Patent Publication Number: US-7591311-B2

Title: Process for recovering heavy oil

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
   This application claims priority under 35 U.S.C. § 119(e) from the following U.S. provisional application: Application Ser. No. 60/888,977 filed on Feb. 9, 2007. That application is incorporated in its entirety by reference herein. 

   BACKGROUND 
   Conventional, oil recovery involves drilling a well and pumping a mixture of oil and water from the well. Oil is separated from the water and the water is usually injected into a sub-surface formation. Conventional recovery works well for low viscosity oil. However, conventional oil recovery processes do not work well for higher viscosity, or heavy, oil. 
   Enhanced Oil Recovery (EOR) processes employ thermal methods to improve the recovery of heavy oils from sub-surface reservoirs. The injection of steam into heavy oil bearing formations is a widely practiced EOR method. Typically, several tonnes of steam are required for each tonne of oil recovered. Steam heats the oil in the reservoir, which reduces the viscosity of the oil and allows the oil to flow to a collection well. After the steam fully condenses and mixes with the oil the condensed steam is classified as produced water. The mixture of oil and produced water that flows to the collection well is pumped to the surface. Oil is separated from the water by conventional processes employed in conventional oil recovery operations. 
   For economic and environmental reasons it is desirable to recycle the water used in steam injection EOR. This is accomplished by treating the produced water and directing the treated feedwater to a steam generator or boiler. The complete water cycle includes the steps of:
         injecting the steam into an oil bearing formation,   condensing the steam to heat the oil whereupon the condensed steam mixes with the oil to become produced water,   collecting the oil and produced water in a well,   pumping the mixture of oil and produced water to the surface,   separating the oil from the produced water,   treating the produced water so that it becomes the steam generator or boiler feedwater, and   converting the feedwater into steam, which has a quality of approximately 70% to nearly 100%, for injecting into the oil bearing formation.       

   Several treatment processes are used for converting produced water into steam generator or boiler feedwater. These processes typically remove constituents which form harmful deposits in the boiler or steam generator. These water treatment processes used in steam injection EOR typically do not remove all dissolved solids, such as sodium and chloride. 
   The type of steam generator that is most often used for steam injection EOR is a special type called the Once-Through-Steam-Generator (OTSG). The OTSG converts approximately 80% of the feedwater to steam. The remaining 20% of feedwater is discharged from the OTSG as a liquid mixed with the steam. This steam and water mixture is defined as 80% quality steam. While some OTSG designs can produce 85% or 90% quality steam and other designs are limited to 70% or 75% quality steam, it is a common feature for OTSGs used in EOR that some amount of water is required in the discharged steam to keep the entire steam generator heat transfer surface wetted. The OTSG which produces approximately 80% quality steam is appropriate for some steam injection EOR operations. First, unlike conventional industrial boilers, an OTSG can accept feedwater that has dissolved solids that are not removed by the water treatment process. These solids are flushed from the steam generator as residual dissolved solids in the 20% of feedwater that is not converted to steam. Secondly, 100% of the output from the OTSG is injected because it is acceptable to inject 80% quality steam into some heavy oil bearing formations. 
   For some EOR operations an OTSG that generates 80% quality steam is adequate. However, there are cases where generating 80% quality steam is not adequate. This is especially true for oil bearing formations where oil is bound or contained in sand deposits such as widely found in the Alberta, Canada region. In such cases, oil is typically recovered using what is referred to as a steam assisted gravity discharge (SAGD) process, and in SAGD processes, steam quality on the order of 70%-80% will not work to efficiently and effectively recover oil. 
   The SAGD process was developed for in-situ recovery of oil from oil sands deposits located in the Province of Alberta, Canada. The SAGD process requires a high quality steam. Indeed, in the past, most SAGD process have required near 100% quality steam. The requirement for such a high quality steam presents a challenge because it is not possible to produce high quality steam using a conventional OTSG. On the other hand, using a conventional industrial boiler has its drawbacks. While high quality steam can be achieved, the feedwater to such industrial boilers must be extensively treated. 
   The high quality steam required for the SAGD process is usually produced by directing 80% quality steam from the OTSG into a steam separator. The steam separator produces two streams. The first stream is a high quality steam, typically near 100% quality steam. The second stream is a liquid blowdown stream that contains the residual dissolved solids that were in the feedwater to the steam generator. This liquid blowdown stream is typically depressurized through pressure reducing stations, which might or might not include heat recovery, and then recycled to the water treatment process. 
   The liquid blowdown stream from the steam separator of a typical SAGD operation, which uses physical/chemical treatment and ion exchange for treating the produced water, is at least 20% of the feedwater flow and has been reported as high as 30%. The equipment required to process this blowdown stream represents a capital expense that provides no value in the oil recovery process. The heat recovery techniques which are employed to minimize the heat lost from the liquid blowdown stream from the separator do not recover 100% of the heat, and the liquid blowdown stream represents an operating cost that has no value in the oil recovery process. Another capital cost impact is that the water treatment system capacity must be increased by at least 25% to accommodate for the liquid blowdown stream from the steam separator. 
   An alternative for treatment of produced water that removes many of the dissolved solids is evaporation of the produced water. Distillate from the evaporator becomes the feedwater for a packaged boiler, for example. This process has the advantage of producing a higher quality feedwater for steam generation. However, even high quality distillate has some dissolved solids. These solids tend to accumulate in a packaged boiler. All packaged boilers require a blowdown stream to purge the dissolved solids that are present in the distillate. For a typical evaporator distillate of 2 ppm TDS comprised of 0.04 ppm hardness as CaCO 3  and a packaged boiler operating at 1200 psig, the solubility limits of Ca(OH) 2  and CaCO 3  requires a blowdown of approximately 5%. Typically this blowdown stream is recycled to the water treatment system. 
   An OTSG can be utilized in a heavy oil recovery process that utilizes evaporation to treat feedwater for steam generation. If an OTSG is used in such a process, the steam quality will still be substantially less than 100% and a high pressure liquid blowdown stream is still required. This is due to the fact that conventional OTSGs require water to wet the heat transfer surfaces. Therefore, when an OTSG is utilized with evaporator distillate as feedwater, a steam separator is required and that gives rise to increased capital cost and operating cost. 
   Therefore, with either an OTSG or a boiler, a pressurized blowdown waste stream is created. In order to accommodate the blowdown waste stream, equipment is required to reduce the pressure of the blowdown waste stream, recover heat from the blowdown stream, and to channel the blowdown waste stream. This increases both capital and operating costs. In addition, these blowdown waste streams carry substantial energy that is lost. Finally, in many applications, these blowdown waste streams would comprise 5% to 20% of the feedwater to the OTSG or boiler, which is recycled for treatment. This effectively reduces the capacity of the treatment facility by 5% to 20%, which of course means that to compensate for treating these blowdown waste streams, the capacity of the treatment facility must be increased by 5% to 25%. This results in additional capital outlays and ongoing operating costs. 
   SUMMARY OF THE INVENTION 
   The present invention relates to a SAGD oil recovery system and process that generates and utilizes less than 100% quality steam to recover heavy oil from oil bearing formations. In this process, steam having a quality of approximately 98% is injected into the oil bearing formation, sometimes referred to as an injection well, and the heat associated with the steam reduces the viscosity of the oil in the oil bearing formation and the oil drains into a collection well. 
   In addition, in one embodiment, the SAGD oil recovery process disclosed herein utilizes substantially all of the feedwater directed to the boiler or the OTSG for oil recovery. That is, substantially all of the feedwater entering the OTSG or boiler is directed into the injection well, in the form of steam and water, for the purpose of heating the heavy oil in the oil bearing formation around the injection well. 
   Further, in one embodiment there is provided an oil recovery process that utilizes a boiler or steam generator to generate steam that is injected into an injection well. The steam produced by the boiler or steam generator is less than 100% quality steam, typically on the order of approximately 98% quality steam. Moreover, in this process the conventional boiler or steam generator blowdown stream is eliminated or substantially eliminated. The boiler or steam generator produces a steam stream that is typically 100% quality steam or slightly less than 100% quality steam. Further, the boiler or steam generator produces water (i.e., concentrated feedwater). Some of the water produced in the boiler or steam generator is recirculated back through the boiler or steam generator. Another portion of the water is mixed with the produced steam to form a steam-water mixture that typically is approximately 98% quality steam. The steam water mixture is injected into the injection well. Solids in the boiler or steam generator are removed via the water. That is, the solids in the boiler or steam generator become entrained in the water and along with the water are mixed with the steam and hence are ultimately injected into the injection well as a part of the steam-water mixture. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
       FIG. 1  is a flowchart illustrating basic steps in the present invention for a SAGD oil recovery process. 
       FIG. 2  is a schematic illustration of a vapor purifying process, which is one embodiment of the present invention. 
       FIG. 3  is a schematic illustration of a boiler and the process of converting boiler feedwater to quality steam for injection into an injection well. 
       FIG. 4  is a schematic illustration of an OTSG and the process of converting OTSG feedwater to quality steam for injection into an injection well. 
       FIG. 5  is a schematic illustration of an alternate OTSG and an alternate process for converting OTSG feedwater to quality steam for injection into an injection well. 
       FIG. 6  is a schematic illustration showing an exemplary package boiler and how the package boiler is utilized to generate a steam-water mixture for injection into an injection well. 
   

   METHOD OF REMOVING HEAVY OIL 
   With further reference to the drawings, the present invention entails a SAGD process for recovering heavy oil, such as the oil found in the northern region of Canada. In implementing the SAGD process, steam, at least 98% quality, is injected into a horizontal injection well that extends through or adjacent to an oil bearing formation. The heat associated with the steam causes oil to drain into an underlying collection well. Because the steam condenses, the process results in an oil-water mixture being collected in the collection well and pumped to the surface. See  FIG. 1 . 
   The oil-water mixture is subjected to a separation process which effectively separates the oil from the water. This is commonly referred to as primary separation and can be carried out by various conventional processes such as gravity separation. Separated water is subjected, in some cases, to a de-oiling process where additional oil is removed from the water. Resulting water from the above oil-water separation process is referred to as produced water. 
   Produced water from the primary separation process includes dissolved inorganic ions, dissolved organic compounds, suspended inorganic and organic solids, and dissolved gases. Typically, the total suspended solids in the produced water are less than about 1000 ppm. 
   In some cases, after primary separation, it may be desirable to remove suspended inorganic and organic solids from the produced water. Various types of processes can be utilized to remove the suspended solids. For example, the produced water can be subjected to gas flotation processes or other processes that use centrifugal force, gravity separation, adsorbent or absorbent processes. After treating the produced water to remove suspended solids, typically the concentration of the suspended solids in the produced water is less than 50 ppm. 
   In addition to suspended solids, produced water from heavy oil recovery processes will include dissolved organic and inorganic solids in varying portions. As discussed below, the produced water will eventually be fed to an evaporator, and the evaporator will produce a distillate that will be directed to a steam generator or boiler. The dissolved organic or inorganic solids in the produced water have the potential to foul the evaporator and the steam generator or boiler. Depending on the absolute and relative concentration of these dissolved solids, the heavy oil recovery process of the present invention may employ chemical treatment of the feedwater after primary separation. Various types of chemical treatment can be employed. For example, scale inhibitors and/or dispersants can be added to the produced water to prevent inorganic fouling and scaling in the evaporator for hardness concentrations of approximately 150 ppm as CaCO 3  or less. In addition, silica scale inhibitors can be mixed with the produced water to prevent silica fouling and scaling in the evaporator. Moreover, the chemical treatment can include the addition of acid to partially convert alkalinity to CO 2  and thereafter the CO 2  can be removed by degassing. Finally, a caustic can be added to the feedwater to increase the pH to approximately 10. This will have the tendency to prevent organic and silica fouling in the evaporator system. 
   After the produced water has been chemically treated, the produced water is directed to an evaporator. The evaporator produces a distillate and an evaporator blowdown stream. Various types of evaporators can be used including but not limited to mechanical vapor compression and steam driven multiple effect. In addition, the heat transfer surfaces of the evaporator can be a plate-type or tubular-type and can be horizontal or vertical, with evaporation occurring on either side of these surfaces. 
   During the evaporation process, a portion of the produced water fed to the evaporator is vaporized. That portion of the produced water that is not vaporized is known as concentrate or brine. Substantially all of the solids in the produced water fed to the evaporator remain with the concentrate. The concentrate is discharged from the evaporator as a waste stream. This is commonly referred to as evaporator blowdown. The evaporator blowdown stream can be converted into a solid in a zero liquid discharge system (ZLD) or disposed in an injection well. Generally, the evaporator converts at least 90% of the produced water to vapor. Vapor is condensed in the evaporator where it releases its latent heat to vaporize produced water, or in a condenser where the heat sink is air or cooling water. After condensing, vapor becomes the distillate. 
   In some cases it may be desirable to treat or purify the vapor produced by the evaporator prior to the vapor being condensed into the distillate. This is because the vapor produced in the evaporator can contain entrained fine droplets of concentrate. The entrained droplets of concentrate contaminate the distillate. In some cases, chemical treatment of the distillate may be required in order to prevent scaling or fouling in the downstream steam generation system. By removing the entrained droplets in the vapor, the amount or degree of chemical treatment of the distillate may be reduced. 
     FIG. 2  schematically illustrates a vapor purifier that can be associated with the evaporator for treating the vapor produced by the evaporator. As illustrated in  FIG. 2 , the vapor with entrained droplets from the evaporator enters the vapor purifier where it makes contact with wash water having a temperature substantially the same as the temperature of the vapor. Furthermore, the wash water includes a lower concentration of solids than the entrained droplets in the vapor being treated. Contact between the vapor and wash water can be achieved in various ways. For example, contact can be realized by utilizing one or more sprays, bubble trays or packing. Essentially the vapor is mixed with the wash water and the entrained droplets mix with and become a part of the wash water. Substantially all of the entrained concentrate droplets mix with the wash water and are removed from the vapor in the separation area of the vapor purifier. Since the solids concentration of the wash water increases due to the mixing of the entrained concentrate droplets, a portion of the wash water is discharged or recirculated back to the evaporator. This maintains a solids balance in the vapor purifier. The discharged wash water is replaced with fresh wash water, which is referred to as makeup wash water, and which has virtually no solids. This makeup water further dilutes the solids in the circulating wash water. 
   During the vapor purification process, it is possible for some droplets of the wash water to become entrained in the vapor. As seen in  FIG. 2 , the vapor after it has been washed is directed upwardly through a mist eliminator. As the vapor moves through the mist eliminator, substantially all of the entrained wash droplets are removed from the vapor and fall by gravity into the catch basin of the vapor purifier. The concentration of solids within the vapor entering the mist eliminator is substantially less than the original concentration of solids in the vapor entering the vapor purifier. 
   It is desirable to produce a high quality steam, for example at least 98% quality, and at the same time eliminate or substantially reduce blowdown streams from the steam generation system. To achieve this it may be desirable to treat the distillate produced by the evaporator and which forms the feedwater for the steam generation system to prevent corrosion, fouling or scaling in the steam generation system. Various forms of chemical treatment (phosphates, polymers, chelants, volatiles, and caustic) can be employed for these purposes. 
   The presence of oxygen in the distillate can be a source of corrosion. There are various processes that can be utilized to remove oxygen. For example, distillate from the evaporator can be directed to a deaerator before entering the steam generation system. Downstream of the deaerator, an oxygen scavenger of the type that will not contribute to scaling can be injected and mixed with the distillate. If the evaporator can be vented adequately, it may not be necessary to utilize a deaerator. Injecting an oxygen scavenger upstream of the steam generation system may be sufficient to reduce the concentration of oxygen in the distillate. Various oxygen scavenging chemicals can be utilized such as diethylhydroxylamine, commonly referred to as DEHA. As an alternate approach to removing oxygen from the feedwater to the steam generation system, an activated carbon filter can be utilized upstream of the evaporator to remove oxygen from the evaporator feedwater. 
   In a typical SAGD process, the distillate stream includes but is not limited to Ca, Mg, Na, K, Fe +3 , Mn +2 , Ba +2 , Sr +2 , SO 4 , Cl, F, NO 3 , HCO 3 , CO 3 , PO 4 , SiO 2 . A typical concentration for a number of the above elements is: Ca—0.0054 mg/l, Mg—0.0010 mg/l, Na—0.3606 mg/l, and K—0.0083 mg/l. Also, in a typical distillate stream, one would find suspended solids to be approximately 0.13 mg/l, TOC to be approximately 40 mg/l, non-volatile TOC to be approximately 5 mg/l, and hardness as mg/l , of CaCO 3 —0.0176 mg/l. The pH of a typical distillate stream may be approximately 8.5. 
   The chemical treatment for hardness could include a polymer-phosphate blend or a chelant. This will solubilize hardness and prevent corrosion. A typical polymer-phosphate blend would comprise trisodium phosphate (TSP); sulfonated styrene/maleic acid (SSMA); high performance quad-sulfonated polymer; and phosphinocarboxylic acid (PCA). A caustic, such as NaOH, can be injected as required to adjust the pH of the distillate. The chemicals may be injected upstream of the boiler or directly into the boiler. 
   Table 1, below, illustrates some typical residual chemical constituents in the boiler water after chemical treatment. The degree and extent of chemical treatment may vary depending upon the operating pressure of the steam generation system. In Table 1 the typical residual chemical constituents are shown for a boiler operating at 1200 psig, 1500 psig and 2000 psig. 
   
     
       
         
             
           
             
               TABLE 1 
             
           
          
             
                 
             
             
               Typical Residual Chemical Constituents in Boiler Water for Varying 
             
             
               Boiler Operating Pressures 
             
          
         
         
             
             
          
             
                 
               Boiler Operating Pressure 
             
          
         
         
             
             
             
             
             
          
             
                 
               Chemical 
               1200 psig 
               1500 psig 
               2000 psig 
             
             
                 
                 
             
          
         
         
             
             
             
             
             
             
             
             
          
             
                 
               Phosphate 
               10-15 
               ppm 
               8-12 
               ppm 
               2-4 
               ppm 
             
             
                 
               Polymer 
               4-5 
               ppm 
               2-4 
               ppm 
               1-2 
               ppm 
             
             
                 
               DEHA* 
               20-40 
               ppb 
               20-40 
               ppb 
               20-40 
               ppb 
             
             
                 
               Caustic 
               0-2 
               ppm 
               0-2 
               ppm 
               0-2 
               ppm 
             
             
                 
                 
             
             
                 
               *DEHA is residual as measured in the boiler feedwater. All other chemicals are residuals measured in the boiler water, that is, the water recirculating through the boiler. 
             
          
         
       
     
   
   The chemistry of the distillate stream will vary, and accordingly, the chemical treatment suggested herein will also vary depending on distillate chemistry, the type of steam generation system utilized, operating pressures of the steam generation system, and the quality of steam produced, as well as other factors. 
   After treatment if a treatment process is implemented, the distillate is directed to a steam generation system. The steam generation system can assume various forms such as a boiler or a once through steam generator (OTSG).  FIG. 3  illustrates a package boiler that is indicated by the numeral  50 . Package boiler  50  includes a steam drum  52  and mud drum  54 . A plurality of risers  56  extend between the mud drum  54  and the steam drum  52 . A plurality of downcorners  58  extends between the steam drum  52  and the mud drum  54 . 
   Boiler  50  is provided with a water recirculation loop  60 . A pump  62  disposed in the recirculation loop  60  serves to pump the water from the steam drum  52  and back to the inlet of the steam drum  52  via line  60 A. In addition, the recirculation loop  60  is connected, via line  60 B, to a steam outlet line  70  that extends from the steam drum  52 . This permits water moving in the recirculation loop  60  to be mixed with both the incoming distillate or feedwater and the steam in line  70  exiting the steam drum  52 . 
   Water in the boiler  50  circulates naturally based on the differences in density between the water in the risers  56  and the downcorners  58 . Downcorners  58  return water from the steam drum  52  to the mud drum  54 . The temperature of the water in the downcorners  58  is at or slightly less than saturation temperature. The downcorners  58  are not used for heat transfer. Heat from combustion within the boiler  50  is applied to the outside of the risers  56 . This heat is transferred to the water in risers  56  and results in partially boiling the water. The net effect is that the density of the column of fluid in the risers  56  is less than that of the fluid in the downcorners  58 . This density differential drives the circulation of water from the steam drum  52  to the mud drum  54  and back to the steam drum. Steam is produced in the steam drum  52 . Associated with the steam drum  52  of the boiler  50  is a conventional vapor-liquid separator that separates the steam or vapor from the water in the steam drum. Various mechanisms can be utilized in the boiler  50  to separate the vapor from the water. These separating mechanisms generally include gravity separators, centrifugal force separators, and mechanical entrainment elimination devices. Generally, nearly 100% quality steam is produced at the outlet of the steam drum  52 . 
   As steam is produced in the steam drum  52 , additional feedwater is directed through the boiler feedwater line  66  into the steam drum. The boiler feedwater will carry some non-volatile solids. In this case, to deal with any significant solids introduced into the boiler  50 , a portion of the water being recirculated in the recirculation loop  60  is directed into the steam outlet line  70 . Here, the water mixes with the steam to form a steam-water mixture. Generally, it is contemplated that the water directed into the steam outlet line  70  will be such that the steam being directed into the oil bearing formation will be approximately 98% quality steam. Note that in this case, there is no boiler blowdown stream and approximately 100% of the heat transferred to the feedwater is injected for EOR. That is, on an ongoing basis, no waste stream is discharged from the boiler  50 . This means that essentially all of the feedwater directed to the boiler  50  is utilized for oil recovery and injected into the injection well extending through the oil bearing formation. 
   Another type of steam generator or steam generation system is shown in  FIG. 4 . In this case the steam generation system includes an OTSG  100 . Note in  FIG. 4  where there is provided a feedwater line  80  that leads to a pump  82 . Extending between the pump  82  and the OTSG  100  is an inlet line  72 . A steam outlet line  74  is communicatively connected with a steam-water separator  76 . A recirculation loop  78  extends from the steam-water separator  76  to the inlet line  72 . Disposed in the recirculation loop is a pump  86 . A feed line  88  extends from the recirculation loop  78  and is communicatively connected to a steam outlet line  84  that extends from the separator  76 . 
   OTSG  100  is a forced circulation type steam generator that utilizes the high pressure pump  82  to force the feedwater through heating tubes in the steam generator. Feedwater is pumped through the tubing and is heated from combustion heat applied exteriorly of the tubes. Water is partially converted to steam by the time the fluid exits the heat transfer tubing in the steam generator. Typically 70% to 80% of the water is converted to steam through this process. Water and vapor mixture exiting outlet line  74  is 70% to 80% quality steam. The 70% to 80% quality steam mixture enters the separator  76  where the steam is separated from the water. In the case of the present process, steam exits the separator  76  at approximately 98% quality or higher. 
   High pressure water from the separator  76  is circulated via recirculation loop  78  back to the inlet of the OTSG  100 . As seen in  FIG. 4 , to control solids accumulation in the OTSG  100 , a mixing stream of high pressure water is directed through mixing line  88  and combines with the steam being directed through the steam outlet line  84 . Again, this produces a steam-water mixture having a steam quality of approximately 98%. 
     FIG. 5  illustrates an alternative steam generation system. In  FIG. 5  there is a once through steam generator  100  that is similar in many respects to the system shown in  FIG. 4  and described above. Line  90  extends from the steam-water separator  76  to a pump  94  which is operative to direct some of the water passing in line  90  to the steam outlet line  84  via feed line  92 . Line  102  directs a portion of the water from line  90  to the feedwater inlet line  72 . However, in the  FIG. 5  embodiment, line  90  also connects to a flash vessel  96 . Connected to the flash vessel  96  is a line  98 , having pump  106  connected therein, which is operative to direct water from the flash vessel through line  98  to the feedwater inlet line  72 . Flash vessel  96  also includes a vapor line  104  that is utilized to direct vapor from the flash vessel  96  to a beneficial use in the process where the heat associated with the vapor can be recovered. 
     FIG. 6  shows a more detailed schematic of a package boiler design. The package boiler shown herein is similar to the package boiler shown in  FIG. 3 . As illustrated in  FIG. 6 , the package boiler  50  includes a steam drum  52  and a mud drum  54 . A plurality of risers  56  extend between the steam drum  52  and the mud drum  54 . In addition, a plurality of downcorners  58  extends between the steam drum  52  and the mud drum  54 . Steam drum  52  includes a blowdown outlet  110  which ordinarily connects to a boiler blowdown line. As will be discussed subsequently herein, the blowdown outlet  110  is connected to line  60  which, as discussed above, branches into a recirculation stream or line  60 A and a blending stream or line  60 B. A discussion of line  60  and the process of mixing water and solids from line  60  into steam line  70  will be subsequently discussed. 
   Turning now to a description of the overall process, distillate from an evaporator is directed through line  66  into a boiler feedwater tank  112 , which is disposed adjacent the boiler  50 . Boiler feedwater in tank  112  is pumped by a transfer pump  114  into line  116  which extends thorough a boiler feedwater preheater  118 . From the preheater  118 , the boiler feedwater is directed into a deaerator  120 . In conventional fashion, an oxygen scavenger injector  122  is communicatively coupled to the deaerator  120  for removing gases from the feedwater. From the deaerator  120 , the feedwater is pumped by pump  124  through another preheater  126  and through a heat exchanger  128  on the inlet side of the steam drum  52 . Feedwater passing from the heat exchanger  128  through line  130  is fed into the steam drum  52 . 
   Boiler  50  produces steam. As seen in  FIG. 6 , steam from the steam drum  52  is directed through a super heater  160  which is heated by flue gases from the boiler  50 . Steam leaving super heater  160  is directed through steam line  70  to a device referred to as a de-super heater  162 . While temperature, pressure and other parameters can vary, in one embodiment the super heater  160  adds approximately 50° F. of super heat to the steam produced by the boiler. At a steam drum pressure of 1400 psig, the saturated temperature is approximately 587° F. Under these conditions, steam leaving the super heater  160  will have a temperature of approximately 637° F. (587° F.+50° F.). 
   Boiler  50  also produces a water stream that includes dissolved solids and which is directed out the steam drum  52  via the blowdown outlet  110  and line  60 . Pump  62  pumps the water stream to a point where the water stream branches into streams  60 A and  60 B. Water and residual dissolved solids in stream  60 B are mixed with the steam in primary steam line  70  in the de-super heater  162  to form a blended steam line  71  that is directed into an injection well. Water in line  60 A is recycled to the steam drum  52 . 
   Various chemicals are injected into the boiler  50  for treating the steam or water in the boiler. For example, as shown in  FIG. 6  there is provided a caustic injection system  132  that injects a caustic via line  134  into the steam drum  52 , or via line  134 A into the boiler feedwater line  130 . Likewise, another injection system  136  injects various boiler water treatments directly into steam drum  52  via line  138 . 
   Boiler  50  includes a conventional mud blow off line  140  that is interconnected between the mud drum  54  and a blow off tank  142 . The mud blow off collected in tank  142  is pumped by pump  144  to a filtering system  146 . Filtering system  146  removes suspended solids from the mud blow off. The effluent from the filter system  146  is recycled through line  148  to the boiler feedwater tank  112 . Occasionally cooling water can be injected into the line between the tank  142  and pump  144 . 
   The mud blow off portion of the package boiler just described is conventional in packaged boilers. Typically one or more valves between the mud drum  54  and the mud blow off line  140  is open for a relatively short period of time. It is contemplated in one embodiment that these valves would be open once every eight hours for approximately 30 seconds. During this time, mud or sludge concentrated in the bottom of the mud tank  54  is forced under pressure through line  140  into blow off tank  142 . This mud or sludge would include suspended solids, water, and dissolved solids. 
   In the embodiments shown in  FIGS. 3-6 , water is generally recirculated through the various recirculation loops and various branches extending therefrom. In the  FIG. 3  embodiment, for example, water is circulated through line  60 B to the steam outlet line  70 , and from line  60  into branch line  60 A into the feedwater inlet to the boiler. Preferably, flow of water into the various steam lines varies depending on the concentration of solids in the feedwater. The higher the concentration of solids in the feedwater, the greater the amount of recirculated water directed into the steam lines. However, in one embodiment, the amount of water recirculated and mixed with steam would not exceed 2% of the feedwater. To achieve a variable flow of recirculated water to the steam line, the process of the present invention could utilize various conventional means such as controlling the flow of water to the steam outlet line based on the sensed or measured concentration of solids in the feedwater. 
   As noted above, various types of controls can be employed to control and maintain the steam quality at approximately 98% or more. In the  FIG. 6  embodiment, a flow control valve FCV is employed in line  60  and controls the amount of water recirculated through line  60 A to the steam drum  52  and the amount of water directed through line  60 B to steam line  70  for mixing with the steam. Basically in one example, the control scheme will first permit sufficient water to be mixed with the steam in line  70  to effectively de-super heat the steam. At this point, the steam is still approximately 100% quality steam. One control program, which uses the temperature difference between the super heated and saturated steam temperatures, would add a small excess amount of water into the de-super heater in line  70 . For example, an additional 0.5% of the measured steam flow is added to the calculated de-super heating water flow and the resulting point is the set point for the flow control valve FCV. This will ensure 99.5% quality steam. At 100% design capacity, in one embodiment, steam is produced at 50° F. super heat from the boiler  50 . As the boiler capacity is reduced, there will be less super heat in the steam, and less super heating water is required. When the amount of calculated super heating water decreases to 2% of the steam flow, the de-super heating flow control will remain at 2% of the steam flow rate to maintain 98% quality steam and for all operations below this point. 
   In cases where there is no super heater included with the boiler, the amount of water injected into the steam line is approximately 2% of the measured steam flow. This will permit 98% quality steam to be maintained. 
   The oil recovery processes, as discussed above, are designed to operate without a waste stream being generated and wasted from the steam generating systems shown in  FIGS. 3-6 . It is possible for upsets to occur in the overall oil recovery process, and for example, a significant amount of oil can be inadvertently passed into the boiler or steam generator feedwater, and hence into the boiler or steam generator. In such cases, it is beneficial to provide the steam generating system with some means of flushing and cleaning the boiler or steam generator to remove such oil or other contaminants. However, such flushing or cleaning forms no part of the ongoing steam generation process used in the oil recovery process. Rather, these measures are implemented for scheduled maintenance or to deal with an upset. 
   In the process embodiments discussed herein, it is desirable to inject substantially the entirety of the feedwater, in the form of steam and water, into the injection well. This means that the process can be carried out without any blowdown stream from either the boiler  50  or the OTSG  100 . In the case of the process embodiments illustrated in  FIGS. 4 and 5 , the quality of the steam produced by the steam-water separator  76  may vary between 98% and approximately 100%. In the case of 98% quality steam, it is envisioned that there would be no need to inject water from the recirculation loops into the steam being directed into the injection wells. However, in cases where the steam-water separator  76  produces near 100% quality steam, it is envisioned that water from the recirculation loop would be injected into the steam being directed to the injection well in an amount that would yield a 98% quality steam. This would mean that sufficient water would be injected into the steam such that the water in the steam-water mixture injected into the injection well would constitute, by weight, approximately 2% of the fluid injected into the injection well. 
   The present invention may, of course, be carried out in other ways than those specifically set forth herein without departing from essential characteristics of the invention. The present embodiments are to be considered in all respects as illustrative and not restrictive, and all changes coming within the meaning and equivalency range of the appended claims are intended to be embraced therein.