                                
                               g 
                             
                           
                           ) 
                         
                       
                       
                         V 
                         
                           pore 
                            
                           
                               
                           
                            
                           space 
                            
                           
                               
                           
                            
                           per 
                            
                           
                               
                           
                            
                           100 
                            
                           
                               
                           
                            
                           grams 
                            
                           
                               
                           
                            
                           foundation 
                            
                           
                               
                           
                            
                           rock 
                         
                       
                     
                   
                   , 
                 
               
               
                 
                   ( 
                   
                     equation 
                      
                     
                         
                     
                      
                     5 
                   
                   ) 
                 
               
             
           
         
       
     
     and calculating the concentration of calcium cations (in milliequivalents) per volume of the formation according to equation (6): 
       [Ca 2+ ] per volume of formation (meq/ml)   =Qv   (meq/ml) *(Ca 2+ ) r (Ca2+ fraction on formation rock ion exchange sites)   (equation 6).
 
     Assuming that 1 mole of chelating agent will sequester 1 mole (2 equivalents) of Ca 2+  the required concentration of chelating agent in weight % can be calculated by equation (7), assuming the oil recovery formulation has a density of about 1 (a good approximation for dilute aqueous solutions): 
       Wt chelating agent (%)=(meq/ml [Ca2+]*molecular weight/mole of chelating agent)/(10/2)   (equation 7).
 
     The approximate amount of chelating agent (wt. %) in the oil recovery formulation required to precipitate all of the calcium in the formation in a volume swept by the oil recovery formulation may then be calculated based on the fractional pore volume (P. V.) of oil recovery formulation used to sweep the formation, according to equation (8): 
       Wt % of chelating agent in chemical slug=wt % chelating agent needed to complex Ca/fraction of reservoir PV injected with chemical slug  (8)
 
     Typically 0.3 PV of chemical slug is injected into the reservoir. 
     The oil recovery formulation composition further comprises a surfactant, where the surfactant may be any surfactant effective to reduce the interfacial tension between oil and water in the oil-bearing formation and thereby mobilize the oil for production from the formation. The surfactant may be mixed with other components of the oil recovery formulation to form the oil recovery formulation, where the surfactant may be mixed with the other oil recovery formulation components 1) prior to introduction of the oil recovery formulation to the oil-bearing formation, or 2) after one or more of the oil recovery formulation components have been individually introduced into the formation, or 3) simultaneously with introduction of one or more of the oil recovery formulation components into the formation, but separate from at least one of the components. The oil recovery formulation may comprise one or more surfactants. The surfactant may be an anionic surfactant. The anionic surfactant may be a sulfonate-containing compound, a sulfate-containing compound, a carboxylate compound, a phosphate compound, or a blend thereof. The anionic surfactant may be an alpha olefin sulfonate compound, an internal olefin sulfonate compound, a branched alkyl benzene sulfonate compound, an alkyl propylene oxide sulfate compound, an alkyl ethylene oxide sulfate compound, an alkyl propylene oxide-ethylene oxide sulfate compound, or a blend thereof. The anionic surfactant may be a surfactant that forms a water insoluble calcium salt in the presence of calcium cations. The anionic surfactant may be stable at temperatures of from 50° C. to 90° C., or from 60° C. to 75° C. The anionic surfactant may have a hydrophobic tail containing from 12 to 28 carbons, or from 12 to 20 carbons. The surfactant of the oil recovery formulation may comprise an internal olefin sulfonate compound containing from 15 to 18 carbons or an alkyl propylene oxide sulfate compound containing from 12 to 15 carbons, or a blend thereof, where the blend contains a volume ratio of the alkyl propylene oxide sulfate to the internal olefin sulfonate compound of from 1:1 to 10:1. 
     The oil recovery formulation composition may contain an amount of the surfactant effective to reduce the interfacial tension between oil and water in the formation and thereby mobilize the oil for production from the formation. The oil recovery formation composition may contain from 0.05 wt. % to 5 wt. % of the surfactant or combination of surfactants, or may contain from 0.1 wt. % to 3 wt. % of the surfactant or combination of surfactants. 
     The oil recovery formulation composition further comprises a polymer, where the polymer may provide the oil recovery formulation with a viscosity on the same order of magnitude as the viscosity of oil in the formation under formation temperature conditions so the oil recovery formulation may drive mobilized oil across the formation for production from the formation with a minimum of fingering of the oil through the oil recovery formulation and/or fingering of the oil recovery formulation through the oil. The polymer may be in an aqueous solution or an aqueous dispersion prior to being mixed to form the oil recovery formulation. The polymer may be mixed with other components of the oil recovery formulation to form the oil recovery formulation, where the polymer may be mixed with the other oil recovery formulation components 1) prior to introduction of the oil recovery formulation to the oil-bearing formation, or 2) after one or more of the oil recovery formulation components have been individually introduced into the formation, or 3) simultaneously with introduction of one or more of the oil recovery formulation components into the formation, but separate from at least one of the components. 
     The oil recovery formulation composition may comprise a polymer selected from the group consisting of polyacrylamides, partially hydrolyzed polyacrylamides, polyacrylates, ethylenic co-polymers, biopolymers, carboxymethylcelloluses, polyvinyl alcohols, polystyrene sulfonates, polyvinylpyrrolidones, AMPS (2-acrylamide-methyl propane sulfonate), and combinations thereof. Examples of ethylenic co-polymers include co-polymers of acrylic acid and acrylamide, acrylic acid and lauryl acrylate, and lauryl acrylate and acrylamide. Examples of biopolymers include xanthan gum and guar gum. 
     The quantity of polymer in the oil recovery formulation should be sufficient to provide the oil recovery formulation with a viscosity sufficient to drive the oil through the oil-bearing formation with a minimum of mobilized oil fingering through the oil recovery formulation and, optionally, a minimum of fingering of the oil recovery formulation through the mobilized oil. The quantity of the polymer in the oil recovery formulation may be sufficient to provide the oil recovery formulation with a dynamic viscosity at formation temperatures on the same order of magnitude, or, less preferably a greater order of magnitude, as the dynamic viscosity of the oil in the oil-bearing formation at formation temperatures so the oil recovery formulation may push the oil through the formation. In a preferred embodiment, the oil recovery formulation may have a dynamic viscosity within 400%, or within 300%, or within 200% of the dynamic viscosity of the oil in the oil-bearing formation when measured isothermally. The quantity of the polymer in the oil recovery formulation may be sufficient to provide the oil recovery formulation with a dynamic viscosity of at least 1 mPa s (1 cP), or at least 10 mPa s (10 cP), or at least 50 mPa s (50 cP), or at least 100 mPa s (100 cP) at 25° C. or at a temperature within a formation temperature range. The concentration of polymer in the oil recovery formulation may be from 200 ppm to 10000 ppm, or from 500 ppm to 5000 ppm, or from 1000 to 2500 ppm. 
     The molecular weight average of the polymer in the oil recovery formulation should be sufficient to provide sufficient viscosity to the oil recovery formulation to drive the mobilized oil through the formation. The polymer may have a molecular weight average of from 10,000 to 30,000,000 daltons, or from 100,000 to 10,000,000 daltons. 
     In one aspect, the present invention is directed to an oil recovery formulation composition comprising water, ammonia, a chelating agent, a surfactant, and a polymer. The water, ammonia, chelating agent, surfactant, and polymer may be as described above. The oil recovery formulation composition may contain an amount of ammonia liquid comprising at most 10 wt. % water, preferably anhydrous liquid ammonia, at an ammonia concentration of from 0.01M to 2 M, or from 0.01 wt. % to 5 wt. % ammonia; from 0.001 wt. % to 2 wt. %. or from 0.01 wt. % to 1 wt. %, or from 0.05 wt. % to 0.5 wt. % of a chelating agent; from 0.05 wt. % to 5 wt. %, or from 0.1 wt. % to 3 wt. % of the surfactant or combination of surfactants; and from 200 ppm to 10000 ppm, or from 500 ppm to 5000 ppm, or from 1000 to 2500 ppm of the polymer or a combination of polymers. 
     In the process of the present invention, the oil recovery formulation is, or components of the oil recovery formulation are, introduced into an oil-bearing formation. The oil-bearing formation comprises oil that may be separated and produced from the formation after contact and mixing with the oil recovery formulation. The oil of the oil-bearing formation may contain oil having a total acid number (TAN) expressed in milligrams of KOH per gram of sample of at least 0.1 or at least 0.3 or at least 0.5, wherein the TAN of an oil may be determined in accordance with ASTM Method D664. Oils having a TAN of at least 0.1 contain significant quantities of acidic moieties that may interact with ammonia to form a soap when treated with an oil recovery formulation comprising ammonia, thereby reducing interfacial tension between oil and water in the formation and mobilizing the oil for production from the formation. 
     The oil contained in the oil-bearing formation may be a light oil or an intermediate weight oil containing less than 25 wt. %, or less than 20 wt. %, or less than 15 wt. %, or less than 10 wt. %, or less than 5 wt. % of hydrocarbons having a boiling point of at least 538° C. (1000° F.) and having an API gravity as determined in accordance with ASTM Method D6882 of at least 20°, or at least 25°, or at least 30°. Alternatively, but less preferably, the oil of the oil bearing-formation may be a heavy oil containing more than 25 wt. % of hydrocarbons having a boiling point of at least 538° C. and having an API gravity of less than 20°. 
     The oil contained in the oil-bearing formation may have a dynamic viscosity under formation conditions (in particular, at temperatures within the temperature range of the formation) of at least 0.4 mPa s (0.4 cP), or at least 10 mPa s (10 cP), or at least 100 mPa s (100 cP), or at least 1000 mPa s (1000 cP), or at least 10000 mPa s (10000 cP). The oil contained in the oil-bearing formation may have a dynamic viscosity under formation temperature conditions of from 0.4 to 10000000 mPa s (0.4 to 10000000 cP). 
     The oil-bearing formation may be a subterranean formation. The subterranean formation may be comprised of one or more porous matrix materials selected from the group consisting of a porous mineral matrix, a porous rock matrix, and a combination of a porous mineral matrix and a porous rock matrix, where the porous matrix material may be located beneath an overburden at a depth ranging from 50 meters to 6000 meters, or from 100 meters to 4000 meters, or from 200 meters to 2000 meters under the earth&#39;s surface. 
     The subterranean formation may be a subsea subterranean formation. The process of the present invention may be particularly suited for recovering oil from an oil-bearing subsea subterranean formation utilizing an offshore oil recovery platform. 
     The porous matrix material may be a consolidated matrix material in which at least a majority, and preferably substantially all, of the rock and/or mineral that forms the matrix material is consolidated such that the rock and/or mineral forms a mass in which substantially all of the rock and/or mineral is immobile when oil, the oil recovery formulation, water, or other fluid is passed therethrough. Preferably at least 95 wt. % or at least 97 wt. %, or at least 99 wt. % of the rock and/or mineral is immobile when oil, the oil recovery formulation, water, or other fluid is passed therethrough so that any amount of rock or mineral material dislodged by the passage of the oil, oil recovery formulation, water, or other fluid is insufficient to render the formation impermeable to the flow of the oil recovery formulation, oil, water, or other fluid through the formation. The porous matrix material may be an unconsolidated matrix material in which at least a majority, or substantially all, of the rock and/or mineral that forms the matrix material is unconsolidated. The formation may have a permeability of from 0.0001 to 15 Darcys, or from 0.001 to 1 Darcy. The rock and/or mineral porous matrix material of the formation may be comprised of sandstone and/or a carbonate selected from dolomite, limestone, and mixtures thereof—where the limestone may be microcrystalline or crystalline limestone and/or chalk. 
     Oil in the oil-bearing formation may be located in pores within the porous matrix material of the formation. The oil in the oil-bearing formation may be immobilized in the pores within the porous matrix material of the formation, for example, by capillary forces, by interaction of the oil with the pore surfaces, by the viscosity of the oil, or by interfacial tension between the oil and water in the formation. 
     The oil-bearing formation may also be comprised of water, which may be located in pores within the porous matrix material. The water in the formation may be connate water, water from a secondary or tertiary oil recovery process water-flood, or a mixture thereof. The water in the oil-bearing formation may be positioned in the formation to immobilize oil within the pores. Contact of the oil recovery formulation with the oil and water in the formation may mobilize the oil in the formation for production and recovery from the formation by freeing at least a portion of the oil from pores within the formation by reducing interfacial tension between water and oil in the formation. 
     In some embodiments, the oil-bearing formation may comprise unconsolidated sand and water. The oil-bearing formation may be an oil sand formation. In some embodiments, the oil may comprise between about 1 wt. % and about 16 wt. % of the oil/sand/water mixture, the sand may comprise between about 80 wt. % and about 85 wt. % of the oil/sand/water mixture, and the water may comprise between about 1 wt. % and about 16 wt. % of the oil/sand water mixture. The sand may be coated with a layer of water with the petroleum being located in the void space around the wetted sand grains. Optionally, the oil-bearing formation may also include a gas, such as methane or air, for example. 
     The oil-bearing formation may be comprised of calcium cations and/or calcium compounds or salts from which calcium cations may be displaced. The calcium cations and/or calcium compounds or salts from which calcium cations may be displaced may be present in the connate water within the formation. The calcium cations may be present in the connate water in a concentration of from 10 ppm to 30,000 ppm. The calcium cations and/or calcium compounds or salts from which calcium cations may be displaced may be present in porous matrix material of the formation, as described above. 
     Referring now to  FIG. 1 , a system  200  for practicing a process of the present invention is shown. The system includes a first well  201  and a second well  203  extending into an oil-bearing formation  205  such as described above. The oil-bearing formation  205  may be comprised of one or more formation portions  207 ,  209 , and  211  formed of porous material matricies, such as described above, located beneath an overburden  213 . The oil-bearing formation  205  may be a subsea formation where the first well  201  and the second well  203  may extend from one or more offshore platforms  215  located on the surface of the sea  217  above the oil-bearing formation  205 . 
     In an embodiment of the process of the present invention, an oil recovery formulation may be provided comprising water as described above, ammonia as described above, a chelating agent as described above, a surfactant as described above, and a polymer as described above. The salinity of the oil recovery formulation may be selected and/or adjusted to optimize the interfacial tension reducing capacity of the surfactant and/or the ammonia of the oil recovery formulation with oil in the oil-bearing formation, and/or to optimize the viscosity of the oil recovery formulation, as described above. The oil recovery formulation may be provided from an oil recovery formulation storage facility  219  fluidly operatively coupled to a first injection/production facility  221  via conduit  223 . First injection/production facility  221  may be fluidly operatively coupled to the first well  201 , which may be located extending from the first injection/production facility  221  into the oil-bearing formation  205 . The oil recovery formulation may flow from the first injection/production facility  221  through the first well  201  to be introduced into the formation  205 , for example in formation portion  209 , where the first injection/production facility  221  and the first well, or the first well itself, include(s) a mechanism for introducing the oil recovery formulation into the formation. Alternatively, the oil recovery formulation may flow from the oil recovery formulation storage facility  219  directly to the first well  201  for injection into the formation  205 , where the first well may comprise a mechanism for introducing the oil recovery formulation into the formation. The mechanism for introducing the oil recovery formulation into the formation  205  via the first well  201 —located in the first injection/production facility  221 , the first well  201 , or both—may be comprised of a pump  225  for delivering the oil recovery formulation to perforations or openings in the first well through which the oil recovery formulation may be introduced into the formation. 
     In another embodiment as shown in  FIG. 2 , the system may include separate storage facilities for one or more of the ammonia liquid, chelating agent, surfactant, and polymer of the enhanced oil recovery formulation. The ammonia liquid may be stored in an ammonia liquid storage facility  227 , and may contain up to 10 wt. % water, or up to 5 wt. % water, or may be anhydrous liquid ammonia. The chelating agent, either as an aqueous solution or as a pure compound, may be stored in a chelating agent storage facility  228 . The surfactant may be stored in a surfactant storage facility  229 , and may be an anionic surfactant as described above. The polymer may be stored in a polymer storage facility  231 , and may be a polymer as described above. 
     Water may be provided from source water—for example sea water, produced formation water, lake water, aquifer water, or river water—treated in a water treatment facility  233  to adjust the salinity of the water to an optimum salinity for use in the oil recovery formulation as described above. The water treatment facility may be operatively fluidly coupled to the chelating agent storage facility  228  via conduit  234  to provide water for mixing with the chelating agent, if necessary; and/or may be operatively fluidly coupled to the surfactant storage facility  229  via conduit  235  to provide water for mixing with the surfactant to form a solution of the surfactant; and/or may be operatively fluidly coupled to the polymer storage facility  231  via conduit  237  to provide water for mixing with the polymer to form a solution of the polymer. Alternatively, the chelating agent stored in the chelating agent storage facility  228  may be a pre-mixed aqueous chelating agent solution, and/or the surfactant stored in the surfactant storage facility  229  may be a pre-mixed aqueous surfactant solution, and/or the polymer stored in the polymer storage facility  231  may be a pre-mixed aqueous polymer solution. 
     The ammonia liquid, chelating agent, surfactant, and polymer may be provided from the ammonia liquid storage facility  227 , the chelating agent storage facility  228 , the surfactant storage facility  229 , and the polymer storage facility  231 , respectively, to the oil recovery formulation storage facility  219  wherein the ammonia liquid, the chelating agent, the surfactant, and the polymer may be mixed and stored as the oil recovery formulation. The ammonia liquid storage facility  227  may be operatively fluidly coupled to the oil recovery formulation storage facility  219  by conduit  239 ; the chelating storage facility  228  may be fluidly operatively coupled to the oil recovery formulation storage facility by conduit  240 ; the surfactant storage facility  229  may be operatively fluidly coupled to the oil recovery formulation storage facility by conduit  241 ; and the polymer storage facility  231  may be operatively fluidly coupled to the oil recovery formulation storage facility by conduit  243 . Water for the oil recovery formulation, if necessary, may be provided from source water treated in the water treatment facility  233 , wherein the water treatment facility may be operatively fluidly coupled to the oil recovery formulation storage facility  219  by conduit  245 . 
     The oil recovery formulation may be provided from the oil recovery formulation storage facility  219  to the first injection/production facility  221  or to the first well  201  for injection into the formation  205  as described above. 
     Alternatively, the ammonia liquid, the chelating agent, the surfactant, and the polymer may be provided separately from the ammonia liquid storage facility  227 , the chelating agent storage facility  228 , the surfactant storage facility  229 , and the polymer storage facility  231 , respectively, to the first injection/production facility  221  or to the first well  201  for injection into the formation  205 . The ammonia liquid storage facility  227  may be fluidly operatively coupled to the first injection/production facility  221  or the first well  201  by conduit  247 ; the chelating agent storage facility  228  may be fluidly operatively coupled to the first injection/production facility or the first well by conduit  248 , the surfactant storage facility  229  may be fluidly operatively coupled to the first injection/production facility or the first well by conduit  249 ; and the polymer storage facility  231  may be fluidly operatively coupled to the first injection/production facility or the first well by conduit  251 . Ammonia liquid, one or more chelating agents, one or more surfactants, and/or one or more polymers, and optionally water, may be provided separately to the first injection/production facility  221  or the first well  201  and may be mixed in the first injection/production facility or the first well to form the oil recovery formulation for injection into the formation. Alternatively the ammonia liquid, one or more chelating agents, one or more surfactants, one or more polymers, and optionally additional water, may be injected into the formation  205  via the first well  201  separately or in a combination that does not form the complete oil recovery formulation, and the ammonia liquid, one or more chelating agents, one or more surfactants, one or more polymers, and optionally water, may be mixed to form the oil recovery formulation within the formation, where the oil recovery formulation formed within the formation may then be contacted with oil in the formation to mobilize the oil for production from the formation. 
     Referring now to both  FIGS. 1 and 2 , the oil recovery formulation may be introduced into the formation  205 , for example by injecting the oil recovery formulation into the formation through the first well  201  by pumping the oil recovery formulation through the first well and into the formation, or by pumping the components of the oil recovery formulation through the first well into the formation for mixing within the formation to form the oil recovery formulation in situ. The pressure at which the oil recovery formulation or the components of the oil recovery formulation is/are introduced into the formation may range from the instantaneous pressure in the formation up to, but not including, the fracture pressure of the formation. The pressure at which the oil recovery formulation or its components may be injected into the formation may range from 5% to 95%, or from 40% to 90%, of the fracture pressure of the formation. Alternatively, the oil recovery formulation or its components may be injected into the formation at a pressure equal to, or greater than, the fracture pressure of the formation. 
     The volume of oil recovery formulation or combined components of the oil recovery formulation introduced into the formation  205  via the first well  201  may range from 0.001 to 5 pore volumes, or from 0.01 to 2 pore volumes, or from 0.1 to 1 pore volumes, or from 0.2 to 0.6 pore volumes, where the term “pore volume” refers to the volume of the formation that may be swept by the oil recovery formulation or combined components of the oil recovery formulation between the first well  201  and the second well  203 . The pore volume may be readily be determined by methods known to a person skilled in the art, for example by modeling studies or by injecting water having a tracer contained therein through the formation  205  from the first well  201  to the second well  203 . 
     As the oil recovery formulation is introduced into the formation  205  or as the components of the oil recovery formulation are individually introduced into the formation and mixed therein to form the oil recovery formulation, the oil recovery formulation spreads into the formation as shown by arrows  253 . Upon introduction to the formation  205  or upon mixing of components of the oil recovery formulation in the formation to form the oil recovery formulation, the oil recovery formulation contacts and forms a mixture with a portion of the oil in the formation. The oil recovery formulation may mobilize the oil in the formation upon contacting and mixing with the oil and water in the formation. The oil recovery formulation may mobilize the oil in the formation upon contacting and mixing with the oil, for example, by reducing capillary forces retaining the oil in pores in the formation, by reducing the wettability of the oil on pore surfaces in the formation, by reducing the interfacial tension between oil and water in the formation, and/or by forming a microemulsion with oil and water in the formation. 
     The mobilized mixture of the oil recovery formulation and oil and water may be pushed across the formation  205  from the first well  201  to the second well  203  by further introduction of more oil recovery formulation or components of the oil recovery formulation into the formation. The oil recovery formulation may be designed to displace the mobilized mixture of the oil recovery formulation and oil through the formation  205  for production at the second well  203 . As described above, the oil recovery formulation contains a polymer, wherein the oil recovery formulation comprising the polymer may be designed to have a viscosity on the same order of magnitude as the viscosity of the oil in the formation under formation temperature conditions, so the oil recovery formulation may drive the mobilized mixture of oil recovery formulation, oil, and water across the formation while inhibiting fingering of the mixture of mobilized oil and oil recovery formulation through the driving plug of oil recovery formulation and inhibiting fingering of the driving plug of oil recovery formulation through the mixture of mobilized oil and oil recovery formulation. 
     Oil may be mobilized for production from the formation  205  via the second well  203  by introduction of the oil recovery formulation and/or its components into the formation, where the mobilized oil is driven through the formation for production from the second well as indicated by arrows  255  by introduction of the oil recovery formulation or components of the oil recovery formulation into the formation via the first well  201 . The oil mobilized for production from the formation  205  may include the mobilized oil/oil recovery formulation mixture. Water and/or gas may also be mobilized for production from the formation  205  via the second well  203  by introduction of the oil recovery formulation or its components into the formation via the first well  201 . 
     After introduction of the oil recovery formulation into the formation  205  via the first well  201 , oil may be recovered and produced from the formation via the second well  203 . A mechanism may be located at the second well for recovering and producing the oil from the formation  205  subsequent to introduction of the oil recovery formulation or the components of the oil recovery formulation into the formation, and may include a mechanism located at the second well for recovering and producing the oil recovery formulation, water, and/or gas from the formation subsequent to introduction of the oil recovery formulation into the formation. The mechanism located at the second well  203  for recovering and producing the oil, and optionally for recovering and producing the oil recovery formulation, water, and/or gas may be comprised of a pump  257 , which may be located in a second injection/production facility  259  and/or within the second well  203 . The pump  257  may draw the oil, and optionally the oil recovery formulation, water, and/or gas from the formation  205  through perforations in the second well  203  to deliver the oil, and optionally the oil recovery formulation, water, and/or gas, to the second injection/production facility  259 . 
     Alternatively, the mechanism for recovering and producing the oil—and optionally the oil recovery formulation, water, and/or gas—from the formation  205  may be comprised of a compressor  261  that may be located in the second injection/production facility  259 . The compressor  261  may be fluidly operatively coupled to a gas storage tank  263  via conduit  265 , and may compress gas from the gas storage tank for injection into the formation  205  through the second well  203 . The compressor may compress the gas to a pressure sufficient to drive production of oil—and optionally the oil recovery formulation, water, and/or gas—from the formation via the second well  203 , where the appropriate pressure may be determined by conventional methods known to those skilled in the art. The compressed gas may be injected into the formation from a different position on the second well  203  than the well position at which the oil—and optionally the oil recovery formulation, water, and/or gas—are produced from the formation, for example, the compressed gas may be injected into the formation at formation portion  207  while oil, oil recovery formulation, water, and/or gas are produced from the formation at formation portion  209 . 
     Oil, optionally in a mixture with the oil recovery formulation, water, and/or gas may be drawn from the formation  205  as shown by arrows  255  and produced up the second well  203  to the second injection/production facility  259 . The oil may be separated from the oil recovery formulation, water, and/or gas in a separation unit  267  located in the second injection/production facility  259  and operatively fluidly coupled to the mechanism  257  for producing oil and, optionally, the oil recovery formulation, water, and/or gas, from the formation. The separation unit  267  may be comprised of a conventional liquid-gas separator for separating gas from the oil, oil recovery formulation, and water; and a conventional hydrocarbon-water separator including a demulsification unit for separating the oil from water and water soluble components of the oil recovery formulation. 
     The separated produced oil may be provided from the separation unit  267  of the second injection/production facility  259  to an oil storage tank  269 , which may be fluidly operatively coupled to the separation unit  267  of the second injection/production facility by conduit  271 . The separated gas, if any, may be provided from the separation unit  267  of the second injection/production facility  259  to the gas storage tank  263 , which may be fluidly operatively coupled to the separation unit  267  of the second injection/production facility  259  by conduit  273 . 
     In an embodiment of a process of the present invention, the first well  201  may be used for injecting the oil recovery formulation and/or its components into the formation  205  and the second well  203  may be used to produce oil from the formation as described above for a first time period, and the second well  203  may be used for injecting the oil recovery formulation and/or its components into the formation  205  to mobilize the oil in the formation and drive the mobilized oil across the formation to the first well and the first well  201  may be used to produce oil from the formation for a second time period, where the second time period is subsequent to the first time period. The second injection/production facility  259  may comprise a mechanism such as pump  275  that may be fluidly operatively coupled the oil recovery formulation storage facility  219  by conduit  277 , and that is fluidly operatively coupled to the second well  203  to introduce the oil recovery formulation into the formation  205  via the second well. Alternatively, as shown in  FIG. 2 , the mechanism  275  may be fluidly operatively coupled to: the ammonia liquid storage facility  227  via conduit  279 ; the chelating agent storage facility  228  via conduit  280 ; the surfactant storage facility  229  via conduit  281 ; and the polymer storage facility  231  by conduit  283  for introduction of the components of the oil recovery formulation into the formation via the second well  203 . Referring again to  FIGS. 1 and 2 , the first injection/production facility  221  may comprise a mechanism such as pump  285 , or compressor  287  fluidly operatively coupled to the gas storage tank  263  by conduit  289 , for production of oil, and optionally the oil recovery formulation, water, and/or gas from the formation  205  via the first well  201 . The first injection/production facility  221  may also include a separation unit  291  for separating produced oil, oil recovery formulation, water, and/or gas. The separation unit  291  may be comprised of a conventional liquid-gas separator for separating gas from the produced oil and water; and a conventional hydrocarbon-water separator for separating the produced oil from water and water soluble components of the oil recovery formulation, where the hydrocarbon-water separator may comprise a demulsifier. The separation unit  291  may be fluidly operatively coupled to: the oil storage tank  269  by conduit  293  for storage of produced oil in the oil storage tank; and the gas storage tank  263  by conduit  295  for storage of produced gas in the gas storage tank. 
     The first well  201  may be used for introducing the oil recovery formulation or the components of the oil recovery formulation into the formation  205  and the second well  203  may be used for producing oil from the formation for a first time period; then the second well  203  may be used for introducing the oil recovery formulation or components of the oil recovery formulation into the formation  205  and the first well  201  may be used for producing oil from the formation for a second time period; where the first and second time periods comprise a cycle. Multiple cycles may be conducted which include alternating the first well  201  and the second well  203  between introducing the oil recovery formulation or its components into the formation  205  and producing oil from the formation, where one well is introducing and the other is producing for the first time period, and then they are switched for a second time period. A cycle may be from about 12 hours to about 1 year, or from about 3 days to about 6 months, or from about 5 days to about 3 months. 
     Referring now to  FIG. 3 , an array of wells  300  is illustrated. Array  300  includes a first well group  302  (denoted by horizontal lines) and a second well group  304  (denoted by diagonal lines). In some embodiments of the process of the present invention, the first well described above may include multiple first wells depicted as the first well group  302  in the array  300 , and the second well described above may include multiple second wells depicted as the second well group  304  in the array  300 . 
     Each well in the first well group  302  may be a horizontal distance  330  from an adjacent well in the first well group  302 . The horizontal distance  330  may be from about 5 to about 5000 meters, or from about 10 to about 1000 meters, or from about 20 to about 500 meters, or from about 30 to about 250 meters, or from about 50 to about 200 meters, or from about 90 to about 150 meters, or about 100 meters. Each well in the first well group  302  may be a vertical distance  332  from an adjacent well in the first well group  302 . The vertical distance  332  may be from about 5 to about 5000 meters, or from about 10 to about 1000 meters, or from about 20 to about 500 meters, or from about 30 to about 250 meters, or from about 50 to about 200 meters, or from about 90 to about 150 meters, or about 100 meters. 
     Each well in the second well group  304  may be a horizontal distance  336  from an adjacent well in the second well group  304 . The horizontal distance  336  may be from 5 to 5000 meters, or from 10 to 1000 meters, or from 20 to 500 meters, or from 30 to 250 meters, or from 50 to 200 meters, or from 90 to 150 meters, or about 100 meters. Each well in the second well group  304  may be a vertical distance  338  from an adjacent well in the second well group  304 . The vertical distance  338  may be from 5 to 5000 meters, or from 10 to about 1000 meters, or from 20 to 500 meters, or from 30 to 250 meters, or from 50 to 200 meters, or from 90 to 150 meters, or about 100 meters. 
     Each well in the first well group  302  may be a distance  334  from the adjacent wells in the second well group  304 . Each well in the second well group  304  may be a distance  334  from the adjacent wells in first well group  302 . The distance  334  may be from 5 to 5000 meters, or from 10 to 1000 meters, or from 20 to 500 meters, or from 30 to 250 meters, or from 50 to 200 meters, or from 90 to 150 meters, or about 100 meters. 
     Each well in the first well group  302  may be surrounded by four wells in the second well group  304 . Each well in the second well group  304  may be surrounded by four wells in the first well group  302 . 
     In some embodiments, the array of wells  300  may have from 10 to 1000 wells, for example from 5 to 500 wells in the first well group  302 , and from 5 to 500 wells in the second well group  304 . 
     In some embodiments, the array of wells  300  may be seen as a top view with first well group  302  and the second well group  304  being vertical wells spaced on a piece of land. In some embodiments, the array of wells  300  may be seen as a cross-sectional side view of the formation with the first well group  302  and the second well group  304  being horizontal wells spaced within the formation. 
     Referring now to  FIG. 4 , an array of wells  400  is illustrated. Array  400  includes a first well group  402  (denoted by horizontal lines) and a second well group  404  (denoted by diagonal lines). The array  400  may be an array of wells as described above with respect to array  300  in  FIG. 3 . In some embodiments of the process of the present invention, the first well described above may include multiple first wells depicted as the first well group  402  in the array  400 , and the second well described above may include multiple second wells depicted as the second well group  404  in the array  400 . 
     The oil recovery formulation or components thereof may be injected into first well group  402  and oil may be recovered and produced from the second well group  404 . As illustrated, the oil recovery formulation may have an injection profile  406 , and oil may be produced from the second well group  404  having a oil recovery profile  408 . 
     The oil recovery formulation or components thereof may be injected into the second well group  404  and oil may be produced from the first well group  402 . As illustrated, the oil recovery formulation may have an injection profile  408 , and oil may be produced from the first well group  402  having an oil recovery profile  406 . 
     The first well group  402  may be used for injecting the oil recovery formulation or components thereof and the second well group  404  may be used for producing oil from the formation for a first time period; then second well group  404  may be used for injecting the oil recovery formulation or components thereof and the first well group  402  may be used for producing oil from the formation for a second time period, where the first and second time periods comprise a cycle. In some embodiments, multiple cycles may be conducted which include alternating first and second well groups  402  and  404  between injecting the oil recovery formulation or components thereof and producing oil from the formation, where one well group is injecting and the other is producing for a first time period, and then they are switched for a second time period. 
     To facilitate a better understanding of the present invention, the following examples of certain aspects of some embodiments are given. In no way should the following examples be read to limit, or define, the scope of the invention. 
     Example 
     An oil recovery flood utilizing an oil recovery composition comprising ammonia as the alkaline agent was performed. An experiment was conducted to determine the effect of utilizing an ammonia-surfactant-polymer formulation on residual oil recovery from a formation. A sandpack was prepared by packing 80 to 120 mesh sand in a two inch diameter glass cylinder. The sandpack was then put under vacuum and flooded with a synthetic reservoir brine solution. The sandpack was then positioned vertically in an oven at 69° C., and saturated with a low viscosity (1.2 mPa s at 69° C.) crude oil from the top of the sandpack until no more water was produced upon further introduction of oil to the sandpack. To simulate water flood production of oil from the sandpack, the sandpack was then flooded with the synthetic brine solution from the bottom of the sandpack at a rate of LU meter/day until no more oil was produced from the sandpack. By these techniques both oil saturation and waterflood are stabilized by gravity as the less dense fluid is injected from the top of the sandpack and the more dense fluid is injected from the bottom. The amount of residual oil remaining in the sandpack after the waterflood (Sor) was calculated by subtracting the amount of oil recovered as a result of the waterflood from the total amount of oil absorbed by the sandpack during saturation of the sandpack with oil. 
     Oil recovery resulting from an ammonia-surfactant-polymer flood was then determined. An ammonia-surfactant-polymer brine solution was prepared containing 1 wt. % NH 4 OH, 0.8 wt. % IOS2024 as the surfactant (C20 to 24 internal olefin sulfonate), 250 ppm FLOPAAM™ 3130 (a copolymer of 30% acrylic acid and 70% acrylamide, nominally 5 million molecular weight), and 1 wt. % NaCl. To determine the oil recovery resulting from an ammonia-surfactant-polymer flood after the waterflood, the sandpack was flooded with 0.3 pore volumes of the ammonia-surfactant-polymer brine solution at a flow rate of 1 foot/day followed by 1.2 pore volumes of 250 ppm FLOPAAM™ 3130 in 1% NaCl to produce further oil from the residual oil remaining in the sandpack. The oil production of the residual oil (S OR ) was measured as a function of the pore volumes of the ammonia-surfactant-polymer brine solution introduced to the sandpack. Introduction of 0.3 pore volumes of ammonia-surfactant-polymer brine solution and 1.2 pore volumes of polymer solution to the sandpack provided approximately 87% recovery of the residual oil in the sandpack. 
     The present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. While systems and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from a to b,” or, equivalently, “from a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Whenever a numerical range having a specific lower limit only, a specific upper limit only, or a specific upper limit and a specific lower limit is disclosed, the range also includes any numerical value “about” the specified lower limit and/or the specified upper limit. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an”, as used in the claims, are defined herein to mean one or more than one of the element that it introduces.