Abstract:
A process for recovering heavy oil with the steps of: a) injecting into one or more injection wells an aqueous injection fluid containing one or more surfactants designed to form a pseudo-emulsion between the injection fluid and the heavy oil, and, b) recovering the oil from one or more producing wells. The process does not require the addition of outside mechanical or thermal energy or solvents to recover the heavy oil and does not form emulsions between the injection fluid and the heavy oil that may be difficult to break when brought to the surface or may cause increased viscosity and injectivity problems within the reservoir.

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
       [0001]    This application is based on provisional application Ser. No. 60/925,713, filed on Apr. 23, 2007. 
     
    
     STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT 
       [0002]    Not Applicable 
       DESCRIPTION OF ATTACHED APPENDIX 
       [0003]    Not Applicable 
       BACKGROUND OF THE INVENTION 
       [0004]    This invention relates generally to the field of enhanced oil recovery and more specifically to a process for recovering heavy oil using surfactants without the need for mechanical or thermal external energy sources. 
         [0005]    The present invention relates to compositions and a process for the recovery of oil from subterranean oil bearing reservoirs, and more particularly the present invention is to improve the heavy oil recovery from a subterranean oil bearing formation involving the injection of an aqueous injection fluid containing one or more surfactants that provide low interfacial tensions, wettability alteration, foaming properties and most importantly forms a water external pseudo-emulsion to reduce the viscosity of the heavy oil without the need for external sources of energy such as thermal, solvents or by mechanical means. 
         [0006]    In the recovery of oil from subterranean reservoirs it usually is possible to recover approximately 15%-20% of the original oil in place by primary recovery. Secondary recovery methods such as well stimulation or water flooding are applied after the amount of oil recovered by primary recovery becomes uneconomical. Secondary recovery methods can recover approximately an additional 15%-30% of the original oil in place which leaves the reminder of the oil unrecoverable unless other means such as tertiary recovery processes are applied. These tertiary recovery methods include but are not limited to the use of miscible and immiscible gases and liquids, steam, foam, alkali, surfactants, and polymers. However, the heavy oil recovery is often restricted even from the primary recovery stage due to the high viscosity and poor mobility of the heavy crude oil. Furthermore, the value of the heavy crude is not as high as the lighter crude oil. Steam flood is often used, however, the steam generation is costly, and steam quickly losses temperature to the formation and the recovery area and efficiency is limited. How to economically recover the heavy oil is a challenge for the oil industry. 
         [0007]    It has been known that many factors, including but not limited to the interfacial tension between the injection brine and the residual oil, the relative mobility of the injected brine, and the wettability characteristics of the rock surfaces comprising the reservoir are all important in determining the amount of oil recovered by tertiary recovery. Numerous studies have found that the addition of surfactants to the injection brine can alter the interfacial and wetting properties to help overcome the high capillary pressure and increase the oil recovery. In many cases the addition of a polymer along with the surfactant or immediately after the surfactant can increase the mobility ratio between the injected brine and oil thus further improving the sweep efficiency of the flood. 
         [0008]    Heavy crude oil reservoirs are generally more difficult to develop than reservoirs of lighter crude oil. Heavy petroleum deposits contain crude oil of relatively high density. The density of a crude oil is generally represented by its API gravity—defined by the American Petroleum Institute (API). API Gravity in Degrees=[141.5/specific gravity]−131.5, where the specific gravity is measured at 60° F. Crude oil produced from heavy crude oil deposits generally have an average API gravity of 25 or less; from medium deposits, 30 or less. API gravity is inversely proportional to density: the higher the API gravity, the lower the density. Higher density is generally associated with higher viscosity, i.e., greater resistance to flow. Heavier crude oil deposits, having high viscosity, do not flow readily and are difficult to develop. This raises production costs. 
         [0009]    Economic recovery of the heavy oil is a challenge. Crude oil is held in a reservoir by viscous forces (resistance to flow) and capillary forces. Viscous forces predominate in heavy oil reservoirs. Heavy oil reservoir enhanced recovery processes generally focus on reducing viscosity to improve oil mobility. This is usually accomplished by providing a source of external energy such as heating the oil or subjecting it to mechanical stimulation. Adding light oil such as condensate to reduce the viscosity of the heavy crude, or using carbon dioxide is also used. However, these processes are relatively expensive and the sources are not always available. 
         [0010]    Hot water flooding is an enhanced recovery process that uses heat to improve conventional water flooding. The higher temperature lowers the viscosity of the heavy oil; the oil then flows more easily to the production well. Hot water loses its heat when traveling through the reservoir and it is generally inefficient and unpopular. Steam flooding is another recovery process that is used to improve conventional flooding. But steam flooding is not suitable for some heavy oil reservoirs, e.g., where: (1) the heavy oil is of very high viscosity, (2) the reservoir is at too high a pressure to develop a steam gas phase, or (3) the formation of a steam chest is undesirable for environmental reasons. This has made the process less popular for oil recovery. 
         [0011]    U.S. Pat. No. 4,629,000 discloses injecting a slug containing an oil-soluble alcohol of 5 to 7 carbon atoms and an oil-soluble sulfate or sulfonate surfactant. This process seeks to improve recovery efficiency by lowering capillary forces. Solvent is injected into a reservoir as a slug—a discrete volume of fluid of composition different from the injection fluid. The solvent slug mixes with water and oil and displaces both. This process uses solvents mutually soluble in water and oil to effect a miscible to nearly-miscible type displacement process in light to medium oil reservoirs (&gt;25° API). 
         [0012]    U.S. Pat. No. 3,608,638 discloses a method to enhance oil recovery from tar sands using hot hydrocarbon solvents. The solvents are injected at temperatures between 300° F. and 700° F. Preferred solvents are aromatic hydrocarbons. U.S. Pat. No. 4,004,636 and U.S. Pat. No. 4,109,720 disclose petroleum recovery methods using multiple-component solvent injection. 
         [0013]    Laboratory studies performed using the methods described above showed that oil recoveries declined as the oil gravity decreased and viscosity increased. In addition, the injection of certain solvents may cause precipitation of asphaltenes that are solubilized by the heavier hydrocarbons. This suggests that these processes are not suitable for heavy oil recovery. Additionally, solvent injection processes are costly, since large amounts of relatively expensive solvent are consumed. 
         [0014]    U.S. Pat. No. 3,977,471 discloses an oil recovery method using an injection fluid containing brine, a sulfonate surfactant, and an alcohol co-surfactant to improve surface activity in high salinity brine for applications with reservoir temperature less than 120° F. The process is not carried out at elevated temperature, since the surfactants lose surface activity under reservoir conditions of high temperature. The process uses alcohols as co-surfactants. U.S. Pat. No. 4,018,278 addresses the problem of temperature instability of salts of polyethoxylated alcohols, polyethoxylated alkylphenols and alkylphenol sulfates, and the problem of poor performance of alkyl and alkylaryl sulfonates in water of high salinity, by using sulfonated, ethoxylated alcohols or alkylphenols having alkyl or alkylaryl groups of 8 to 20 carbons. These processes differ from the present invention in that no attempt is made to prevent emulsion formation between the recovered oil and the injection fluid. Emulsions formed, especially between an aqueous phase and a heavy oil are particularly difficult to break once the emulsions is recovered at the surface. In most cases treatment with heat and chemical demulsifiers is required. In addition emulsions formed downhole serve to increase viscosities and may decrease injectivity and form emulsion blocks within the reservoir making it difficult and sometimes impossible to recover the oil. 
         [0015]    U.S. Pat. No. 4,556,107 and U.S. Pat. No. 4,607,700 disclose the use of dimerized alpha-olefin sulfonates as steam diverting agents to improve mobility by foaming. U.S. Pat. No. 4,743,385 uses an anionic surfactant and a hydrotrope to recover heavy oil with steam. U.S. Pat. No. 4,577,688 uses surfactants, especially alcohol ether sulfonates along with a non-condensable gas as steam diverting agents. 
         [0016]    Carbon dioxide flooding is another conventional process for improved crude oil recovery. U.S. Pat. No. 4,899,817 discloses the use of alcohol in solvent flooding by carbon dioxide. U.S. Pat. No. 5,333,687 discloses carbon dioxide flooding with a surfactant foaming agent and alcohols of 8 to 20 carbons. 
         [0017]    Among the mechanical methods to recover heavy oil, U.S. Pat. No. 6,841,141 discloses a method of fracturing the reservoir and applying vibrational energy to improve oil recovery performance of various recovery techniques such as gravity-assisted drainage, vapor-extraction gravity drainage, or cyclic steam injection. This method also involves the use of expensive equipment and additional costly processes such as fracturing. 
         [0018]    Therefore, there is a need in the art for an effective, higher temperature stable, salt tolerant and lower cost process that improves the efficiency of heavy oil recovery. The present invention, for which a full description is presented below, provides a new composition and process using one or more surfactant to form water external pseudo-emulsion to effectively lower the viscosity and recover the heavy oil without the disadvantages that are described in the prior art above. 
       BRIEF SUMMARY AND OBJECT OF THE INVENTION 
       [0019]    The primary object of the invention is to provide compositions and process that is effective in the recovery of heavy oil from subterranean reservoirs without forming troublesome emulsions and without the need to provide external mechanical and thermal sources of energy. 
         [0020]    Another object of the invention is to provide compositions and process that can be used over a wide range of temperatures, salinities, and water hardness levels. 
         [0021]    A further object of the invention is to provide compositions and a process that reduces the interfacial tension between the injection fluid and the oil within the reservoir and changes the wettability to help overcome the capillary forces trapping the oil within the microscopic pores of the reservoir rock. 
         [0022]    Yet another object of the invention is to provide a composition and a process that can reduce the viscosity of the heavy oil by forming a water external pseudo-emulsion without forming stable emulsions. 
         [0023]    Other objects and advantages of the present invention will become apparent from the following descriptions, taken in connection with the accompanying drawings, wherein, by way of illustration and example, an embodiment of the present invention is disclosed. 
     
    
     DETAILED DESCRIPTION OF THE INVENTION 
       [0024]    Detailed descriptions of the preferred embodiment are provided herein. It is to be understood, however, that the present invention may be embodied in various forms. Therefore, specific details disclosed herein are not to be interpreted as limiting, but rather as a basis for the claims and as a representative basis for teaching one skilled in the art to employ the present invention in virtually any appropriately detailed system, structure or manner. 
         [0025]    The present invention of the process of recovering heavy oil from a subterranean reservoir involves a process for recovering heavy oil by a) injecting an aqueous injection fluid containing one or more surfactants into one or more injection wells to form a low viscosity water external pseudo-emulsion when contacting the heavy oil; and b) recovering the oil from one or more producing wells. The injection well and the producing well may be the same. 
         [0026]    The surfactant(s) used in the process of recovering oil may be a single surfactant or a mixture of two or more surfactants that provide the necessary properties of forming a water external pseudo-emulsion for lowering the viscosity of the heavy oil. The surfactant may also provides the properties of lowering IFT, changing wettability of the reservoir, and dispersing the oil without the formation of emulsion and without the need for heat or mechanical stimulation. 
         [0027]    The aqueous injection fluid of the present invention may contain, in addition to the surfactant(s), one or more from the group: viscosifiers for mobility control, alkalis for reducing adsorption, co-surfactants for improved interfacial tension lowering, co-solvents for improved handling and freeze-thaw stability. 
         [0028]    The choice of surfactants and its concentration in the formulation is determined by the properties of the injection brine, the connate brine, the reservoir characteristics, the oil properties and the injection design. The concentration of the total surfactants is generally between 0.025 and 5.0 wt % and usually between 0.05 and 1.0 wt %. The actual concentration is determined by the amount necessary to give the desired properties without forming stable emulsions between the aqueous injection fluid and the crude oil to be recovered. 
         [0029]    Any nonionic or anionic surfactant or mixtures of nonionic and anionic surfactants may be used if they satisfy the condition of forming a pseudo-emulsion when an aqueous solution of the surfactants comes in contact with a heavy oil. For the purposes of this invention, a pseudo-emulsion is defined as a two phase water external mixture of an oil and an aqueous liquid where the oil is suspended in the aqueous phase as a fine dispersion that is easily transported but that separates into the individual aqueous and oil phases when the mixture is allowed to stand for a short period of time without agitation. 
         [0030]    Non-exclusive examples of surfactants that have been found to form pseudo-emulsions between the crude oil and aqueous injection fluid include alkoxylated phenol, alkoxylated alkylphenols, alkoxylated linear or branched alcohols, alkoxylated fatty acids, alkoxylated sorbitol esters, Also, the phosphate, sulfonate, and sulfate alkali metal salts of alkoxylated phenol, alkoxylated alkylphenols, alkoxylated linear or branched alcohols. Also, alkali metal salts of branched or linear alkylaryl sulfonates, branched or linear alkyl ether sulfonates, branched or linear internal olefin sulfonates, branched or linear alpha olefin sulfonates. 
         [0031]    We have also found that the desired properties to achieve the formation of a pseudo-emulsion may be obtained by using a single surfactant with the properties of a non-ionic and an anionic surfactant combined within the same molecule. This offers the additional advantage of eliminating the possibility of chromatographic separation as the surfactant propagates through the reservoir. 
         [0032]    One example of surfactant of this type that may be used in the present invention is shown below. 
         [0000]      R 1 [—(O—(R 2 O) m —(R 3 O) n —(R 4 )] y    
         [0000]    where:
 
R 1 =alkyl, alkenyl, amine, alkylamine, dialkylamine, trialkylamine, aromatic, polyaromatic, cycloalkane, cycloalkene,
 
       R 2 =C 2 H 4  or C 3 H 6  or C 4 H 
     R 3 =C 2 H 4  or C 3 H 6  or C 4 H 8 , 
       [0033]    R 4 =linear or branched C 7 H 14 SO 3 X to C 30 H 60 SO 3 X when y=1,
 
R 4 =linear or branched C 7 H 14 SO 3 X to C 30 H 60 SO 3 X or H when y&gt;1 but at least one R 4  must be linear or branched C 7 H 14 SO 3 X to C 30 H 60  SO 3 X,
       m≧1,   n≧0,   n+m=1 to 30+,   y≧1,   X=alkali metal or alkaline earth metal or ammonium or amine.       
 
         [0039]    The degree of alkoxylation, the type of alkoxylate and the length of the alkyl group are determined by the properties of the produced fluid, the brine/oil ratio, the produced brine composition, and the bottom hole temperature. 
         [0040]    Another example of a surfactant class that may be used is shown below. 
         [0000]    
       
                 
         
             
             
         
       
     
         [0000]    where m+n=5-28 
       M=H, Na, K, NH 3 , Amine, Ca, Mg, 
     Y=H or COOM or PO 3 M 
     X=H, CH 3  or CH 2 CH 3    
       [0041]    x=1-30 or more 
         [0042]    Another example of a surfactant that may be used with the present invention is shown as structures I and II. 
         [0000]    
       
                 
         
             
             
         
       
     
         [0000]    where;
 
M is Na, K, NH 3 , Ca, Mg, or an amine
 
a=0 to 20
 
b=0 to 20
 
x+y+z=5 to 19
 
         [0043]    The degree of alkoxylation, the type of alkoxylate and the length of the alkyl group are determined by the properties of the produced fluid, the brine/oil ratio, the produced brine composition, and the bottom hole temperature. 
         [0044]    The type of surfactant illustrated above offers several advantages. They are easily manufactured from readily available raw materials as described in U.S. Pat. No. 6,043,391 and U.S. Pat. No. 6,736,211. They contain both anionic and nonionic properties in the same molecule and therefore not subject to chromatographic separation when propagating through the reservoir. They are very salt tolerant and thermally stable and therefore can be used at temperatures up to 250° F. and salinity above 20 wt % with total hardness of 4 wt %. 
         [0045]    In any case the surfactant(s) is used along with a suitable solvent, including, but not limited to, water, alcohol, or alcohol ether. Other additives that are known to impart certain desirable features to the composition, as is known to the art, may be added. These include viscosifiers, alkalis, co-surfactants, and co-solvents. 
       EXAMPLE 1 
       [0046]    This example demonstrates the effectiveness of the present invention in reducing the heavy oil viscosity using a combination of an anionic surfactant and a nonionic surfactant. 
         [0047]    The total dissolved solids of the brine is 183,000 ppm, testing temperature is 25° C. Oil viscosity is 6,700 cps. 0.1 wt % of the following surfactant formulation is used as shown below: 
         [0000]    30 wt % of the phenol+7 EO
 
30 wt % of C1517 alcohol ether sulfate
 
40 wt % water
 
       Sample Preparation: 
       [0048]    20 wt % of the heavy oil was added to the brine with and without the surfactant, each in a 4 ounce, capped glass jar. Sample A in Table 1 is the control without surfactant. Sample B contains 0.1 wt % of the above formulation: 
         [0000]    
       
         
               
             
               
               
               
             
           
               
                 TABLE 1 
               
             
             
               
                   
               
               
                 Heavy oil pseudo-emulsion formation 
               
             
          
           
               
                 Description 
                 Sample A 
                 Sample B 
               
               
                   
               
               
                 Appearance after 
                 The oil floats on top 
                 The heavy oil breaks into fine 
               
               
                 shaking the jar 
                 of the brine as a 
                 particles and is dispersed in 
               
               
                   
                 solid lump 
                 the brine 
               
               
                 Appearance after 
                 The oil float on top 
                 The oil droplets separate from 
               
               
                 aging the above 
                 of the brine as a 
                 the brine and floats to the top. 
               
               
                 solution for 10 
                 solid lump 
                 The oil droplet remain water 
               
               
                 minutes 
                   
                 wet with low viscosity 
               
               
                 Oil Viscosity, cps 
                 6,700 cps 
                 125 cps 
               
               
                   
               
             
          
         
       
     
         [0049]    The data above shows that a low concentration of the surfactant can alter the oil surface and create a water external pseudo-emulsion. The viscosity of the water external pseudo-emulsion is much lower than the original oil viscosity, thus, it is much easier to remove it from the reservoir. The water external pseudo-emulsion is easily separated upon standing and will not cause any emulsion separation problems. 
       EXAMPLE 2 
       [0050]    This example demonstrates the effectiveness of the above formation on the oil recovery. Two sand columns are prepared and saturated with the heavy oil. 0.3 pore volume of the fluid was injected through each of the sand column at ambient temperature to compare the oil recovered. 
         [0000]    
       
         
               
             
               
               
               
             
               
               
               
               
             
           
               
                 TABLE 2 
               
             
             
               
                   
               
               
                 Oil recovery in the lab sand column test 
               
             
          
           
               
                   
                   
                 0.1% of the surfactant 
               
               
                   
                   
                 formulation as shown in 
               
               
                   
                 Control - no surfactant 
                 Example 1 
               
               
                   
                   
               
             
          
           
               
                   
                 Oil Recovered 
                 0.02% 
                 6.4% 
               
               
                   
                   
               
             
          
         
       
     
         [0051]    The data in Table 2 above shows that the heavy oil cannot be recovered by injecting water only. 0.1% surfactant can easily remove 6.4% of the heavy oil and make the process very economical. 
       EXAMPLE 3 
       [0052]    This example demonstrates the effectiveness of the present invention in recovering heavy oil using a single surfactant that comprises both anionic and nonionic groups. The viscosity of the crude oil is 31,000 cps and the bottom hole temperature of 185° F. 
         [0053]    A 400 m 3  slug of aqueous injection fluid containing 0.1 wt % of a surfactant having the structure below was injected into a well an allowed to remain 48 hours after which the well was allowed to flowback and the recovered oil measured. Table 3 compares the results before and after treatment with the surfactant. 
         [0000]    
       
                 
         
             
             
         
       
     
         [0000]    where x=6 
       Y=H 
     X=H 
     M=Na 
       [0054]    m=0
 
n=12-14
 
         [0000]    
       
         
               
             
               
               
               
             
               
               
               
             
           
               
                 TABLE 3 
               
             
             
               
                   
               
               
                 Field pilot test result 
               
             
          
           
               
                   
                 Before Treatment 
                 After Treatment 
               
               
                   
                   
               
             
          
           
               
                 Oil Production, MT/day 
                 1.2 
                 8.9 
               
               
                 Water Cut, % 
                 60 
                 30 
               
               
                   
               
             
          
         
       
     
         [0055]    While the invention has been described in connection with a preferred embodiment, it is not intended to limit the scope of the invention to the particular form set forth, but on the contrary, it is intended to cover such alternatives, modifications, and equivalents as may be included within the spirit and scope of the invention as defined by the appended claims.