STEAM DRIVEN DIRECT CONTACT STEAM GENERATION

Abstract

The present invention is a system and method for steam production for oil production. The method includes generating steam, mixing the steam with water containing solids and organics, separating solids, and injecting the steam through an injection well or using it above ground for oil recovery, such as for generating hot process water. The system includes a steam drive direct contact steam generator. The water feed of the present invention can be hot produced water separated from a produced oil emulsion and/or low quality water salvaged from industrial plants, such as refineries and tailings from an oilsands mine.

Description

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

REFERENCE TO MICROFICHE APPENDIX

Not applicable.

BACKGROUND OF THE INVENTION

1. Field of the Invention

This application relates to a system and method for producing steam from a contaminated water feed for Enhanced Oil Recovery (EOR). This invention relates to processes for directly using steam energy, preferably superheated dry steam, for generating additional steam from contaminated water by direct contact, and using this produced steam for various uses in the oil industry, and in other industries as well. The produced steam can be injected underground for Enhanced Oil Recovery. It can also be used to generate hot process water for the mining oilsands industry. The high pressure drive steam is generated using a commercially available, non-direct steam boiler, co-gen, Once Through Steam Generator (OTSG) or any steam generation system or steam heater. Contaminates, like suspended or dissolved solids within the low quality water feed, can be removed in a stable solid (former Liquid Discharge) system. The system can be integrated with a combustion gas fired Direct Contact Steam Generator (DCSG) for consuming liquid waste streams or with distillation water treatment systems.

2. Description of Related Art Including Information Disclosed Under 37 CFR 1.97 and 37 CFR 1.98

The injection of steam into heavy oil formations has proven to be an effective method for EOR and it is the only method currently used commercially for recovery of bitumen from deep underground oilsands formations in Canada. It is known that EOR can be achieved when combustion gases, mainly CO2, are injected into the formation, possibly with the use of a DCSG as described in my previous applications. The problem is that oil producers are reluctant to implement significant changes to their facilities, especially if they include changing the composition of the injected gas to the underground formation and the risk of corrosion in the carbon steel pipes due to the presence of the CO2. Another option to address these concerns and generate steam from low grade produced water with Zero Liquid Discharge (ZLD) is to operate the DCSG with steam instead of a combustion gas mixture that includes, in addition to steam, other gases like nitrogen, carbon dioxide, carbon monoxide, etc. The driving steam is generated by a commercially available non-direct steam generation facility. The driving steam is directly used to transfer liquid water into steam and solid waste. In EOR facilities, most of the water required for steam generation is recovered from the produced bitumen-water emulsion. The produced water has to be extensively treated to remove the oil remains that can damage the boilers. This process is expensive and consumes chemicals. The Steam Drive-Direct Contact Steam Generator (SD-DCSG) can consume the contaminated water feed for generating steam. The SD-DCSG can be a standalone system or can be integrated with a combustion gas DCSG, as described in this application. The proposed SD-DCSG is also suitable for oilsands mining projects where the Fine Tailings (FT) or Mature Fine Tailings (MFT) are heated and converted to solids and steam using the driving steam energy. The produced steam from the SD-DCSG can be used to heat the process water in a direct or non-direct heat exchange. The hot process water is mixed with the mined oilsands ore during the extraction process.

The method, as described, includes generating additional steam from highly contaminated oily water with an option for zero liquid waste discharge. Superheated steam from an industrial boiler is used as the driving force for generating additional steam in a direct contact heat transfer with the contaminated water. Fine Tailings from tailing ponds can be also used. A “tailor made” pressure and temperature steam, as required for injection into the underground oil bearing formation, is generated. This process allows for generation of additional lower temperature steam from waste water in a high efficiency energy process. The amount of additional steam generated increases with the temperature of the driving steam, and with the reduction of the pressure of the formation. For low pressure shallow formations, more steam can be produced in comparison to deep, high pressure formations. Another option is to recycle a portion of the produced steam through a heater and use it as the driving steam, and thereby minimizing the need for external steam as a heat energy source. A portion of the oil component in the water feed will be converted into hydrocarbon gas, basically serving as a solvent. Additional solvents can be added and injected with the steam to improve the oil recovery. The presented technology has a high thermal efficiency capable of consuming contaminated hot produced water, without the need to reduce the heat to allow effective water treatment. The process can convert the existence of oil contaminates within the feed water into an advantage by generating solvent. This steam generation direct contact facility can be located in close proximity to the SAGD pads to use the hot produced water and inject the produced steam into the injection wells.

The steam for the SD-DCSG can be provided directly from a power station. The most suitable steam will be medium pressure, super-heated steam as is typically fed to the second or third stage of steam turbine. A cost efficient, hence effective system will be used to employ a high pressure steam turbine to generate electricity. The discharge steam from the turbine, at a lower pressure, can be recycled back to the boiler re-heater to generate a superheated steam which is effective as a driving steam. Due to the fact that the first stage turbine, which is the smallest size turbine, produces most of the power (due to a higher pressure), the cost per Megawatt of the steam turbine will be relatively low. The efficiency of the system will not be affected as the superheated steam will be used to drive the SD-DCSG directly and to generate injection steam for an enhanced oil recovery unit with Zero Liquid Discharge (ZLD). A ZLD facility is more environmentally friendly compared to a system that generates reject water and sludge.

The definition of “Steam Drive-Direct Contact Steam Generation” (SD-DCSG) is that steam is used to generate additional steam from a direct contact heat transfer between the liquid water and the combustion gas. This is accomplished through the direct mixing of the two flows (the water and the steam gases). In the SD-DCSG, the driving steam pressure is similar to the combustion pressure and the produced steam is a mixture of the two.

The driving steam is generated in a Non-Direct Steam Generator (like a steam boiler with a steam drum and a mud drum) or in a “Once Through Steam Generator” (OTSG) COGEN that uses the heat from a gas turbine to generate steam, or in any other available design. The heat transfer and combustion gases are not mixed and the heat transfer is done through a wall (typically a metal wall), where the pressure of the generated steam is higher than the pressure of the combustion. This allows for the use of atmospheric combustion pressure. The product is pure steam (or a steam and water mixture, as in the case of the OTSG) without combustion gases.

The excessive energy in the superheated steam is used for generating additional lower temperature steam for injection into the formation. The use of evaporation water treatment facilities in the oilsands industry allows for the production of superheated steam. The proposed method uses Direct Contact Steam Generation where the superheated steam gas is in direct contact with the liquid produced water. Hydrocarbons, like solvents, within the produced water will be directly converted to gas and recycled back to the formation, possibly with additional solvents that can be added to the steam flow. The method generates a “tailor made” pressure and temperature steam, as required for injection into the underground oil bearing formation while maximizing the amount of the generated steam. The simulation in this application shows that for a 263 psi system with a constant feed of 25° C. water flow at 1000 kg/hour, there is a need for 12.9 tons/hour of 300° C. steam to gasify 1 ton/hour of liquid water. When higher temperature (500° C.) driving steam is used, there is a need for only 4.1 tons/hour of steam. The example simulation results show that the amount of produced steam increases by 314% with an increase in the driving steam temperature. The pressure impact simulation was based on driving steam being at a constant temperature of 450° C. and with one ton/hour of 25° C. water feed. The simulation shows that at pressure of 263 psi, 4.9 tons/hour of driving steam is used to gasify the water feed. At a higher pressure of 1450 psi, 5.1 tons/hour driving steam will be used. The results show that a pressure increase slightly reduces the amount of produced steam. The impact of the feed water temperature on the system performance was also simulated. It was shown that for a system of constant 12 kw heat source at 600 psi, 15.1 kg/hour of feed water was gasified to generate injection steam. When the produced water temperature was 220° C., 22.4 kg/hour was gasified. This shows that the produced water temperature has a large impact on the overall performance and that by using the high temperature produced water, the system performance can be increased by close to 150%. The simulation shows that hydrocarbons, like solvents with the produced water, will be converted to gas and injected with the steam. The system can also include a heater to recycle a portion of the produced steam as the driving steam that will be produced locally. There was also shown to be an advantage to using hot produced water and minimizing the produced steam pressure drop. This can be achieved by locating the system close to the injection and production well pad. Make-up steam supplied from a remote steam generation facility can be used to operate a steam ejector with a local steam heater, or be used as the superheated driving steam. The system is ZLD in nature. It can also produce liquid waste if liquid disposal is preferred.

There are patents and disclosures issued in the field of the present invention. U.S. Pat. No. 6,536,523, issued to Kresnyak et al. on Mar. 25, 2003, describes the use of blow-down heat as the heat source for water distillation of de-oiled produced water in a single stage MVC water distillation unit. The concentrated blow-down from the distillation unit can be treated in a crystallizer to generate solid waste.

U.S. patent application Ser. No. 12/702,004, filed by Minnich et al. and published on Aug. 12, 2010, describes a heat exchanger that operates on steam for generating steam in an indirect way from low quality produced water that contains impurities. In this disclosure, steam is used indirectly to heat the produced water that includes contaminates. By using steam as the heat transfer medium, the direct exposure of the low quality water heat exchanger to fire and radiation is prevented, thus there will be no damage due to the redaction of the heat transfer. The concentrated brine is collected and delivered for disposal or to a multi stage evaporator to recover most of the water and there generates a ZLD system. The heat transfer surfaces between the steam and the produced water will have to be clean or the produced water will have to be treated. The concentrated brine, possibly with organics, will be treated in a low pressure, low temperature evaporator to increase the concentration; the higher the concentration is, the lower the temperature. In my application, due to the direct approach of the heat transfer, the system in ZLD with the highest concentration, possibly up to 100% liquid recovery, while generating solid waste, is at the first stage at a higher temperature due to the direct mixture with the superheated dry steam that converts the liquid into gas and solids.

U.S. Pat. No. 7,591,309, issued to Minnich et al. on Sep. 22, 2009, describes the use of steam for operating a pressurized evaporation facility where the pressurized vapor steam is injected into underground formations for EOR. The steam heats the brine water which is boiled to generate additional steam. To prevent the generation of solids in the pressurized evaporator, the internal surfaces are kept wet by liquid water and the water is pre-treated to prevent solid build up. The concentrated brine is discharged for disposal or for further treatment in a separate facility to achieve a ZLD system. To achieve ZLD, the brine evaporates in a series of low pressure evaporators (Multi Effect Evaporator).

U.S. Pat. No. 6,733,636, issued to Heins on May 11, 2004, describes a produced water treatment process with a vertical MVC evaporator.

U.S. Pat. No. 7,578,354, issued to Minnich et al. on Aug. 25, 2009, describes the use of Multi Effect Distillation (MED) for generating steam for injection into an underground formation.

U.S. Pat. No. 7,591,311, issued to Minnich et al. on Sep. 22, 2009, describes a process of evaporating water to produce distilled water and brine discharge, feeding the distilled water to a boiler, and injecting the boiler blow-down water from the boiler into the produced steam. The solids and possibly volatile organic remains are carried with the steam to the underground oil formation. The concentrated brine is discharged in liquid form.

U.S. Pat. No. 4,398,603, issued to Rodwell on Aug. 16, 1983, describes producing steam from a low quality feed water. Superheated steam is introduced into liquid water in a vessel. The mixture is done in a liquid environment where minerals (solids) are participates and are removed in a liquid phase from the vessel by withdrawing a waste water stream. Due to the excess heat within the superheated steam, a portion of the liquid feed water evaporates and produces saturated steam. Because all mixing with the steam is done in a liquid environment, the process can only produce saturate (wet) steam with waste liquid discharge for removing the solids.

This invention's method and system for producing steam for extraction of heavy bitumen includes the steps as described in the patent figures.

The advantage and objective of the present invention are described in the patent application and in the attached figures.

These and other objectives and advantages of the present invention will become apparent from a reading of the attached specifications and appended claims.

SUMMARY OF THE INVENTION

Steam injection is currently the only method commercially used on a large scale for recovering oil from deep (non-minable) oil sands formations. Sometimes additional solvents are used, mainly hydrocarbons. There are a few disadvantages to the existing steam generation methods. For example, the steam is much cleaner than is needed for injection. To achieve the water quality currently used for steam injection, the water is extensively treated—the first stage is to separate the oil and de-oiling. To achieve that, the produced water is cooled to a temperature at which it can efficiently be de-oiled to the water treatment plant feed specifications where it is treated to the boiler feed water specifications. The need to cool the water decreases the SAGD's overall efficiency. In recent year there has been a shift toward the use of evaporator water treatment technologies instead of softening based technologies. As a result, due to the higher quality of the produced water, it is possible to increase the produced steam temperature and pressure. There are other advantages to the use of evaporators to treat the produced water, such as the ability to use brackish water with high levels of salts and incorporate a crystallizer to achieve ZLD. The proposed method intends to use the systems and methods developed for combustion of low quality fuel in gas driven Direct Contact Steam Generation (DCSG) and to replace the combustion gas driving fluid with steam, where additional steam is generated by a direct mixture of liquid with superheated steam gas, resulting in a relatively low cost steam achieved by a Steam Drive DCSG.

The method and system of the present invention for steam production (for extraction of heavy bitumen by injecting the steam into an underground formation or by using it as part of an above ground oil extraction facility) includes the following steps: (1) Generating a super heated steam stream. The steam is generated by a commercially available non-direct steam generation facility, possibly as part of a power plant facility; (2) Using the generated steam as the hot gas to operate a DCSG (Direct Contact Steam Generator); (3) Mixing the super heated steam gas with liquid water containing significant levels of solids, oil contamination and other contaminates; (4) Directly converting liquid phase water into gas phase steam; (5) Removing the solid contaminates that were supplied with the water for disposal or further treatment; (6) Using the generated steam for EOR, possibly by injecting the produced steam into an underground oil formation through SAGD or CSS steam injection wells.

The presented method and its associated system can be applied to many existing oilsands operations. Due to the minimal water treatment requirements and the fact that the feed water can be at higher temperatures, it is possible to produce additional steam close to the production and the injection wells, on the well pad. The high temperature of the feed water is an advantage as this heat energy helps in the production of steam and minimizes the amount of superheated driving steam consumed. It is possible to operate the SD-DCSG in a ZLD mode where the solids contaminates are extracted in a dry, semi-dry stable form. A ZLD facility is more environmentally friendly compared to a system that generates reject water and sludge. However, it is also possible to operate the SD-DCSG in liquid waste discharge mode (liquid discharge mode can be used if disposal caverns or disposal wells are available and are approved for disposal usage by the regulators, like the Energy Resources Conservation Board (ERCB) in Alberta, Canada). The invention method can also be operated in a liquid waste discharge mode. This can be done by adjusting the ratio between the produced water and the driving superheated steam and increasing the water feed flow or decreasing the superheated driving steam flow. The water feed of this method and system for enhanced oil recovery can be water separated from produced oil and/or low quality water salvaged from industrial plants, such as refineries, and tailings as make-up water. Both of the above will allow oilsands operations to more easily meet environmental regulations without radical changes to oil recovery and water recycling technologies currently in use.

The excessive energy in superheated steam can be used for generating additional lower temperature steam for injection into the formation. The use of evaporation water treatment facilities in the oilsands industry allows for the production of superheated steam. The proposed method uses Direct Contact Steam Generation where the superheated steam gas is in direct contact with the liquid produced water. Hydrocarbons, like solvents, within the produced water will be directly converted to gas and recycled back to the formation, possibly with additional solvents that can be added to the steam flow. The presented technology generates a “tailor made” pressure and temperature steam, as required for injection into the underground oil bearing formation while maximizing the amount of the generated steam. The simulation shows that for a 263 psi system with a constant feed 25° C. water flow at 1000 kg/hour, there is a need for 12.9 tons/hour of 300° C. steam to gasify 1 ton/hour of liquid water. When higher temperature (500° C.) driving steam is used, there is a need for only 4.1 tons/hour of steam. The results show that the amount of produced steam increases by 314% with a driving steam temperature increase. The pressure impact simulation was based on driving steam at a constant temperature of 450° C. and 1 ton/hour 25° C. water feed. The simulation shows that at pressure of 263 psi, 4.9 tons/hour of driving steam is used to gasify the water feed. At a higher pressure of 1450 psi, 5.1 tons/hour driving steam will be used. The results show that a pressure increase slightly reduces the amount of produced steam. The impact of the feed water temperature on the system performance was also simulated. It was shown that for a system of a constant 12 kw heat source at 600 psi, 15.1 kgs/hour of feed water was gasified to generate injection steam. Where the produced water temperature was 220° C. temperature, 22.4 kg/hour was gasified. This shows that the produced water temperature has a large impact on the overall performance and that by using the high temperature produced water, the system performance can be increased by close to 150%. The simulation shows that hydrocarbons, like solvents with the produced water, will be converted to gas and injected with the steam. The system can also include a heater to recycle a portion of the produced steam as the driving steam that will be produced locally. There was shown to be an advantage to using hot produced water and to minimizing the produced steam pressure drop. This can be achieved by locating the system close to the injection and production well pad. Make-up steam supplied from a remote steam generation facility can be used to operate a steam ejector with a local steam heater, or be used as the superheated driving steam. The system can be ZLD. It can also produce liquid waste if liquid disposal is preferred.

In another embodiment, the invention can include the following steps: (1) Generating a super heated steam stream. The steam is generated by heating a steam stream in a non-direct heat exchanger; (2) Using the generated steam as the hot gas to operate a DCSG (Direct Contact Steam Generator); (3) Mixing the super heated steam gas with liquid water containing significant levels of solids, oil contamination and other contaminates; (4) Directly converting liquid phase water into the gas phase steam; (5) Removing the solid contaminates that were supplied with the water for disposal or further treatment; (6) Recycling a portion of the generated steam back to the heating process of (1) to be used as the hot gas operating the DCSG. The recycled steam can be cleaned to remove contaminates that can affect the heating process (like silica). The cleaning process can include any type of filter, precipitators or wet scrubbers. Chemicals (like caustic, magnesium salts or any other commercially available chemicals) can be added to the wet scrubber to remove contaminates from the steam flow.

In another embodiment, part of the generating steam is condensed and used to wash the produced steam of solid particles in a wet scrubber. Chemicals can be added to the liquid water to remove contaminates. A portion of the liquid water is recycled back and mixed with the superheated steam to transfer it into gas and solids. A portion of the scrubbed saturated steam flow can be recycled and heated to generate a super heated “dry” steam flow to drive the SD-DCSG and change the liquid flow into steam.

In another embodiment, the scrubbed saturated steam, after the solids are removed, can be condensed to generate contaminate free liquid water, at a saturated temperature and pressure. The liquid water can be pumped and fed into a commercially available non-direct steam boiler for generating super heated steam to drive the SD-DCSG for transferring the liquid contaminated water into gas and solids.

In another embodiment, the SD-DCSG is integrated with a DCSG that uses combustion gases as the heat source. In that embodiment, the discharge from the SD-DCSG can be in a liquid form and it can be used as the water source for the combustion gas driven DCSG.

The present invention can be used to treat contaminated water using the SD-DCSG in different industries, such as the power industry or chemical industry where there is a need to recover the water from a contaminated water stream to generate steam with zero liquid discharge.

The system and method's different aspects of the present invention are clear from the following figures.

BRIEF DESCRIPTION OF THE DRAWINGS

FIGS. 1, 1A, 1B, 1D, and 1E show the conceptual flowchart of the method and the system.

FIG. 2 shows a block diagram of an embodiment of the invention.

FIG. 2A shows a schematic of a vertical SD-DCSG.

FIG. 2B shows a block diagram of the embodiment of the invention.

FIG. 2C is schematic view of another embodiment of a reaction chamber apparatus of a high-pressure steam drive direct contact steam generator of the present invention.

FIG. 2D shows a schematic view of another embodiment of a vertical SD-DCSG.

FIG. 2E shows a schematic view of a SD-DCSG integrated into an open mine oilsands extraction plant.

FIG. 2F shows a schematic view of a SD-DCSG with a non-direct heat exchanger to heat the process water.

FIG. 3 is a schematic view of an illustration of one embodiment of the present invention without using an external water source for the driving steam.

FIG. 3A is a schematic view of an illustration of another embodiment of the present invention.

FIG. 3B is a schematic view of an illustration of a parallel flow SD-DCSG according to FIG. 3A.

FIG. 3C is a schematic view of an illustration of a SD-DCSG with a stationary enclosure and an internal rotating element.

FIG. 3D is a schematic view of an illustration of a modification of FIGS. 3C and 3B for a steam drive Non-Direct contact steam generator.

FIG. 3E shows a schematic view of a parallel flow and a counter flow steam drive direct contact steam generation system.

FIG. 3F shows a schematic view of a direct contact steam generating system as shown in FIG. 3E with solids separation.

FIG. 3G is a schematic view of a steam drive direct contact steam generator apparatus.

FIG. 3H is a schematic view of another configuration of a steam drive direct contact steam generator apparatus.

FIG. 3I is a schematic view of a steam drive direct contact steam generator apparatus.

FIG. 3J is a schematic view of a steam drive direct contact steam generator with an internal wet scrubber that generates additional wet solids free steam.

FIG. 3K is a schematic view of an illustration of another embodiment of the present invention.

FIG. 4 is a schematic view of an illustration of still another embodiment of the present invention.

FIG. 5 is a schematic diagram of one embodiment of the invention that generates wet scrubbed, clean saturated steam.

FIG. 5A is a schematic view of an illustration of one embodiment of the invention where a portion of the driving steam water is internally generated.

FIG. 5B is a schematic view of the invention with internal distillation water production for the boiler.

FIG. 5C is a schematic diagram of a method that is similar to FIG. 5B but with a different type of SD-DCSG.

FIG. 6 is a schematic diagram of the present invention which includes a SD-DCSG and an EOR facility.

FIG. 6A is a schematic flow diagram of the integration between SD-DCSG and DCSG that uses the combustion gas generated by the pressurized boiler.

FIG. 6B is a schematic view of a direct contact steam generator with rotating internals, dry solids separation, wet scrubber and saturated steam generator.

FIG. 6C is a schematic view of a SD-DCSG and heavy oil extraction through steam injection.

FIG. 6D shows a schematic view of a SD-DCSG similar to the system in FIG. 6C.

FIG. 6E is a schematic view of the SD-DCSG with similarities to FIG. 6D and with externally supplied make-up HP steam.

FIG. 6F shows a schematic view of another embodiment of the present invention for generating steam for oil extraction with the use of a steam boiler and steam heater.

FIG. 7 is a schematic view of an integrated facility of the present invention with a commercially available steam generation facility and for EOR for heavy oil production.

FIG. 8 is a schematic view of the invention with an open mine oilsands extraction facility.

FIG. 9 is another schematic view of the invention with an open mine oilsands extraction facility and a pressurized fluid bed boiler.

FIG. 10 is a schematic diagram of DCSG pressurized boiler and SD-DCSG.

FIG. 11 is a schematic diagram of the present invention which includes a steam generation facility, SD-DCSG, a fired DCSG and MED water treatment plant.

FIG. 11A is a schematic view of the present invention that includes a steam generation facility, SD-DCSG and MED water treatment plant.

FIG. 11B is a schematic diagram of the present invention that includes a steam drive DCSG with a direct heated Multi Stage Flash (MSF) water treatment plant and a steam boiler for generating steam for EOR.

FIG. 12 is a schematic view of an illustration of the use of a partial combustion gasifier with the present invention for the production of syngas.

FIG. 13 is a schematic view of the present invention for the generation of hot water for oilsands mining extraction facilities.

FIG. 13A is a schematic view of the process for the generation of hot water for oilsands mining extraction facilities, with Fine Tailing water recycling.

FIG. 13B is a schematic view of the process for the generation of hot water for oilsands mining extraction facilities, with Fine Tailing water recycling.

FIG. 14 is a schematic view of one illustration of the present invention for the generation of pre-heated water.

FIG. 15 is a schematic view of the invention with an open mine oilsands extraction facility.

FIG. 16 is a another schematic view of the invention with another open mine oilsands extraction facility.

FIG. 17 is a schematic view of the invention with still another open mine oilsand extraction facility.

FIG. 18 is a schematic view of the invention with yet another open mine oilsands extraction facility.

FIG. 19 is a schematic view of an illustration of still another embodiment of the present invention.

FIG. 20 is a schematic view of an illustration of yet another embodiment of the present invention.

FIG. 21 is a schematic view of an illustration of a boiler, steam drive DCSG, solid removal and Mechanical Vapor Compression distillation facility for generating distilled water in the boiler for steam generation.

FIG. 22 is a graph illustration of a simulation of the process as described in FIG. 2A.

FIG. 23 is another graph illustration of a simulation of the process as described in FIG. 2A.

FIG. 24 is yet another graph illustration of a simulation of the process as described in FIG. 2A.

FIG. 25 is a schematic view of the process of Example 7.

FIG. 26 is a schematic view of the process of Example 8.

FIG. 27 is a schematic view of the process of Example 9.

FIG. 28 is a schematic view of the process of Example 10.

FIG. 29 is a schematic view of the process of Example 11.

FIG. 30 is a graph illustration showing the amount of produced steam as a function of the feed water temperature in the system.

DETAILED DESCRIPTION OF THE DRAWINGS

FIGS. 1, 1A, 1B, 1D, and 1E show the conceptual flowchart of the method and the system.

FIG. 2 shows a block diagram of an embodiment of the invention. Flow 9 is superheated steam. The steam pressure can be from 1 to 150 bar and the temperature can be between 150° C. and 600° C. The steam flows to enclosure 11, which is a SD-DCSG. Contaminated produced water 7, possibly with organic contaminates, and suspended and dissolved solids, is also injected into enclosure 11 as the water source for generating steam. The water 7 evaporates and is transferred into steam. The remaining solids 12 are removed from the system. The generated steam 8 is at the same pressure as that of the drive steam 9 but at a lower temperature because a portion of its energy was used to drive the liquid water 7 through a phase change. The generated steam is also at a temperature that is close to the saturated temperature of the steam at the pressure inside enclosure 11. The produced steam can be further treated 13 to remove carry-on solids, reducing its pressure and possibly removing additional chemical contaminates. Then the produced steam is injected into an injection well for EOR.

FIG. 2A shows a schematic of a vertical SD-DCSG. Dry steam 9 is injected into vessel 11 at its lower section. At the upper section, water 7 is injected 3 directly into the up-flow stream of dry steam. The water evaporates and is converted to steam at a lower temperature but at the same pressure. Contaminates that were carried on with the water are turned into solids and possibly gas (if the water includes hydrocarbons like naphtha). The produced gas, mainly steam, is discharged from the SD-DCSG at the top. To prevent carried-on water droplets, demister packing 5 can be used at the top of SD-DCSG enclosure 11. The solids 12 are removed from the system from the bottom 1 of the vertical enclosure where they can be disposed of or treated.

FIG. 2B shows a block diagram of the invention. This figure is similar to FIG. 2 but contains an additional solids removal system as described in Block 15. Block 15 can include any commercially available Solid-Gas separation unit. In this particular figure, cyclone separator 19 and electrostatic separation are represented. High temperature filters, that can withstand the steam's temperature, possibly with a back-pressure cleanup system, can be used as well. The steam flow leaving the SD-DCSG can include solids from the contaminate water 7. A portion of the solids 12 can be recovered in a dry or wet form from the bottom of the steam generation enclosure 11. The carry-on solids 14 can be recovered from the gas flow 8 in a dry form for disposal or for further treatment.

FIG. 2C is another embodiment of a reaction chamber apparatus of a high-pressure steam drive direct contact steam generator of the present invention. A similar structure can be used with DCSG that uses combustion gas as the heat source to convert the liquid water into steam. A counter-flow horizontally-sloped pressure drum 10 is partially filled with chains 11 that are free to move inside the drum and are internally connected to the drum wall. A parallel flow design can be used as well. The chains increase the heat transfer and remove solids build-up. Any other design that includes internal embodiments that are free to move or that are moving with the rotating enclosure and continually lifting solids and liquids to enhance their mixture with the flowing gas can be used as well. The drum 10 is a pressure vessel which is continually rotating, or rotating at intervals. At a low point of the sloped vessel 10, hot dry steam 8 is generated by a separate unit, like the pressurized boiler (not shown), and is injected into the enclosure 8. The boiler is a commercially available boiler that can burn any available fuel like natural gas, coal, coke, or hydrocarbons such as untreated heavy low quality crude oil, VR (vacuum residuals), asphaltin, coke, or any other available carbon or hydrocarbon fuel. The pressure inside the rotating drum can vary between 1 bar and 100 bar, according to the oil underground formation. The vessel is partially filled with chains 10 that are internally connected to the vessel wall and are free to move. The chains 10 provide an exposed regenerated surface area that works as a heat exchanger and continually cleans the insides of the rotating vessel. The injected steam temperature can be any temperature that the boiler can supply, typically in the range of 200° C. and 800° C. Low quality water, like mature tailing pond water, rich with solids and other contaminants (like oil based organics), or contaminated water from the produced water treatment process, are injected into the opposite, higher side of the vessel at section 4 where they are mixed with the driving dry steam and converted into steam at a lower temperature. This heat exchange and phase exchange continues at section 3 where the heavy liquids and solids move downwards, directly opposite to the driving steam flow. The driving steam injected at section 2, which is located at the lower side of the sloped vessel, moves upwards while converting liquid water to gas. The heat exchange between the dry driving steam and the liquids is increased by the use of chains that maintain close contact, both with the hot steam and with the liquids at the bottom of the rotating vessel. The amount of injected water is controlled to produce steam in which the dissolved solids become dry or become high solids concentration slurry and most of the liquids become gases. Additional chemical materials can be added to the reaction, preferably with any injected water. The rotational movement regenerates the internal surface area by mobilizing the solids to the discharged point. The rotating movement can agglomerate the solids into small spheres to increase the solids stability and minimize dust generation. The heat transfer in section 3 is sufficient to provide a homogenous mixture of gas steam and ground-up solids, or high viscosity slurry. Most of the remaining liquid transitions to gas and the remaining solids are moved to a discharge point 7 at the lower internal section of the rotating vessel near the rotating pressurized drum 10 wall. The solids or slurry are released from the vessel 10 at a high temperature and pressure. They undergo further processing, such as separation and disposal.

FIG. 2D shows a schematic of a vertical SD-DCSG. It is similar to FIG. 2A with the following changes: Vessel 11 includes a liquid water 1 bath at its bottom. The water is maintained at a saturated temperature. Saturated water is recycled and dispersed 3 into the up-flow flow of dry steam 9. The dispersed water evaporates into the up-flowing steam. Contaminates that were carried on with the water are turned into solids and possibly gas (if the water includes hydrocarbons). The produced gas, mainly steam, is discharged from the SD-DCSG at the top. A portion of the saturated water 1 is dispersed at the up-flow stream of dry steam. The water evaporates and is converted to a lower temperature steam. Solids are carried with the up-flow gas 8. Over-sized solids 12 can be removed from the system from the bottom 1 of the vertical enclosure in a slurry form for further treatment.

FIG. 2E shows a schematic of a SD-DCSG integrated into an open mine oilsands extraction plant for generating the hot extraction water while consuming the Fine Tailings generated by the extraction process. Flow 9 is superheated steam. The steam flows to enclosure 11 which is a SD-DCSG. Fine Tailings (FT) contaminated produced water 7, is also injected into enclosure 11 as the water source for generating steam. The water component 7 evaporates and is transferred into steam. The remaining solids 12 are removed from the system. The generated steam 8 is at the same pressure as that of the drive steam 9 but at a lower temperature because a portion of its energy was used to drive the liquid water 7 through a phase change. The generated steam is also at a temperature that is close to (or slightly higher than) the saturated temperature of the steam at the pressure inside the enclosure 11. The produce steam is fed into a heat exchanger/condenser 13. In FIG. 2E, a non-direct heat exchanger is described. A direct heat exchanger can be used as well. The produced steam condensation energy is used to heat the flow of cold extraction process water 52 to generate a hot process water 52A flow at a temperature of 70-90° C. The produced hot process water can be used in Block A for tarsands extraction. The hot condensate 10 that is generated from steam flow 8 can be added to the process water 52A or used for other processes as a water source for a High Pressure steam boiler, as an example. In case that Non-Condensed Gases (NCG) were generated 17, they are recovered for further use. (For FT 9 that contains low levels of organics, low amounts of NCG will be generated. With the use of direct contact heat exchange between the process water 52 and the produced steam 8 at 13 (not shown), the low levels of NCG will be dissolved and washed by the large amount of process water 14). Block A is a typical open mine extraction oilsands plant as described, for example, in Block 5 in FIG. 8. Flow 7 is fine tailings generated during the extraction process. Flow 14 is additional fine tailings from other sources, like MFT from a tailing pond (not shown). The driving steam 9 can be generated by compressing and heating a portion of the generated steam, as described in FIG. 3 (not shown).

FIG. 2F shows a SD-DCSG with a non-direct heat exchanger to heat the process water and with the combustion of the NCG hydrocarbons as part of generating the driving steam. FTor MFT 7 are injected into a SD-DCDG. In FIG. 2F, a vertical fluid bed SD-DCSG is schematically represented. Any other SD-DCSG can be used as well, like the horizontal SD-DCDG presented in FIGS. 3A, 3B, 3C or any other design. The FT 7 are mixed with the dry super-heated steam flow 9 that is used as the energy source to transfer the liquid water phase in flow 7 to gas (steam) phase by direct contact heat exchange. The FT 7 solids are removed in a stable form 12 where they can be economically disposed of and can support traffic. The produced steam 8 is condensed in a non-direct heat exchanger/condenser 13. The water condensation heat is used to heat the extraction process water 14. With some tailings types, NCG (Non Condensed Gases) 17 are generated due to the presence of hydrocarbons, like solvents used in the froth treatment or oil remains that were not separated and remained with the tailings. The NCG 17 is burned, together with other fuel 20 like natural gas, syngas or any other fuel. The combustion heat is used, through non-direct heat exchange, to produce the superheated driving steam 9 used to drive the process. The amount of energy in the NCG hydrocarbons 17 recovered from typical oilsands tailings, even that from a solvent froth treatment process, is not sufficient to generate the steam 9 to drive the SD-DCSG. It can provide only a small portion of the process heat energy used to generate the driving steam 9. One option is to use a standard boiler 18 designed to generate steam from liquid water feed 19 from a separate source. Another option is to use a portion of the produced steam condensate 23 as the liquid water feed to generate the driving steam 9. The condensate will be treated to bring it to BFW quality. Treatment units 24 are commercially available. Another option to generate the driving steam 9 is to recycle a portion of the produced steam 8. The recycled produced steam 21 is compressed 22. The compression is needed to overcome the pressure drop due to the recycle flow and to generate the flow through the heater 18 and the SD-DCSG 11. The compression can be done using a steam ejector with high pressure additional steam or with the use of any available low pressure difference mechanical compressor. The recycled produced steam 21—possibly after additional cleaning, like wet scrubbing, to remove contaminates like silica—is indirectly heated by combustion heater 18.

FIG. 3 is an illustration of one embodiment of the present invention without using an external water source for the driving steam. SD-DCSG 30 includes a hot and dry steam injection 36. The steam is flowing upwards where low quality water 34 is injected to the up-flow steam. At least a portion of the injected water is converted into steam at a lower temperature and is at the same pressure as the dry driving steam 36. The generated steam can be saturated (“wet”) steam at a lower temperature than the driving steam. A portion of the generated steam 32 is recycled through compressing device 39. The compression is only designed to create the steam flow through heat exchanger 38 and create the up flow in the SD-DCSG 30. The compressing unit 39 can be a mechanical rotating compressor. Another option is to use high pressure steam 40 and inject it through ejectors to generate the required over pressure and flow in line 36. Any other commercially available unit to create the recycle flow 36 can be used as well. The produced steam, after its pressure is slightly increased to generate the recycle flow 36, and possibly after the contaminates are removed in a dry separator or wet scrubber to protect the heater, flows to heat exchanger 38 where additional heat is added to the recycled steam flow 32 to generate a heated “dry” steam 36. This steam is used to drive the SD-DCSG as it is injected into its lower section 30 and the excess heat energy is used to evaporate the injected water and generate additional steam 31. The heat exchanger 38 is not a boiler as the feed is in gas phase (steam). There are several commercial options and designs to supply the heat 37 to the process. The produced steam 31 or just the recycled produced steam 32 can be cleaned of solids carried with the steam gas by an additional commercially available system (not shown). The system can include solids removal; this heat exchanger can be any commercially available design. The heat source can be fuel combustion where the heat transfer can be radiation, convection or both. Another possibility can be to use the design of the re-heat heat exchanger typically used in power station boilers to heat the medium/low pressure steam after it is released from the high pressure stages of the steam turbine. This option is schematically shown on FIG. 3. Typically, the re-heater 40 supplies the heat to operate the second stage (low pressure) steam turbine. Accordingly, the feed to the re-heater is saturated or close to saturated medium-low steam. As such, this minimizes the re-heater design conversion changes to heat the generated steam 31 for generating the superheated steam 36. If an existing steam power plant is used, the supercritical high-pressure steam can be used to drive a high pressure steam turbine, while the remaining heat can be used through the re-heater to provide the heat 37 to drive the steam generation facility. The advantages of this configuration: a high pressure steam turbine has smaller dimensions and Total Installed Cost (TIC) compared to medium/low pressure steam turbine per energy unit output.

FIG. 3A is an illustration of one embodiment of the present invention. It is similar to FIG. 3 with the use of a rotating SD-DCSG. The driving superheated (“dry”) steam 36 is injected into a rotating pressurized enclosure 30. The rotating SD-DCSG enclosure consumes liquid water 34, possibly with solid and organic contaminations, and generates lower temperature steam 31 and solid waste 35 that can be disposed of in a landfill and can support traffic. The rotating SD-DCSG 30 is described in FIG. 2C.

FIG. 3B is an illustration of a parallel flow SD-DCSG. It is similar to FIG. 3A with the use of a parallel flow direct contact heat exchange between the liquid water and the dry steam. The driving superheated (“dry”) steam 36 is injected into rotating pressurized enclosure 30. Liquid water 34, possibly with solid and organic contaminations, is injected together with the driving steam at the same side of the enclosure. Lower temperature produced steam 31 and solid waste 35 can be disposed of in a landfill and can support traffic. The driving superheated steam is generated by recycling a portion of the produced steam 32. The recycled produced steam is compressed to overcome the pressure loss and generate the required flow. It is indirectly heated 38 and recycled back 36 to the SD-DCDG 30.

FIG. 3C is an illustration of a SD-DCSG with a stationary enclosure and an internal rotating element. Super heated driving steam 36 is injected into enclosure 30. Low quality liquid water with high levels of contaminates, like Fine Tailings generated by an open mine oilsands extraction plant, is injected into the enclosure. The enclosure is pressurized. The liquid water is evaporated to generate produced steam 33. The produced steam 33 is at a lower temperature as compared to the superheated driving steam; it is close to the saturated point due to the additional water that was evaporated and converted to steam. The solids that were introduced with the low quality liquid water 34 are removed in a stable form where they can be disposed of in a land fill and can support traffic. To increase the direct contact heat transfer within the enclosure 30, moving internals are used. The internals can be any commercially available design that is used to mobilize slurry and solids in a cylindrical enclosure. A rotating screw 31 can be used. The rotating movement 32 is provided through a pressure sealed connection from outside the enclosure. The screw mobilizes the solids and drives them to the discharge location where they are discharged from the pressurized enclosure.

FIG. 3D is an illustration of a modification of FIGS. 3C and 3B for a steam drive Non-Direct contact steam generator where the heat is supplied by steam to a heated stationary external enclosure and an internal rotating element to mobilize the evaporating low quality solids rich water, like MFT. The process includes generating or heating steam 36 through indirect heat exchange (not shown). The generated steam energy 36 is used to indirectly gasify liquid water 34 with solids and organic contaminates, like fine tailings, so as to transfer said liquid water from a liquid phase to a gas phase 33. Solids 35 are removed to produce solids-free gas phase steam 33. The produced steam can be further condensed to generate heat and water for oil production (not shown). The hot driving steam (there is no need to usie dry superheated steam as the driving steam) 36 is heating enclosure 30. Low quality liquid water with high levels of contaminates, like Fine Tailings generated by an open mine oilsands extraction plant, are injected into the enclosure. The enclosure is pressurized. The liquid water evaporates due to a non-direct heat transfer from the enclosure 30 to generate produced steam 33. The solids that were introduced with the low quality liquid water 34 are removed in a stable form 35 where they can be disposed of in a land fill and can support traffic. To increase the direct contact heat transfer within the enclosure 30 and to mobilize the solids and slurry, moving internals are used. The internals can be any commercially available design that is used to mobilize slurry and solids in a cylindrical enclosure. The rotating movement can agglomerate the solids into small spheres to increase the solids stability and minimize dust generation. A rotating screw 31 can be used. The rotating movement 32 is provided through a pressure sealed connection from outside the enclosure. The screw mobilizes the solids and drives them to the discharge location where they are discharged from the pressurized enclosure. Any other design (like double screws, lifting scoops, or chains) can be used as well. Condensed water 36A from the condensing driving steam 36 is recycled to the point where it can be re-heated for generating additional driving steam 36 or for any other use.

FIG. 3E shows a parallel flow and a counter flow steam drive direct contact steam generation system. In the parallel flow system 1 liquid water 7, possibly with high levels of suspended and dissolved solids like fine tailings, produced water, evaporator brine, brackish water, produced gas, carbons, hydrocarbons or any available water feed possibly with high levels of contaminates, is fed into a longitude enclosure 5. Superheated dry steam 6 is also fed into the same longitude enclosure 4 at the same side where the low quality water is injected and where the two flows, the liquid and the gas, are mixed in direct contact. To enhance the mixing and mobilize the generated slurry or solids, mechanical energy is supplied to the enclosure. One possible, simple way to supply the mechanical energy is by a longitudinal rotating element 9. There are several designs for such a rotating element that can include spirals, scoops, scrapers or any other commercially available design. It is possible to use a single rotating unit 11 in a circle enclosure 10. It is also possible to use double rotating units 13 and 14 in an oval enclosure 12 where the multiple rotating units can enhance the mixing and the removal of solids deposits. In the parallel system, the produced steam 3 is discharged with the solids rich slurry or solids at the enclosure end. To allow efficient heat transfer duration, the enclosure length is longer than its diameter, typically the length L is at least twice the diameter D. The steam-solids mixture is further separated (not shown). In the counter flow system 15 the low quality liquid flow 18, similar to flow 7 in the parallel flow system 1, is fed into a longitude enclosure with an internal rotating element to introduce mechanical energy into the enclosure. The superheated driving steam 16 is introduced at the opposite end of the enclosure where it is mixed with the flow of liquids 18. The heat energy in the super heated driving steam 16 is directly transferred to the liquid water to generate steam. The slurry or solids are transferred by rotating auger, possibly with a spiral in the opposite direction, to the driving steam 16 flow and discharged from the longitude system at 17. It is also possible to connect the parallel flow and the counter flow systems to each other where the discharge from the first system 3 or 17 still contains significant levels of liquids, possible in a slurry form, which is fed into the second system 18 or 7.

FIG. 3F shows a direct contact steam generating system as shown in FIG. 3E with solids separation. The direct contact parallel flow steam generator 1 is similar to FIG. 3E where the solid contaminates are removed from the steam flow in a separator 10 through a de-pressurized collection hopper system that includes valves 12 and 14, de-pressurized enclosure 13, and solids discharge 15. The enclosure 10 can include internals to generate cyclone separation or any other commercially available solids separation design. A commercially available gas-solid separation package can be added to the discharged flow 20 to remove solids from the gas stream (not shown). The solids removed from stream 20 can be discharged through the de-pressurized hopper system 13.

FIG. 3G is a steam drive direct contact steam generator apparatus. It includes a vertical enclosure 2 with steam injection points 6 arranged around the enclosure wall. The injection flows 5, 9 are arranged to enhance the mixing flow within the vessel and to protect the enclosure wall from solids build-up. Liquid water 7 injected into the upper section 1 of the enclosure. The water injection can include a sprayer to disperse the water and enhance the mixture between the liquid water and the steam. The injected water can be low quality produced water or water from any other source, such as tailings pond water. The injected water 7 can include dissolved or suspended solids as well as any other carbon or hydrocarbon contamination. The water is injected at the upper section—section C. Super heated dry steam 5 is injected at section B located below the water injection 7. The dry steam is injected substantially perpendicular to the enclosure wall, possibly with an angle to enhance the mixture of the liquid water and the steam and to minimize the contact between the liquid water and the enclosure wall which can prevent build up of solids deposits on the enclosure wall. The solids rich contaminates 4 that were introduced into the system with the water feed 7, after most of the liquid water evaporates into steam, are collected at the bottom of the enclosure 3 and removed from the system. The injected steam 9 can be dispersed by a nozzle 10 close to the enclosure wall in such a way that part of the steam flow will be spread and then will generate a flowing movement that will reduce the potential contact between the water feed 7 and the enclosure wall. The injected steam 5 and the water feed that was converted into steam is released in a gas flow 8 from the upper section of the enclosure 1. The steam flow 8 can flow through a demister and a separator that can be located internally in section C or externally to remove water droplets and solids remains (not shown). The pressure of the produced steam 8 is similar to the pressure of the superheated driving steam 5, except for a small difference to generate the up flow movement, and its temperature is closer to the saturated temperature at the particular enclosure pressure due to the evaporation of the feed water 7.

FIG. 3H is another configuration of a steam drive direct contact steam generator apparatus. Sections A and B are described in FIG. 3E. Superheated dry steam 6 is injected into Section B. Any liquid water that flows into the up-flow chamber of Section B is converted into steam. Contaminates, mainly solids, that were carried with the feed water 3 are removed from the bottom of the enclosure 9 from Section A. The superheated steam 6 flows from Section B into Section C located above B. Section C includes a fluid bed 4. This fluid bed includes liquid, solids and slurry supplied with the feed water 3. Additional free moving bodies, like sand, round metal particles, or round ceramic particles can be added to the fluid bed 4 to enhance the heat transfer between the up flowing steam and the slurry from the water feed 3. The fluid bed in Section C can include additional steam injectors (not shown) to mobilize the solids and prevent solids build-ups that can block the fluid bed. A direct steam injection into Section C can be done in intervals in strong bursts to mobilize the fluid bed and remove build-ups. A mechanical means to create movement within the fluid bed can be used as well, possibly in intervals, in case the steam up flow from Section B is not sufficient to prevent solidifications within the fluid bed 4 and remove build-ups (not shown). Solids can also be removed directly from 4, from the fluid bed section. The produced steam 1 from water flow 3 and from the driving super heated steam 6 is used for oil extraction or for other usages. In the case that the low quality water feed 3 contains hydrocarbons, a portion of the hydrocarbons will be recovered with the produced steam and injected into the underground formation for heavy oil recovery. The produced steam 1 can be further treated in a commercially available demister and gas-solids separator to remove water droplets or flying solids carried-on with the generated steam flow.

FIG. 3I is a steam drive direct contact steam generator apparatus. Superheated steam 7 is injected into a vertical enclosure at its lower section. Liquid water 3 is injected into the enclosure above the steam injection area. The water injection can include a sprayer to disperse the water and enhance the mixture between the liquid water 3 and the steam 7. The injected water can be low quality SAGD produced water, boiler blow-down, evaporator brine or water from any other source, such as open mine tailings pond water. The injected water 3 can include dissolved or suspended solids as well as any other carbon or hydrocarbon contamination. To enhance the mixture of the steam and the water and to remove solids, an internal structure 4 is placed in between the steam injection section and the water injection section. Internal 4 can include a moving bed or any other configuration of free moving elements, like chains 5, that can remove solids build-ups from the supplied water 3. Mechanical energy can be introduced into the internal structure 4 to generate continuous or interval movement between its parts or between the internal structure and the enclosure. Vibration movement can be introduced to the bottom structure 6 to prevent solids build-ups. The solids 9 are collected and removed from a cone 8 in the enclosure bottom. One option is to generate relative movement between the upper bed structure 4 and the lower bed structure 6 and the enclosure wall. Any commercially available design for moving bed internals can be used as well. The generated steam 2 is released from the upper section of the enclosure 2. The generated steam 1, can be further cleaned in a dry or wet scrubber and used in enhanced oil recovery by injecting it underground, like in SAGD or CSS, or to heat water in an open mine extraction process.

FIG. 3J is a steam drive direct contact steam generator with an internal wet scrubber that generates additional wet solids free steam. Superheated steam 10 is injected into Section A of the vertical enclosure. Liquid water 5 is injected and dispersed above the dry steam injection point. A fluid bed, possibly with additional solid particles 9, is supported above the steam injection area 10 in Section A. The fluid bed increases the heat transfer between the up-flowing steam 10 and the dispersed water 5. Solids 12 are remove from the bottom of Section A for disposal or further treatment. The bottom section of the fluid bed can move by mechanical means to generate a moving or vibrating bed. Solids can be recovered from the fluid bed at Section A to maintain a constant solids level. The up-flow generated steam, possibly with solids particles, flows into section B. In this section, the up flowing steam is scrubbed by liquid saturated water 7. To generate the contact between the liquid saturated water and the steam, a liquid bath 7 can be used where the steam is forced (due to pressure differences) through the liquid water. Another option is to continually recycle hot saturated liquid water 4 and spray it 2 into the up flowing steam, thereby scrubbing any solids remains and generating additional steam. In Figure J, both options are presented (the liquid bath is combined with the water sprayers 2) however it is possible to use only one of the presented options. If only the liquid bath 7 is used, the feed water 3 will be supplied to the liquid bath as a make-up water (not shown) to replace the water that was evaporated in Section B and water 5, ensuring any solids are scrubbed, from Section B that is supplied to Section A and evaporated there. The generated solids free saturated steam from Section B flows into Section C. Section C can include a demister to separate any droplets carried on with the up-flow steam (not shown). The produced solids free steam can be used for oilsands bitumen recovery with any commercial oilsands plant that requires steam.

FIG. 3K is an illustration of one embodiment of the present invention. An up-flow direct contact steam generator, as described in FIG. 3H or 3I, is used to generate steam 9 from superheated steam and liquid water 8. Additional designs for direct contact steam generators, like FIGS. 2C, 2D and 2E can be used as well. The produced steam 9 flows to an external wet scrubber that also generates additional steam. The produced steam is mixed with liquid water 11, possibly by circulating system 12 with sprayers for dispersing the water 3, where any solids remains are scrubbed with the water droplets while wet steam is generated. Liquid water 8 at a saturated temperature and pressure is continually recycled and injected into the steam generator 2. Water feed, possible with high levels of contaminates, is fed into the system. Portion 14 of the produced steam 13 can be used for any industrial use, such as for oil recovery or for steam use in the chemical industry. The other portion 15 of the produced steam is recycled and used to produce dry superheated steam 24 to operate the direct contact steam generator 1. The recycled produced steam 15 can be further filtered in any commercially available filter package to remove contaminates like gas silica remains. Water and chemicals 17 can be used in any gas treated commercial package 16. The steam 19 is then compressed to recover the pressure drops in the recycled piping and equipment and then flows to steam heater. Depending on the mechanical compressing system 20 requirements, some heat can be added to flow 19 prior to the compression. Another option is to use a steam ejector 20 with high pressure steam feed to generate the recycle flow 21. The steam flow 21 is further heated in any commercially available heating system 23. Heat flow 22 increases the steam temperature 24 to generate a dry, superheated steam flow that is injected back into the direct contact steam generator as the driving steam.

FIG. 4 is an illustration of one embodiment of the present invention, where the generated steam 44 is saturated and is washed by saturated water in a wet scrubber 40 where additional steam is generated. BLOCK 1 includes the system described in FIG. 3 where BLOCK 32 can include solids removal as a means to remove solid particles from the gas (steam) flow. BLOCK 3 generates steam 33 and stable waste 35. The generated steam 33 can contain carry-on solid particles and contaminates that might create problems with corrosion or solids build ups in the high temperature heat exchanger. One way to remove the solid contaminates is by the use of a commercially available solid-gas separation unit, as described in FIG. 2B, or with any other prior art solids removal method. However, there is an advantage to wet scrubbing of solids and possibly other gas contaminates. To improve the removal of the solids and other contaminates, the steam 33 is directed to a wet scrubber. In one embodiment, the wet scrubber generates the liquid water for its operation. This is done by an internal heat exchanger that recovers heat from the steam and generates condensate water. The condensate liquid water is used for scrubbing the flowing steam in vessel 40. The condensate is recycled 41 and used to wash the steam and is then used as a means to improve the heat transfer. Low quality water from the oil-water separation process, fine tailing water from tailings ponds or from any other source is pre-heated through heat exchanger 42 while recovering heat from the produced steam 34 generated by the SD-DCSG 30. The condensate is recycled in the wet scrubber to wash the steam. Additional chemicals can be added to the condensate to remove gas contaminates. A portion of the condensate with the solids and other contaminates 43 is removed from vessel 40 to maintain the contamination concentration of the condensate so it is constant. Additional low quality water 47A can be added to the SD-DCSG without pre-heating so as to prevent excessive cooling of the produced steam 33 and to prevent the generation of excessive condensate. The generated steam, after going through the wet scrubber, is a clean and saturated (“wet”) steam. A portion of the clean steam 45 is directed through heat exchanger 38 to generate “dry” steam to drive the SD-DCSG 30 with sufficient thermal energy to convert the low quality water feed 34 into steam. The flow through the heat exchanger and inside the vessel 30 is generated by any suitable commercial unit that can be driven by mechanical energy or can be a jet energy driven compression unit. The produced clean saturated steam 46 can be injected into an underground reservoir, like SAGD, for oil recovery, and it can also be used for heating process water for tar separation or for any other process that consumes steam.

FIG. 5 is a schematic diagram of one embodiment of the invention that generates wet scrubbed, clean saturated steam. BLOCK 1 includes a SD-DCSG 30 as previously described. The generated steam 31 can be cleaned of solids in commercial unit 32, previously described. Low quality water 34, like MFT, produced water or water from any other available source, can be injected into the SD-DCSG 30. Solids 35 carried by the water 34 are removed. The SD-DCSG 30 is driven by superheated (“dry”) steam that supplies the energy needed for the steam generation process. The dry steam 36 is generated by a commercially available boiler as described in BLOCK 4. Boiler Feed Water (BFW) 49 is supplied to BLOCK 4 for generating the driving steam. The boiler facility can include an industrial boiler, OTSG, COGEN combined with gas turbine, steam turbine discharge re-heater or any other commercially available design that can generate dry steam 36 and that can drive the SD-DCSG 30. In the case where the boiler consumes low quality fuel, like petcoke or coal, commercially available flue gas treatment will be used. There is a lot of prior art knowledge for the facility in BLOCK 4 as it is similar to the facility that is used all over the world for generating electricity. The generated steam from the SD-DCSG 37 is supplied to BLOCK 2, which includes a wet scrubber. The wet scrubber 50 can contain chemicals like ammonia or any other chemical additive to remove contaminates. The exact chemicals and their concentration will be determined based on the particular contaminates of the low quality water that is used. The contamination levels are much lower than in direct fired DCSG where the water is directly exposed to the combustion products, as described in my previous patents. Liquid water 48 is injected to the wet scrubber vessel 50 to scrub the contaminates from the up-flowing steam 37. Liquid water 51, that includes the scrubbed solids, is removed from vessel 50 and recycled back to the SD-DCSG 30 together with the feed water 34. Depending on the particular feed water quality 34, it can be used in the scrubber. In that case stream 48 and 34 will have the same chemical properties and be from the same source. The scrubbed generated steam 45 generated at BLOCK 2 can be used for extracting and producing heavy oil or can be used for any other use.

FIG. 5A is an illustration of one embodiment of the invention where a portion of the driving steam water is internally generated. The embodiment is described in FIG. 5 with the following changes: BLOCK 3 was added and connected to BLOCK 2. This block includes a direct contact condenser/heat exchanger 40 that is designed to generate hot (saturated) boiler feed water 46 and possibly saturated steam 44. The saturated steam 45 from scrubber 50 flows into the lower section of a direct contact heat exchanger/condenser 40 where BFW 42 is injected. From the direct contact during the heating of the BFW, additional water will be condensed generating additional BFW 46. A portion of the injected and generated water 48 is used in wet scrubber 50 to remove contamination and is then recycled back to the SD-DCSG 30. The additional condensate—clean BFW quality water 49—is used in BLOCK 4 for generating steam. The condensate is hot—it is at the water or steam saturated temperature at the particle system pressure. Addition hot condensate can be generated and recovered from the system as hot process water for oil recovery or for other uses. BLOCK 4 can include any commercially available steam generator boiler capable of producing dry steam 36. In FIG. 5A, a schematic COGEN is described. Gas turbine 62 generates electricity. The gas turbine flue gas heat is used to generate or heat steam through non-direct heat exchanger 61. Typically the produced steam is used to operate steam turbines as part of a combined cycle. At least part of the produced dry superheated steam 36 is used to operate the SD-DCSG 30.

FIG. 5B is a schematic view of the invention with internal distillation water production for the boiler. The illustration is similar to the process described in FIG. 5A with a different BLOCK 3. The low quality water 47 is heated with the saturated, clean (wet scrubbed) steam 45 from BLOCK 2 (previously described). The saturated steam 45 condenses on the heat exchanger 42, located inside vessel 40, while generating distilled water 46. A portion of the distilled water 48 is recycled to the wet scrubber vessel 50 where it removes the solids and generates additional wet steam from the partially dry steam generated in the SD-DCSG 30 in BLOCK 1. Additional distilled water 49, possibly after minor treatment and addition of chemical additives (not shown) to bring it to BFW specifications, is directed to the boiler in BLOCK 4 for generating the driving steam. The system can produce saturated steam 44A or saturated liquid distilled water 44B or both. The produced steam and water are used for oil production or for any other use.

FIG. 5C is a schematic diagram of a method that is similar to FIG. 5B but with a different type of SD-DCSG in Block 1. FIG. 5C includes a vertical stationary SD-DCSG. The dry driving steam 36 is fed into vessel 30 where the low quality water 34 is fed above it. Due to excessive heat, the liquid water is converted into steam. The waste discharge at the bottom 35 can be in a liquid or solid form. BLOCKS 2, 3 and 4 are similar to those in the previous FIG. 5B.

FIG. 6 is a schematic diagram of the present invention which includes a SD-DCSG and an EOR facility like SAGD for injecting steam underground. BLOCK 1 is a standard commercially available boiler facility. Fuel 1 and oxidizer 2 are combusted in the boiler 3. The combustion heat is recovered through a non-direct steam generator for generation of superheated dry steam 9. The combustion gases are released to the atmosphere or for further treatment (like solid particles removal, SOX removal, CO2 recovery, etc.). The water that is fed to the boiler is fed from BLOCK 2, which includes a commercially available boiler treatment facility. The required quality of the supplied water is according to the particular specifications of the steam generation system in use. The dry steam is fed to SD-DCSG 10. Additional low quality water 7 is fed into vessel 11 where the liquid water is transferred to steam due to the excess heat in the superheated driving steam 9. The generated steam 8, possibly saturated or close to being saturated, is injected into an underground formation through an injection well 16 for EOR. The produced emulsion 13 of water and bitumen is recovered at the production well 15. The produced emulsion is treated using commercially available technology and facilities in BLOCK 2, where the bitumen is recovered and the water is treated for re-use as a BFW. Additional make-up water 14, possibly from water wells or from any other available water source, can be added and treated in the water treatment plant. The water treatment plant produces two streams of water—a BFW quality 6 stream as is currently done to feed the boilers, and another stream of contaminated water 7 that can include the chemicals that were used to produced the high quality BFW, oil contaminates, dissolved solid (like salts) and suspended solids (like silica and clay). The low quality flow is fed to the SD-DCSG 10 to generate injection steam.

FIG. 6A is a schematic flow diagram of the integration between SD-DCSG and DCSG that uses the combustion gas generated by the pressurized boiler. BLOCK 1 includes a DCSG with non-direct heat exchanger boiler as described in my previous applications. Carbon or hydrocarbon fuel 2 is mixed with an oxidizer that can be air, oxygen or oxygen enriched air 1 and combusted in a pressurized combustor. Low quality water 12 discharged from the SD-DCSG is fed into the combustion unit to recover a portion of the combustion heat and to generate a stream of steam and combustion gas mixture 4. The solid contaminates 18 are removed in a solid or stable slurry form where they can be disposed of. The steam and combustion gas mixture 4 is injected into injection well 17 for EOR. Injection well 17 can be a SAGD “old” injection well where the formation oil is partly recovered and large underground volumes are available, as well as where corrosion problems are not so crucial as, for example, the well is approaching the end of its service life. Another, preferable option for using the steam and combustion gas mixture is to inject it into a formation that is losing pressure and needs to be pressurized by the injection of addition non-condensable gas, together with the steam. A portion of the combustion energy is used to generate superheated dry steam in a boiler type heat exchanger 5. The generated steam 9 is driving the SD-DCSG 10. The water for the non-direct boiler 5 is supplied from the commercially available water treatment plant in BLOCK 2. Low quality water from BLOCK 2 is fed directly into the SD-DCSG where it is converted into steam. In this scheme, the conversion is only partial as the discharge from 10 is in a liquid form 12. The liquid discharge 12 is directed to the combustion DCSG to generate an overall ZLD (Zero Liquid Discharge) facility. The steam from the SD-DCSG 8 is injected into an underground formation through an injection well 16 for EOR.

FIG. 6B described a direct contact steam generator with rotating internals, dry solids separation, wet scrubber and saturated steam generator. Super heated driving steam 13 is fed into a direct contact steam generator where it is mixed with water, possibly with contaminates. The excessive heat energy in the steam evaporates the water to generate additional steam. Solids 6 are removed from the system in a dry or slurry form. The produced steam is treated in a commercially available gas treatment unit in Block B. An inlet demister, to remove carried-on liquid droplets, can be incorporated in Block B. Any commercially available unit to remove solids and contaminates can be used, such as cyclone solids removal system schematically described in B1, a high temperature filter B2, an electrostatic precipitator B3 or a combination of these with any other commercially available design. The solids are removed in a dry form are added to the solids removed from the steam generator 14. The solids lean flow 5 is fed into a saturated steam generator and a wet scrubber 2. Liquid water is recycled and dispersed into the flowing steam. A portion of the liquid water evaporates. The water droplets remove contaminates. Chemicals like anti-foaming, flocculants, Ph control and other commercially available chemicals to control the process efficiency and prevent corrosion can be added to the recycled water 11. Make-up water 10 can be added to the system to replace the water converted into steam and to replace the recycled water with contaminates, back to the feed water 13. The scrubbed solids free generated steam 8 is supplied from the system for other usages.

FIG. 6C includes SD-DCSG and heavy oil extraction through steam injection. Emulsion of steam, water bitumen and gas is produced from a production well 10, like a SAGD well. The produced flow 1 is separated in a separator 3 (located in BLOCK A) to generate water rich flow 5 with contaminates like sand, and hydrocarbons rich flow 4. There are a few commercial designs for separators that are currently used by the industry. Chemicals can be added to the separation process. The hydrocarbon rich flow 4 is further treated in processing plant at BLOCK B. Flow 4 is further separated into the produced bitumen, usually diluted with light hydrocarbons to enhance the separation process and to reduce the viscosity which allows the flow of the bitumen in the transportation lines. In BLOCK B, the produced water that remained with the flow 4 is de-oiled and used, usually with make-up water from water wells, for generating super-heated steam 6. The water rich flow 5, at a high temperature that is close to the produced emulsion temperature, is pumped into a SD-DCSG 7 where it is mixed with the dry superheated steam 6 to generate additional steam for injection 2. Light hydrocarbons in flow 5 evaporate due to the heat required to generate hydrocarbons that are injected with the injection steam 2 into the underground formation 11. Additional solvents can be added to the injection steam 2—it is a common practice to add solvents to the generated steam for injection. It is known that hydrocarbons that are mixed with the steam can improve the oil recovery. The SD-DCSG 7 includes rotating internals to enhance the mixture between the two phases and to mobilize the generated slurry and solids. The solids 8 are removed from the system for landfill disposal 13 or for any other use. The heat energy within flow 5 from separator 3 increases the quantity of steam generated in SD-DCSG 7 and by that improves the overall thermal efficiency of the system. The generated steam 2 is injected, possibly after additional contaminate removal treatment and pressure control (not shown), into an injection well 11 for EOR. The SD-DCSG 7 is a parallel flow steam generator, as described by Unit 1 in FIG. 3E, however, any other SD-DCSG design like the counter flow SD-DCSG as described by Unit 15 in FIG. 3E, or the rotating or fluid bed units as described in drawings 2C, 2D and 3C-3J can be used as well.

FIG. 6D includes a SD-DCSG similar to the system in 6C, where the superheated driving steam is generated by recycling and re-heating the produced steam generated by the SD-DCSG 7. A mixture of steam, water, bitumen and gas is produced from a production well 10, like a SAGD well. The produced flow 1 is separated in a separator 3 located in BLOCK A to generate water rich flow 5 and hydrocarbons rich flow 4. There are a few commercial designs for separators that are currently used by the industry. Chemicals can be added to the separation process. The hydrocarbon rich flow is further treated in a processing plant at BLOCK B. The water rich flow 5, possibly with hydrocarbons and other contaminates like sand, is at a high temperature that is close to the produced emulsion temperature. The heat energy within flow 5 increases the quantity of steam generated in SD-DCSG 7 for a given amount of superheated driving steam 6. Flow 5 is pumped into a SD-DCSG 7 where it is mixed with dry superheated steam 6 to generate additional steam 18. Any available design for mixing the water and the steam to generate additional steam and solids or slurry discharge can be used as well. The solids or slurry 8 are removed from the system for landfill disposal 13 or for any other use. The produced steam 18 is split into two flows—flow 2 of the generated steam 18 is injected, possibly after additional contaminate removal treatment and pressure control (not shown), into an injection well 11 for EOR. The other part of flow 18, flow 12, is recycled back to BLOCK C. Depending on the recycled steam quality and the feed requirements of the compressing and heating units, it can be pre-cleaned by any commercially available cleaning technologies. The recycled produced steam is compressed by a mechanical compressor, steam ejector or any other available unit 14 and then indirectly heated by heat flow 15 to generate a super heated driving steam flow 6. The heating can be done with any available heating unit that can heat steam, possibly with hydrocarbons remains. Electrical heaters for small units, carbon (like coal, petcoke etc.) combustion units for large scale, or hydrocarbon fired (like natural or produced gas, bitumen etc.) for medium and large size units can be used as facility 16 for heating the produced steam, possibly with small amounts of hydrocarbon gas to generate the dry, superheated driving steam 6. The superheated driving steam 6 is injected to the SD-DCSG 7 where it is mixed with the produced water 5.

FIG. 6E is a schematic view of the SD-DCSG with similarities to FIG. 6D and with externally supplied make-up HP steam. A mixture of steam, water, bitumen and gas is produced from a production well 10, like a SAGD well. The produced flow 1 is separated in a separator 3 located in BLOCK A to generate water rich flow 5 and hydrocarbons rich flow 4. There are a few commercial designs for separators that can be used. Chemicals can be added to the separation process. The hydrocarbon rich flow is further treated in a commercially available oil and water processing plant at BLOCK B. There are commercially available technologies and designs for such plants—some are used by the oilsands thermal insitue industry (like SAGD processing plant). The water rich flow 5, possibly with hydrocarbons and other contaminates like sand, is at a high temperature close to the produced emulsion 1 temperature. Flow 5 is pumped into a SD-DCSG 7 where it is mixed with dry superheated steam 6 to generate additional steam 18. The SD-DCSG is a counter flow design as described by Unit 15 in FIG. 3E. Any available design for mixing the water and the steam to generate additional steam and solids rich water can be used as well. The solids or slurry is removed from the system through separator 20 and de-compression system 21 in a stable form 22. The produced steam 18 is split into two flows—flow 2 of the generated steam 18 is injected, possibly after additional contaminate removal treatment and pressure control (not shown), into an injection well 11 for EOR or for any other usage in the mining industry or in any other industry that required large quantities of steam. Additional solvents can be added to the injection steam 2—it is a common practice to add solvents to the generated steam for injection. The other part from flow 18, flow 12, is recycled to be re-heated and used as the superheated driving steam. In non-direct contact heater 16, additional heat Q is added to the steam flow 12 to generate superheated dry steam 13. The heating can be done with any available heating facility. This superheated steam is compressed with the pressure energy from High Pressure (HP) make-up steam 6 generated in BLOCK B. The make-up steam is produced from the produced water that remains in flow 4. The produced water is treated in the process facility in BLOCK B that includes de-oiling and possibly de-mineralization before being used in a commercially available high pressure boiler or OTSG for generating high pressure steam 6. Additional make-up water 24 is usually required to compensate for the water loss in the formation and for the waste water rejected from the water treatment facility in BLOCK B. The make-up water is usually supplied from a water well 25 or can be from any available water source. Disposal water 23 from the water processing facility in BLOCK B, possibly with oil and solids, can be recycled to the SD-DCSG 7 together with stream 5 as the water feed to 7.

FIG. 6F describes another embodiment of the present invention for generating steam for oil extraction with the use of a steam boiler and steam heater. A mixture 36 of steam, water, bitumen and gas is produced from a production well 32, like a SAGD production well. The produced flow 36 is separated in a separator 33 to separate the produced gas 38 from the produced liquids 37. The produced gas 38 can include reservoir gas, mainly light hydrocarbons and possibly lifting gas, in case lifting gas is used to lift the produced liquids to the surface (not shown). The produced gas is used in the process as lifting gas. It can also used as fuel for the boilers. The produced liquid emulsion 37 is cooled in heat exchanger 34 while heating the boiler feed water 40 to generate pre-heated boiler feed water. The cooled liquid mixture 39, after the produced gas was already removed, is fed into separator 35. Chemicals, sometimes with solvents like light hydrocarbons, can be added to the produced liquid 39 to support the separation process, break the emulsion, and prevent foaming. The separation vessel 35 separates the water liquid 43 from the bitumen 41. The separation process is a well known process within the heavy oil industry. The gas separator reactor 33 and the water-oil separator reactor 35 are commercially available units. Any additional configuration to enhance the gas-water-oil separation can be used as well. The produced oil 41 is further treated in a commercially available process area BLOCK 1 commonly used with the insitue thermal oil recovery industry, like SAGD or CSS. Solvents can be added to the produced bitumen 41 to remove the water remains and other contaminates. BLOCK A includes a commercially available water treatment facility, like evaporators, to generate boiler feed quality water 40. The water feed to the water treatment plant in BLOCK 1 can be from the water remains in flow 41. Additional water can be directed to the water treatment plant from water 43 that was separated in vessel 35. The produced water used as feed to the boiler feed water treatment plant is de-oiled to remove oil traces that can impact the water treatment process in BLOCK 1. Additional make-up water can be added to the process in BLOCK 1 from any other water source, such as water wells. Usually the make-up water does not include organic contaminates so it is easier to treat them with evaporators and other commercially available distillation units. (See Society of Petroleum Engineers paper No 137633-MS Titled “Integrated Steam Generation Process and System for Enhanced Oil Recovery” presented by M. Betzer at the Canadian Unconventional Resources and International Petroleum Conference, 19-21 Oct. 2010, Calgary, Alberta, Canada.) The produced water flow 7, possibly with solids contaminates and oil remains, is mixed with superheated steam 6. Due to the contaminates within the produced water feed 7, a rotating internal 2 is used to enhance the mixture and remove build-ups within enclosure 1. Due to the driving steam's 6 high temperatures (compared to the saturated steam temperature at the system pressure), liquid water from Flow 7 is converted to steam. The amount of water converted is a function of the ratio of the driving steam 6 and the liquid water 7. If disposal wells are available, it is possible to convert only a portion of the water into steam and dispose of the remaining water with the contaminated solids 12 in a disposal well 13. Heat can be recovered from the disposal liquid flow 12 through a heat exchanger (not shown). The produced steam 20 is separated from the disposal flow 12 or 15 in a separation enclosure 10. If disposal wells for disposing fluids are not available, or a ZLD facility is preferred, most of the water 7 can be converted into steam, generating solids or a stable slurry 15 for landfill disposal 16 or for further treatment. The produced steam flow 20 is used for injection for thermal oil recovery through an injection well. A portion 21 of the produced steam 20 is used to generate the driving superheated steams 6. The clean BFW 28 is used for generating steam through a commercial boiler or OTSG that includes a heat exchanger 26 to generate High Pressure steam 24. Any type of commercially available boiler and steam separation vessel can be used. The produced HP steam 24 pressure energy is used to recycle steam 21 to heater 27 to generate superheated dry steam stream 6 to drive the steam generation process at 1. The pumping and circulation of the produced steam 21 is done through steam ejector 23 that uses the pressure of the HP steam as the energy source to compress and circulate portion 21 of the produced steam 20 through the heat exchanger 27. As described in the other examples, the produced steam 21 can be further treated in a separate unit to remove contaminates, like silica, from the produced steam flow that can affect the super heater heat exchanger's 27 performance and create deposits. There are a few technologies that can be used. One option is to use a liquid scrubber with saturated liquid water, possibly with chemicals, like magnesium oxide, caustic soda or other chemical additives, to remove contaminates that can affect the performance of the non-direct heat exchanger 27, or in some cases the steam lines and the injection well 31. Other technological solutions available to remove the undesired contaminates from the steam gas flow can be used as well. The feed water 40 is a treated water with low levels of contaminates, as required by ASME specifications for boiler feed water. There is a lot of knowledge and commercially available packages to generate the BFW 40 used for generating the high pressure steam 24. In the current sketch, the boiler integrates the steam generation section 26 and the re-heater section 27 for generating super-heated driving steam 6 from the produced steam 21 and the high pressure driving steam 24 for operating the ejector and using the super-heated steam as a driving steam. It is possible to separate the production of the high pressure steam 24 from the superheated steam into two separate units while the steam 24 is generated through a package boiler, OTSG or any other type of commercially available boiler, with any type of carbon or hydrocarbon fuel. The produced steam 21 is heated to generate superheated driving steam with any commercially available heat exchanger design. The heater can be integrated into the boiler or a separate unit with any available heater design. The steam generation unit can be located on the well pads or in close proximity to the well pads. This arrangement will minimize the heat losses and allow the use of the produced water heat. The high pressure steam 24 required to operate the ejector can also be produced remotely in BLOCK 1, whereas on the pad there will only be steam heater 27.

FIG. 7 is a schematic view of an integrated facility of the present invention with a commercially available steam generation facility and for EOR for heavy oil production. The steam for EOR is generated using a lime softener based water treatment plant and an OTSG steam generation facility. This type of configuration is the most common in EOR facilities in Alberta. It recovers bitumen from deep oil sand formations using SAGD, or CSS, etc. Produced emulsion 3 from the production well 54, is separated inside the separator facility into bitumen 4 and water 5. There are many methods for separating the bitumen from the water. The most common one uses gravity. Light hydrocarbons can be added to the product to improve the separation process. The water, with some oil remnants, flows to a produced water de-oiling facility 6. In this facility, de-oiling polymers are added. Waste water, with oil and solids, is rejected from the de-oiling facility 6. In a traditional system, the waste water would be recycled or disposed of in deep injection wells. The de-oiled water 10 is injected into a warm or hot lime softener 12, where lime, magnesium oxide, and other softening chemicals are added 8. The softener generates sludge 13. In a standard facility, the sludge is disposed of in a landfill. The sludge is semi-wet, and hard to stabilize. The softened water 14 flows to a filter 15 where filter waste is generated 16. The waste is sent to an ion-exchange package 19, where regeneration chemicals 18 are continually used and rejected with carry-on water as waste 20. In a standard system, the treated water 21 flows to an OTSG where approximately 80% quality steam is generated 27. The OTSG typically uses natural gas 25 and air 26 to generate steam. The flue gas is released to the atmosphere through a stack 24. Its saturated steam pressure is around 100 bar and the temperature is slightly greater than 300 C. In a standard SAGD system, the steam is separated in a separator to generate 100% steam 29 (for EOR) and blow-down water. The blow down water can be used as a heat source and can also be used to generate low pressure steam. The steam, 29 is delivered to the pads, where it is processed and injected into the ground through an injection well 53. In the current method, additional dry superheated steam flow is produced to drive the SD-DCSG in BLOCK 1 to generate additional injection steam from the waste water stream. The production well 54, located in the EOR field facilities BLOCK 4, produces an emulsion of water and bitumen 3. In some EOR facilities, injection and production occur in the same well, where the steam can be 80% quality steam 27. The steam is then injected into the well with the water. This is typical of the CSS pads where wells 53 and 54 are basically the same well. The reject streams include the blow down water from OTSG 23, as well as the oily waste water, solids, and polymer remnants from the produced water de-oiling unit. This also includes sludge 13 from the lime softener, filtrate waste 16 from the filters and regeneration waste from the Ion-Exchange system 20. The reject streams are collected 33 and injected directly 33A into Steam SD-DCSG 30 in BLOCK 1. The SD-DCSG can be vertical, stationary, horizontal or rotating. Dry solids 35 are discharged from the SD-DCSG, after most of the liquid water is converted to steam. The SD-DCSG generated steam 31 temperatures can vary between 120 C and 300 C. The pressure can vary between 1 bar and 50 bar. The produced steam 32 can be injected directly 45A into the injection well 53, possibly after additional solids and contamination removal in BLOCK 32. Another option is to wash the generated steam in wet scrubber 50 in BLOCK 2. BLOCK 2 is optional and can be bypassed by flows 33A and 45A. The produced steam from the SD-DCSG 31 is injected into a scrubber vessel 50 where the steam gas is washed with saturated water 48 that was condensed from the produced gas 31 or from additional liquid water supplied to the wet scrubber vessel 50 in order to remove the solid remnants and possibly chemical contaminates. Solid rich water 51 is continually removed from the bottom of vessel 50. It is recycled back to the SD-DCSG, where the solids are removed in dry or semi-dry form 35. The liquid water is converted back to steam 31. The saturated wash water in vessel 50 is generated by removing heat through non-direct heat exchange with the feed water 33. A portion of the steam condenses to generate washing liquid water at vessel 50. The liquid water is continually recycled to enhance the washing and the wet scrubbing. The SD-DCSG is driven by superheated steam generated by the steam generator 23 or generated in a separate boiler or in a separate heat exchanger within the boiler (re-heater type heat is exchanged to heat steam to produce a superheated steam). There are many varieties of commercially available options to generate the dry steam needed to drive the process in the SD-DCSG. The generated clean steam 45 is injected into an underground formation for EOR.

FIG. 8 is a schematic of the invention with an open mine oilsands extraction facility, where the hot process water for the ore preparation is generated from condensing the steam produced from the fine tailings using a SD-DCSG. A typical mine and extraction facility is briefly described in BLOCK 5. The tailing water 27 from the oilsand mine facility is disposed of in a tailing pond. The tailing ponds are built in such a way that the sand tailings are used to build the containment areas for the fine tailings. The tailing sources come from Extraction Process. They include the cyclone underflow tailings 13, mainly coarse tailings, and the fine tailings from the thickener 18, where flocculants are added to enhance the solid settling and recycling of warm water. Another source of fine tailings is the Froth Treatment Tailings, where the tailings are discarded using the solvent recovery process characterized by high fines content, relatively high asphaltene content, and residual solvent. (See “Past, Present and Future Tailings, Tailing Experience at Albian Sands Energy” a presentation by J. Matthews from Shell Canada Energy on Dec. 8, 2008 at the International Oil Sands Tailings Conference in Edmonton, Alberta). A sand dyke 55 contains a tailing pond. The sand separates from the tailings and generates a sand beach 56. Fine tailings 57 are put above the sand beach at the middle-low section of the tailing pond. Some fine tailings are trapped in the sand beach 56. On top of the fine tailings is the recycled water layer 58. The tailing concentration increases with depth. Close to the bottom of the tailing layer are the MFT. (See “The Chemistry of Oil Sands Tailings: Production to Treatment” presentation by R. J. Mikula, V. A. Munoz, O. E. Omotoso, and K. L. Kasperski of CanmetENERGY, Devon, Alberta, Natural Resources Canada on Dec. 8, 2008 at the International Oil Sands Tailings Conference in Edmonton, Alberta). The recycled water 41 is pumped from a location close to the surface of the tailing pond (typically from a floating barge). The fine tailings that are used for generating steam and solid waste in this invention are the MFT. They are pumped from the deep areas of the fine tailings 43. MFT 43 is pumped from the lower section of the tailing pond and is then directed to the SD-DCSG in BLOCK 1 and in BLOCK 3. The SD-DCSG that includes BLOCKS 1-4 is described in FIG. 5B. However, any available SD-DCSG that can generate gas and solids from the MFT can be used as well. Due to the heat from the superheated steam and pressure inside the SD-DCSG, the MFT turns into gas and solids as the water is converted to steam. The solids are recovered in a dry form or in a semi-dry, semi-solid slurry form. The semi-dry slurry form is stable enough to be sent back into the oilsands mine without the need for further drying to support traffic. The produced steam needed for extraction and froth treatment, is generated by a standard steam generation facility 61 used to generate the driving steam for the DCSG in BLOCK 1, or from the steam produced from the SD-DCSG 62. The generated saturated steam 47 is mixed with the process water 41 in mixing enclosure 45 to generate the hot water 52 used in the extraction process in BLOCK 5. By continually consuming the fine tailing water 43, the oil sand mine facility can use a much smaller tailing pond as a means of separating the recycled water from the fine tailings. This solution will allow for the creation of a sustainable, fully recyclable water solution for open mine oilsands facilities.

FIG. 9 is a schematic view of the invention with an open mine oilsands extraction facility and a prior art commercially available pressurized fluid bed boiler that uses combustion coal for a power supply. Examples of pressurized boilers are the Pressurized Internally Circulating Fluidized-bed Boiler (PICFB) developed and tested by Ebara, and the Pressurized-Fluid-Bed-Combustion-Boiler (PFBC) developed by Babcock-Hitachi. Any other pressurized combustion boiler that can combust petcoke or coal can be used as well. BLOCK 1 is a prior art Pressurized Boiler. Air 64 is compressed 57 and supplied to the bottom of the fluid bed combustor to support the combustion. Fuel 60, like petcoke, is crushed and grinded, possibly with lime stone 61 and water 62, to generate pumpable slurry 59. The water 62 is recycled water with a high level of contaminates 38, as discharged from the SD-DCSG 28. Some portion of stream 38A can be injected above the combustion area to directly recover heat from the combustion gas to generate steam. The boiler includes an internal heat exchanger 63 to generate high pressure steam 51 to drive the SD-DCSG. The steam 51 is generated from steam boiler drum 52 with boiler water circulation pump 58. The boiler heat exchanger 63 recovers energy from the combustion. BFW 37 is fed to the boiler to generate steam 51. The steam can be heated again in a boiler heat exchanger (not shown) to generate a superheated steam stream. The steam is used to drive the SD-DCSG 28. The boiler generates pressurized combustion gas and steam mixture 1 from the SD-DCSG discharged water 24 at an average pressure of 103 kpa and up to 1.5 Mpa, and temperatures of 200 C-900 C. The discharge flow is treated in BLOCK 3 to generate a steam and combustion gas mixture for EOR. The mixture 8 is injected into an underground formation through an injection well 7. There is no need to remove solids from the combustion gas 1 because this gas is fed to the DCSG in BLOCK 3 that works as a wet scrubber and removes solids and possibly contaminated gases like SOx and NOx while creating a steam and combustion gas mixture. Solids from the fluid bed of the PFBC 55 can be recovered to maintain the fluid bed solids level (this is a common practice in FBC (Fluid Bed Combustion) and PFBC). The fluid bed solids can be mixed with the DCSG solids from BLOCK 3 (not shown). The pressurized combustion gases leaving AREA#1 are mixed with the concentrate effluent from SD-DCSG 28 and possibly with other low quality waste water and slurry sources, like HLS/WLS sludge produced by SAGD/CSS water treatment plant (not shown). BLOCK 2 includes a commercially available EOR facility, like SAGD, where the water and bitumen emulsion is treated to generate BFW quality water and low quality water that is fed into the SD-DCSG. There will be two types of injection wells—for the injection of pure steam from the SD-DCSG 6 and for the injection of a mixture of steam and combustion gases, mainly CO2 7. It is possible to combine the two types of EOR fluids in one production facility where the aging injection wells will be converted from pure steam to a steam and combustion gas mixture to pressurize the underground formation and increase the bitumen recovery due to the dissolved CO2 which increases the bitumen fluidity.

FIG. 10 is a schematic diagram of DCSG pressurized boiler and SD-DCSG. Fuel 2 is mixed with air 55 and injected into a Pressurized Fluidized-Bed Boiler 51. The fuel 2 can be generated from the water-bitumen separation process and includes reject bitumen slurry, possibly with chemicals that were used during the separation process, and sand and clay remains. Additional low quality carbon fuel can be added to the slurry. This carbon or hydrocarbon fuel can include coal, petcoke, asphaltin or any other available fuel. Lime stone can be added to the fuel 2 or to the water 52 to remove acid gases like SOx. The Fluidized-Bed boiler is modified with water injection 52 to convert it into a DCSG. It includes reduced capacity internal heat exchangers to recover less combustion heat. The reduction in the heat exchanger's required capacity is because more combustion energy will be consumed due to the direct heat exchange with the water within the fuel slurry 2 and the additional injected solids rich water 52 thereby leaving less available heat to generate high pressure steam through the boiler heat exchangers 56. The boiler produces high-pressure steam 59 from distilled, de-mineralized feed water 37. The produced steam 59, or part of it 31, can be re-heated in re-heater 56 to generate super heated steam 32 to operate the SD-DCSG in BLOCK 3. There are several pressurized boiler designs for BLOCK 1 that can be modified with direct water injections. One example of such a design is the EBARA Corp. PICFB (see paper No. FBC99-0031 Status of Pressurized Internally Circulating Fluidized-Bed Gasifier (PICFG) development Project dated 16-19 May, 1999 and U.S. RE37,300 E issued to Nagato et al on Jul. 31, 2001). Any other commercially available Pressurized Fluidized Bed Combustion (PFBC) can be used as well. Another modification to the fluid bed boiler can be reducing the boiler combustion pressure down to 102 kpa. This will reduce the plant TIC (Total Installed Cost) and the pumps and compressors' energy consumption. The superheated steam 32 is supplied to BLOCK 3 where it is used by the SD-DCSG 28 for generating additional steam from low quality water. BLOCK 2 includes a water treatment facility as previously described. The steam and combustion gas mixture stream 1 is supplied to BLOCK 2 where the water and heat can be used for generating clean BFW in the evaporation/distillation facility. The pressure energy in flow 1 can be used to separate CO2 from the NCG using commercially available membrane technologies. The combustion oxidizer, like air 55, is injected at the bottom of the boiler to maintain the fluidized bed. High pressure 100% quality steam 59 is generated from distilled water 37 through heat exchange inside the boiler 51. The generated steam 59 can be further heated in heat exchanger 56 to generate super-heated steam 32 that is used in BLOCK 3 as the driving steam for the SD-DCSG 28. The steam generated in BLOCK 3 is injected, through an injection well 16, into an underground formation for EOR. Hydrocarbons and water 13 are produced from the production well 15. The mixture is separated in a commercially available separation facility in BLOCK 2.

FIG. 11 is a schematic diagram of the present invention which includes a steam generation facility, SD-DCSG, a fired DCSG and MED water treatment plant. BLOCK 1 is a standard, commercially available steam generation facility that includes an atmospheric steam boiler or OTSG 7. Fuel 1 and air 2 are combusted under atmospheric pressure conditions. The discharged heat is used to generate steam 5 from de-mineralized distilled water 29. The combustion gas is discharged through stack 3. The generated steam is supplied to SD-DCSG 11 in BLOCK 4 which generates additional steam from the concentrated brine 38 discharged from the MED in BLOCK 2. The generated steam 8 is injected into an underground formation 6. The liquid discharge 14 from SD-DCSG 11 is injected into an internally fired DCSG 15 in BLOCK 3. Carbon fuel 41, like petcoke or coal slurry, is mixed with oxygen-rich gas 42 and combusted in a DCSG 15. Discharged liquids from the SD-DCSG 11 are mixed with the pressurized combustion gas to generate a stream of steam-rich gas and solids 13. To reduce the amount of SO2, limestone can be added to the brine water 14 or to the fuel 41 injected into the DCSG, in order to react with the SO2. The solids are separated in separator 16. The separated solids 17 are discharged in a dry form from the solids separator 16 for disposal. The steam and combustion gas 12 flows to heat exchanger 25 and condenser 28. The steam in gas flow 12 is condensed to generate condensate 24. The condensate is treated (not shown) to remove contaminants and to generate BFW that is added to the distillate BFW 29 and then supplied to the steam generation facility. The NCG (Non-Condensation Gas) 40 is released to the atmosphere or used for further recovery, like CO2 extraction. The heat recovered in heat exchanger 28 is used to generate steam to operate the MED 30 (a commercially available package). The water 1 fed to the MED is de-oiled produced water, possibly with make-up underground brackish water. The MED takes place in a series of vessels (effects) 31 and uses the principles of condensation and evaporation at a reduced pressure. The heat is supplied to the first effect 31 in the form of steam 26. The steam 26 is injected into the first effect 31 at a pressure ranging from 0.2 bar to 12 bar. The steam condenses while feed water 32 is heated. The condensation 34 is collected and used for boiler feed water 37. Each effect consists of a vessel 31, a heat exchanger, and flow connections 35. There are several commercial designs available for the heat exchanger area: horizontal tubes with a falling brine film, vertical tubes with a rising liquid, a falling film, or plates with a falling film. The feed water 32 is distributed on the surfaces of the heat exchanger and the evaporator. The steam produced in each effect condenses on the colder heat transfer surface of the next effect. The last effect 39 consists of the final condenser, which is continually cooled by the feed water, thus preheating the feed water 1. To improve the condensing recovery, the feed water can be cooled by air coolers before being introduced into the MED (not shown). The feed water may come from de-oiled produced water, brackish water, water wells or from any other locally available water source. The brine concentrate 2 is recycled back to the SD-DCSG in BLOCK 4.

FIG. 11A is a view of the present invention that includes a steam generation facility, SD-DCSG and MED water treatment plant. BLOCK 1 is a standard, commercially available steam generation facility for generating super heated driving steam 5. The driving steam 5 is fed to the SD-DCSG in BLOCK 3. Discharged brine from the commercial MED facility in BLOCK 2 is also injected into the SD-DCSG 15 and converted into steam and solid particles 13. The solids 17 are removed for disposal. A portion of the generated steam 12 is used to operate the MED through heat exchanger/condenser 28. The condensate 24, after further treatment (not shown), is used as BFW. The MED produces distilled BFW 29 that is used to produce the driving steam at the boiler 7. The steam 8 is injected through injection well 6 for EOR.

FIG. 11B is a schematic diagram of the present invention that includes a steam drive DCSG with a direct heated Multi Stage Flash (MSF) water treatment plant and a steam boiler for generating steam for EOR. BLOCK 4 includes a commercially available steam generation facility. Fuel 2 is mixed with oxidized gas 1 and injected into the steam boiler (a commercially available atmospheric pressure boiler). If a solid-fuel boiler is used, the boiler might include solid waste discharge. The boiler produces high-pressure steam 5 from distilled BFW 39. The steam is injected into the underground formation through injection well 6 for EOR. A portion of the steam can be used to operate the DCSG. The boiler combustion gas may be cleaned and discharged from stack 3. If natural gas is used as the fuel 2, there is currently no mandatory requirement in Alberta for further treatment of the discharged flue gas or for removal of CO2. Steam 9 injected into a pressurized DCSG 15 at an elevated pressure. The DCSG design can be a horizontal sloped rotating reactor, however any other reactor that can generate a stream of steam and solids can also be used. Solids-rich water 14 that includes the brine from the MSF is injected into the direct contact steam generator 15 where the water evaporates into steam and the solids are carried on with gas flow 13. The amount of water 14 is controlled to verify that all the water is converted into steam and that the remaining solids are in a dry form. The solids-rich gas flow 13 flows to a dry solids separator 16. The dry solids separator is a commercially available package and it can be used in a variety of gas-solid separation designs. The removed solids 17 are taken to a land-fill for disposal. The steam flows to tower 25. The tower acts like a direct contact heat exchanger. Typically in MSF processes, the feed water is heated in a vessel called the brine heater. This is generally done by indirect heat exchange by condensing the steam on tubes that carry the feed water through the vessel. The heated water then flows to the first stage. In the method described in FIG. 11B, the feed water of the MSF 45 is heated by direct contact heat exchange 25 (and not through an indirect heat exchanger). The feed water is injected into the up-flowing steam flow 12. The steam condenses because of heat exchange with the feed water 45. A non-direct heat exchanger/condenser can be used as well to heat brine flow 45 with steam flow 12 while condensing the steam flow 12 to liquid water. In the MSF at BLOCK 30, the heated feed water 46 flows to the first stage 31 with a slightly lower pressure, causing it to boil and flash into steam. The amount of flashing is a function of the pressure and the feed water temperature, which is higher than the saturated water temperature. The flashing will reduce the temperature to the saturate boiling temperature. The steam resulting from the flashing water is condensed on heat exchanger 32, where it is cooled by the feed water. The condensate water 33 is collected and used (after some treatment) 38 as BFW 39 in the standard, commercially available, steam generation facility 4. There can be up to 25 stages. A commercial MSF typically operates in a temperature range of 90-110 C. High temperatures increase efficiency but may accelerate scale formation and corrosion in the MSF. Efficiency also depends on a low condensing temperature at the last stage. The feed water for the MSF 9 can be treated by adding inhibitors to reduce the scaling and corrosion 38. Those chemicals are available commercially and the pretreatment package is typically supplied with the MSF. The feed water is recovered from the produced water in separation unit 10 that separates the produced bitumen 8, possibly with diluent that improves separation from the water and decreases the viscosity of the heavy bitumen. The de-oiled water 9 is supplied to the MSF as feed water. There are several commercially available separation units. In my applications, the separation, which can be simplified as discharged “oily contaminate water” 18, is allowed in the process. Make-up water 29, like water from water wells or from any other water source, is continually added to the system. Any type of vacuum pump or ejector can be used to remove gas 36 and generate the low pressure required in the MSF design.

FIG. 12 is an illustration of the use of a partial combustion gasifier with the present invention for the production of syngas for use in steam generation, a SD-DCSG, and a DCSG combined with a water distillation facility for ZLD. The system contains few a commercially available blocks, each of which includes a commercially available facility:

• • BLOCK 1 includes the gasifier that produces syngas.
  • BLOCK 2 includes a commercially available steam generation boiler that is capable of combusting syngas.
  • BLOCK 3 includes a commercially available thermal water distillation plant.
  • BLOCK 4 includes the SD-DCSG which generates the injection steam.
  • BLOCK 5 includes a water-oil separation facility with the option of oily water discharge for recycling into the SD-DCSG.
  • BLOCK 6 includes the DCSG.
  • BLOCK 7 includes a syngas treatment plant where part of the syngas can be used for hydrogen production etc.

Carbon fuel 5 is injected with oxygen rich 6 gas to a pressurized gasifier 7. The gasifier shown is a typical Texaco (GE)™ design that includes a quenching water bath at the bottom. Any other pressurized partial combustion gasifier design can also be used. The gasifier can include a heat exchanger, located at the top of the gasifier (near the combustion section), to recover part of the partial combustion energy to generate high pressure steam. At the bottom of the gasifier, there is a quenching bath with liquid water to collect solids. Make-up water 13 is then injected to maintain the liquid bath water level. The quenching water 15, which includes the solids generated by the gasifier, is injected into a DCSG 15 where it is mixed with the produced hot syngas discharged from the gasifier 12. The DCSG also consumes the liquid water discharge 52 from the SD-DCSG 50. In the DCSG, the water is evaporated into pressurized steam and solids (which were carried with the water and the syngas into the DCSG). The DCSG generates a stream of gas and solids 16. The solids 19 are removed from the gas flow by a separator 17 for disposal. The solids lean gas flow 18 (after most of the solids have been removed from the gas) is injected into a pressurized wet scrubber 20 that removes the solid remains and can also generate saturated steam from the heat in gas flow 18. Solids rich water 25 is continually rejected from the bottom of the scrubber and recycled back to the DCSG 15. Heat 27 is recovered from the saturated water and syngas mixture 21 while condensing steam 21 to liquid water 35 and water lean syngas 36. The condensed water 35 can be used as BFW after further treatment to remove contaminations (not shown). The heat 27 is used to operate a thermal distillation facility in BLOCK 3. There are several commercially available facilities for this, such as the MSF or MED. The distillation facility uses de-oiled produced water 30, possibly with make-up brackish water 31 and heat 27, to generate a stream of de-mineralized BFW 29 for steam generation and a stream of brine water 28, with a high concentration of minerals. The generated brine 28 is recycled back to the SD-DCSG 50 in BLOCK 4. The syngas can be treated in commercially available facilities in BLOCK 7 to remove H2S (using amine) or to recover hydrogen. The treated syngas 37, together with oxidizer 38, is used as a fuel source in the commercially available steam generation facility in BLOCK 2. The super heated steam 40 is generated in steam boiler 39 from the BFW 29. The steam from the boiler 40, possibly together with the steam generated by the gasifier 10, is injected into the SD-DCSG 50 in BLOCK 4 where additional steam is generated from low quality water 53. The generated steam 51 is injected into an underground formation for EOR. The produced bitumen and water recovered from production well 44 are separated in the water-oil separation facility (BLOCK) 5 to produce bitumen 33 and de-oiled water 30. Oily water 34 can be rejected and consumed in the SD-DCSG 50. By allowing continuous rejection of oily water, the chemical consumption can be reduced and the efficiency of the oil separation unit can be improved.

FIG. 13 is a schematic of the present invention for the generation of hot water for oilsands mining extraction facilities, with Fine Tailing water recycling. Block 1A includes a Prior Art commercial open mine oilsands plant. The plant consists of mining oilsands ore and mixing it with hot process water, typically in a temperature range of 70 C-90 C, separating the bitumen from the water, sand and fines. The cold process water 8 includes recycled process water together with fresh make-up water that is supplied from local sources (like the Athabasca River in the Wood Buffalo area). Another bi-product from the open mine oilsands plant is Fine Tailings 5 which, after a time, is transferred to a stable Mature Fine Tailings. Energy 1 is injected into reactor 3. The energy is in the form of steam gas. The hot, super heated (“dry”) steam gas is mixed in enclosure 3 with a flow of FT 5 from BLOCK 1A. Most of the liquid water in the FT is converted to steam. The remaining solids 4 are removed in a solid, stable form to use as a back-fill material and to support traffic. The produced steam 21 is at a lower temperature than steam 1 and contains additional water from the FT that was converted to steam. Steam 1 can be generated by heating the produced steam 21, as described in FIG. 3, 3A or 3B (not shown). The produced steam 21 is mixed with cold process water 8 from BLOCK 1A in a direct contact heat exchanger 7. The produced steam is directly heated and condensed into the liquid water 8 to generate hot process water 9 that is then supplied back to operate the Open Mine Oilsands plant 1A. The amount of NCG 2 is minimal. Some NCG can be generated from the organic contaminates in the FT 5. The enclosure 3 system pressure can vary from 103 kpa to 50000 kpa and the temperature at the discharge point 21 can vary from 100 C to 400 C.

FIG. 13A is a schematic view of the process for the generation of hot water for oilsands mining extraction facilities, with Fine Tailing water recycling. FIG. 13A is similar to FIG. 13 with the notable difference that non-direct heat exchange is used between the drive steam 1 and the FT or MFT 5. Block 1A includes a Prior Art commercial open mine oilsands plant. The plant consists of mining oilsands ore and mixing it with hot process water, typically in a temperature range of 70 C-90 C, and separating the bitumen from the water, sand and fines. The cold process water 8 includes recycled process water together with fresh make-up water that is supplied from local sources (like the Athabasca River in the Wood Buffalo area). Another bi-product from the open mine oilsands plant is Fine Tailing (FT) 5 which, after a time, are transferred to a stable Mature Fine Tailings (MFT). Energy 1 is injected into reactor 3. The energy is in the form of steam gas which is injected around enclosure 3 where the heat is transferred to the reactor and to the MFT through the enclosure wall. The driving hot steam gas is condensed and recovered as a liquid condensate 1A. The driving steam 1 heat energy is transferred to the enclosure and used to evaporate the FT 5. Most of the liquid water in the FT is converted to steam. The remaining solids 4 are removed in a solid/slurry stable form to use as a back-fill material which can support traffic. Steam 1 is generated by a standard boiler heating the condensate 1A in a closed cycle, allowing the use of high quality clean ASME BFW (not shown). The produced steam 21 is mixed with cold process water 8 from BLOCK 1A in a direct contact heat exchanger 7. The produced steam is directly heated and condensed into the liquid water 8 to generate hot process water 9 that is supplied back to operate the Open Mine Oilsands plant 1A. The amount of Non Condensable Gases (NCG) 2 is minimal. Some NCG can be generated from the organic contaminates in the FT 5. The enclosure 3 system pressure can vary from 103 kpa to 50000 kpa and the temperature at the discharge point 21 can vary from 100 C to 400 C.

FIG. 13B is a schematic view of the process for the generation of hot water for oilsands mining extraction facilities, with Fine Tailing water recycling. FIG. 13B is similar to FIG. 13A with rotating internals to enhance the heat transfer between the evaporating MFT and the heat source which is the steam 1 in the enclosure 3. The rotating internals also mobilize the high concentration slurry and solids to the solid discharge 4, where stable material that can support traffic is discharged from the system. The produced steam 6 is further cleaned to remove solids in commercially available solids separation unit 20 like a cyclone, electrostatic filter or any other commercially available system. The generated steam 21 is mixed with cold process water 8 supplied from an open mine extraction plant in a direct contact heat exchanger 7. The produced steam is directly heated and condensed into the liquid water 8 to generate hot process water 9 that is supplied back to operate the extraction Open Mine Oilsands plant.

FIG. 14 is one illustration of the present invention for the generation of pre-heated water that can be used for steam generation or in a mining extraction facility. The invention has full disposal water recycling, so as to achieve zero liquid discharge. Energy 1, in the form of super heated steam, is introduced into the Direct Contact Steam Generator reactor 3. Contaminated water 5, like FT or MFT, is injected into reactor 3. There, most of the water is converted into steam, leaving only solids with a low moisture content. There are several possibilities for the design of reactor 3. The design can be a horizontal rotating reactor, an up-flow reactor, or any other type of reactor that can be used to generate a stream of solids and gas. A stream of hot gas 6, possibly with carried-on solids generated in reactor 3, flows into a commercially available solid-gas separator 20. Solids 4 can also be discharged directly from the reactor 3, depending on the type of reactor used. The separated solids 22 and 4 are disposed of in a landfill. The solids lean steam flow 21, (rich with steam from flow 5) is condensed into liquid water 10 in a non-direct condenser 7. There are many commercially available standard designs for heat-exchanger/condenser that can be used at 7. The steam heat is used to heat flow 8, like process water flow, to generate hot water 9 that can be used in the extraction process. Low volumes of NCG 2 can be treated or combusted as a heat source (not shown). The condensed liquid water 10 can be used as hot process water for the extraction process or any other usage. The steam in flow 21 condenses by non-direct contact with the recycled water 8. Solid remains that previously passed through solid separation unit 20 and were carried on with the gas flow 21, are washed with the condensed water 10.

FIG. 15 is a schematic of the invention with an open mine oilsands extraction facility, where the steam source is a standard gasifier for generating steam in a non-direct heat exchange and syngas can be used for the production of hydrogen for upgrading the produced crude in prior-art technologies or can be used as a fuel source. The MFT recovery is done with the steam which was produced by the gasifier and not with the syngas. The partial combustion of fuel 56 and oxidizer, like enriched air, takes place inside the gasifier 54. The gasification heat is used to produce superheated steam 55 from BFW 59. The produced syngas 60 is recovered and further treated. This treatment can include the removal of the H2S (like in an amine plant). Treatment can also include generating hydrogen for crude oil upgrading or as a fuel source to replace natural gas usage (not shown). The steam 55 flows to a horizontal parallel flow DCSG 1. Concentrated MFT 2 is also injected into the DCSG. The MFT is converted to gas, mainly steam, and solids 6. The solids 8 are removed in a gas-solid separator 7. The solid lean stream flows through heat exchanger 11, where it heats the process water, or any other process flow 12, indirectly through a heat exchanger. Condensing hot water 13 is removed from the bottom 11 and used as hot process extraction water. In case NCG 17 is generated, it can be further treated or combusted as a fuel source. The fine tailings 14 are pumped from the tailing pond and can then be separated into two flows through a specific separation process. Separation 15 is one option to increase the amount of MFT removal. The process can use natural MFT both at flows 2 and 16. This separation can be done using a centrifuge or a thickener (like a High Compression Thickener or Chemical Polymer Flocculent based thickener). This unit separates the fine tailings into solid rich 16 and solid lean 2 flows. The solid lean flow is fed into the DCSG 1 or recycled and used as the process water (not shown). In the DCSG 1, dry solids are generated and removed from the gas-solid separator. The solid rich flow 16 is mixed with the dry solids 8 in a screw conveyor to generate a stable material 27.

FIG. 16 is a schematic of the invention with an open mine oilsands extraction facility, where the hot process water for the ore preparation is generated by recovering the heat and condensing the steam generated from the fine tailings without the use of a tailings pond. A typical mine and extraction facility is briefly described in block diagram 1 (See “Past, Present and Future Tailings, Tailing Experience at Albian Sands Energy” presentation by J. Matthews from Shell Canada Energy on Dec. 8, 2008 at the International Oil Sands Tailings Conference in Edmonton, Alberta). Mined Oil sand feed is transferred via truck to an ore preparation facility, where it is crushed in a semi-mobile crusher 3. It is also mixed with hot water 57 in a rotary breaker 5. Oversized particles are rejected and removed to a landfill. The ore mix goes through slurry conditioning, where it is pumped through a special pipeline 7. Chemicals and air are added to the ore slurry 8. In the invention, the NCGs 58 that are released under pressure from tower 56 can be added to the injected air at 8 to generate aerated slurry flow. The conditioned aerated slurry flow is fed into the bitumen extraction facility, where it is injected into a Primary Separation Cell 9. To improve the separation, the slurry is recycled through floatation cells 10. Oversized particles are removed through a screen 12 in the bottom of the separation cell. From the flotation cells, the coarse and fine tailings are separated in separator 13. The fine tailings flow to thickener 18. To improve the separation in the thickener, flocculant is added 17. Recycled water 16 is recovered from the thickener and fine tailings are removed from the bottom of the thickener 18. The froth is removed from the Primary Separation Cell 9 to vessel 21. In this vessel, steam 14 is injected to remove air and gas from the froth. The recovered froth is maintained in a Froth Storage Tank 23. The coarse tailings 15 and the fine tailings 19 are removed and sent to tailing processing area 60. The fine and coarse tailings can be combined, or removed and sent separately (not shown) to the tailing process area 60. In Unit 60, the sand and other large solid particles are removed and then put back into the mine, or stored in stock-piles. Liquid flow is separated into 3 different flows, mostly differing in their solids concentration. A relatively solids-free flow 62 is heated. This flow is used as heated process water 57 in the ore preparation facility, for generation of the oilsands slurry 6. The fine tailings stream can be separated into two sub streams. The most concentrated fine tailings 51 are mixed with dry solids, generated by the DCSG, to generate a solid and stable substrate material that can be put back into the mine and used to support traffic. The medium concentration fine tailing stream 61 flows to the DCSG facility 50. Steam energy 47 is used in the DCSG to convert the fine tailings 61 water into a dry or semi dry solid and gas stream. The steam can be produced in a standard high pressure steam boiler 40, in an OTSG, or produced by a COGEN, using the elevated temperature in a gas turbine tail (not shown). The boiler consumes fuel gas 38 and air 39 while generating steam 14. A portion 47 of the generated steam 14 can be injected into the DCSG 50. The temperature of the DCSG produced steam can vary from 100 C to 400 C as it includes the water from the MFT. Steam 47 can be also generated by heating a portion of the produced steam 52 as described in FIGS. 3, 3A and 3B. The solids are separated from the gas stream in any commercially available facility 45 which can include: cyclone separators, centrifugal separators, mesh separators, electrostatic separators or other combination technologies. The solids lean steam 52 flows into tower 56. The gas flows up into the tower, possibly through a set of trays, while any solid carried-on remnants are scrubbed from the up flowing gas through direct contact with liquid water. The water vapor that was generated from heating the fine tailing 61 in the DCSG and the steam that provided the energy to evaporate the FT are condensed and added to the down-flowing extraction water process 57. The presence of small amounts of remaining solids in the hot process water is acceptable. That is because the hot water is mixed with the crushed oilsands 3 in the breaker during ore preparation. The temperature of the discharged hot water 57 is between 70 C and 95 C, typically in the 80 C-90 C range. The hot water is supplied to the ore preparation facility. The separated dry solids from the DCSG are mixed with the concentrated slurry flow from the tailing water separation facility 60. They are used to generate a stable solid waste that can be returned to the oilsands mine for back-fill and can be used to support traffic. Any commercially available mixing method can be used in the process: a rotating mixer, a Z type mixer, a screw mixer, an extruder or any other commercially available mixer. The slurry 51 can be pumped to the mixing location, while the dry solids can be transported pneumatically to the mixing location. The described arrangement, where the fine tailings are separated into two streams 61 and 51, is intended to maximize the potential of the process to recover MFT. It is meant to maximize the conversion of fine tailings into solid waste for each unit weight of the supplied fuel source. The system can work in the manner described for tailing pond water recovery. The tailing pond water is condensed in hot water generation 57, without the combination of the dry solids 53 and tailing slurry 51. The generated dry solids 53 are a “water starving” dry material. As such, they are effective in the process of drying MFT to generate trafficable solid material without relying on weather conditions to dry excess water.

FIG. 17 is a schematic of the invention with an open mine oilsand extraction facility, where the hot process water for the ore preparation is generated from condensing the steam produced from the fine tailings. A typical mine and extraction facility is briefly described in block diagram 1. The tailing water from the oilsands mine facility 1 is disposed of in a tailing pond. The tailing ponds are designed in such a way that the sand tailings are used to build the containment areas for the fine tailings. The tailings are generated in the Extraction Process. They include the cyclone underflow tailings 13 (mainly coarse tailings) and the fine tailings from the thickener 18, where flocculants are added to enhance the solid settling and recycling of warm water. Another source of fine tailings is the Froth Treatment Tailings, where the tailings are discarded using the solvent recovery process; the Froth Treatment Tailings are characterized by high fines content, relatively high asphaltene content, and residual solvent. (See “Past, Present and Future Tailings, Tailing Experience at Albian Sands Energy” a presentation by J. Matthews from Shell Canada Energy on Dec. 8, 2008 at the International Oil Sands Tailings Conference in Edmonton, Alberta). A sand dyke 55 contains a tailing pond. The sand separates from the tailings and generates a sand beach 56. Fine tailings 57 are put above the sand beach at the middle-low section of the tailing pond. Some fine tailings are trapped in the sand beach 56. On top of the fine tailing is the recycled water layer 58. The tailing concentration increases with depth. Close to the bottom of the tailing layer are the MFT (Mature Fine Tailings). (See “The Chemistry of Oil Sands Tailings: Production to Treatment” presentation by R. J. Mikula, V. A. Munoz, O. E. Omotoso, and K. L. Kasperski of CanmetENERGY, Devon, Alberta, Natural Resources Canada on Dec. 8, 2008 at the International Oil Sands Tailings Conference in Edmonton, Alberta). The recycled water 41 is pumped from a location close to the surface of the tailing pond (typically from a floating barge). The fine tailings that are used for generating steam and solid waste in my invention are the MFT. They are pumped from the deep areas of the fine tailings 43. Steam 48 is injected into a DCSG. MFT 43 are pumped from the lower section of the tailing pond and are then directed to the DCSG 50. The DCSG described in this particular example is a horizontal, counter flow rotating DCSG. However, any available DCSG that can generate gas and solids from the MFT can be used as well. Due to the heat and pressure inside the DCSG, the MFT turn into gas and solids as the water is converted into steam. The solids are recovered in a dry form or in a semi-dry, semi-solid slurry form 51. The semi-dry slurry form is stable enough to be sent back into the oilsands mine without the need for further drying and can be used to support traffic. The produced steam 14, of which portion 48 can be used to operate the DCSG, is generated by a standard steam generation facility 36 from BFW 37, fuel gas 38 and air 39. The blow-down water 20 can be recycled into the process water 20. By continually consuming the fine tailing water 43, the oil sand mine facility can use a much smaller tailing pond as a means of separating the recycled water from the fine tailings. This smaller recyclable tailing pond is cost effective, and is a simple way to deal with tailings as it does not involve any moving parts (in contrast to the centrifuge or to thickening facilities). This solution will allow for the creation of a sustainable, fully recyclable water solution for the open mine oilsands facilities. Steam 48 can be generated by heating a portion of the produced steam 47, as described in FIGS. 3, 3A and 3B.

FIG. 18 is a schematic of the invention with open mine oilsands extraction facility, where the hot process water for the ore preparation is generated by condensing the steam generated from the fine tailings and the driving steam. The tailing water from the oilsands mine facility 43 (not shown) is disposed of in a tailing pond. Steam 4 is fed into a horizontal parallel flow DCSG 1. Concentrated MFT 2 is injected into the DCSG 1 as well. The MFT is converted into steam, and solids. The solids are removed in a solid-gas separator 7 where the solid lean stream is washed in tower 10 by saturated water. In the tower, the solids are washed out and then removed. The solid rich discharge flow 13 can be recycled back to the DCSG or to the tailing pond. Heat is recovered from the saturated steam 16 in heat exchanger/condenser 17. Steam is condensed to water 20. The condensed water 20 can be used as hot process water and can be added to the flow 24. The recovered heat is used for heating the process water 35. The fine tailings 32 are pumped from the tailing pond and separated into two flows by a centrifugal process 31. This unit separates the fine tailings into two components: solid rich 30 and solid lean 33 flows. The centrifuge unit described is commercially available and was tested successfully in two field pilots (See “The Past, Present and Future of Tailings at Syncrude” presentation by A. Fair from Syncrude on Dec. 7-10, 2008 at the International Oil Sands Tailings Conference in Edmonton, Alberta). Other processes, like thickening the MFT with chemical polymer flocculent, can be used as well instead of the centrifuge. The solid lean flow can contain less than 1% solids. The solid rich flow is a thick slurry (“cake”) that contains more than 60% solids. The solid lean flow is used directly or is recycled back to a settling basin (not shown) and is eventually used as process water 35. The solid concentration is not dry enough to be disposed of efficiently and cannot be used to support traffic. This can be solved by mixing it with a “water starving” material (virtually dry solids generated by the DCSG). Mixing of the dry solids and the thick slurry can be achieved through many commercially available methods. In this particular figure, the mixing is done by a screw conveyer 29 where the slurry 30 and the dry material 8 are added to the bottom of a screw conveyor, mixed by the screw, and then the stable solids are loaded on a truck 28 for disposal. The produced solid material 27 can be backfilled into the oilsands mine excavation site and then used to support traffic. It is also possible to feed the thickened MFT directly to the DCSG 1, eliminating the additional mixing process. In this particular figure, there are two options for supplying the fine tailing water to the DCSG: one is to supply the solid rich thick slurry 30 from the centrifuge or thickening unit 31. The other is to use the “conventional” MFT, typically with 30% solids, pumped from the settlement pond. Feeding the MFT “as is” to the DCSG eliminates the TIC, operation, and maintenance costs for a centrifuge or thickening facility.

FIG. 19 is an illustration of one embodiment of the present invention. Fuel 2 is mixed with oxidizing gas 1 and injected into the steam boiler 4. The boiler is a commercially available atmospheric pressure boiler. If a solid fuel boiler is used, the boiler might include a solid waste discharge. The boiler produces high-pressure steam 5 from distilled BFW 19. The steam is injected into the underground formation through injection well 6 for EOR. The boiler combustion gases are possibly cleaned and discharged from stack 32. If natural gas is used as the fuel 2, there is currently no mandatory requirement in Alberta to further treat the discharged flue gas or remove CO2. Steam 9 is injected into a pressurized DCSG 15 at an elevated pressure. The DCSG design can include a horizontal rotating reactor, a fluidized bed reactor, an up-flow reactor, or any other reactor that can be used to generate a stream of gas and solids. Solids-rich water 14 is injected into the direct contact steam generator 15 where the water evaporates into steam and the solids are carried on with gas flow 13. The amount of water 14 is controlled in order to verify that all the water is converted into steam and that the remaining solids are in a dry form. The solid-rich gas 13 flows to a dry solids separator 16. The dry solids separator is a commercially available package and it can be used in a variety of gas-solid separation designs. The solids 17 are taken to a land-fill. The solids lean flow 12 flows to the heat exchanger 30. The steam continually condenses because of heat exchange. Heat 25 is recovered from gas flow 12. The condensed water 36 can be used for steam generation. The condensation heat 25 can be used to operate the distillation unit 11. The distillation unit 11 produces distillation water 19. The brine water 26 is recycled back to the direct contact steam generator 15 where the liquid water is converted to steam and the dissolved solids remain in a dry form. The distillation unit 11 receives de-oiled produced water 39 that is separated in a commercially available separation facility 10, like that which is currently in use by the industry. Additional make-up water 34 is added. This water can be brackish water, from deep underground formations, or from any other water source that is locally available to the oil producers. The quality of the make-up water 34 is suitable for the distillation facility 11, where there are typically very low levels of organics due to their tendency to damage the evaporator's performance or carry on and damage the boiler. Water that contains organics is a by-product of the separation unit 10 and it will be used in the DCSG 15. By integrating the separation unit 10 and the DCSG 15, the organic contaminated by-product water can be used directly, without any additional treatment by the DCSG 15. This simplifies the separation facility 10 so that it can reject contaminated water without environmental impact. It is sent to the DCSG 15, where most of the organics are converted into hydrocarbon gas phase or are carbonic with the hot steam gas flow. The distilled water 19 produced by the distillation facility 11, possibly with the condensed steam from flow 12, are sent to the commercially available, non-direct, steam generator 4. The produced steam 5 is injected into an underground formation for EOR. The brine 26 is recycled back 14 to the DCSG and solids dryer 15 as described before. The production well 7 produces a mixture of tar, water and other contaminants. The oil and water are separated in commercially available plants 10 into water 9 and oil product 8.

FIG. 20 is an illustration of one embodiment of the present invention. It is similar to FIG. 19 with the following modifications described below: The solids lean flow 12 is mixed with saturated water 21 in vessel 20. The heat carried in the steam gas 12 can generate additional steam if its temperature is higher than the saturated water 21 temperature. The solids carried with the steam gas are washed by saturated liquid water 23. The solids rich water 24 is discharged from the bottom of the vessel 20 and recycled back to the DCSG 15 where the liquid water is converted into steam and the solids are removed in a dry form for disposal. Saturated “wet” solids free steam 22 flows to heat exchanger/condenser 30. The condensed water 36 is used for steam generation. The condensation heat 25 is used to operate a water treatment plant 11, as described in FIG. 19 above. To minimize the amount of steam 9 used to drive the DCSG 15, it is possible to recycle a portion of the produced saturated steam 22 as described in FIGS. 3, 3A and 3B. This option is shown as the dotted line. A portion of the produced steam 22 is recycled to drive the process. This steam is compressed 42 to allow the flow to be recycled and to overcome the heater and the SD-DCSG pressure drop. The steam is heated in a non-direct heat exchanger 41. Any type of heat exchanger/heater can be used at 41. One example is the use of a typical re-heater 43 that is part of a standard boiler design.

FIG. 21 is an illustration of a boiler, steam drive DCSG, solid removal and Mechanical Vapor Compression distillation facility for generating distilled water in the boiler for steam generation for EOR. BLOCK 4 includes a steam generation unit. Fuel 2, possibly with water in a slurry form, is mixed with air 1 and injected into a steam boiler 4. The boiler may have waste discharged from the bottom of the combustion chamber. The boiler produces high-pressure steam 3 from treated distillate feed water 5. The steam is injected into the underground formation through injection well 21 for EOR. Part of the steam 7 is directed to drive a DCSG 9. BLOCK 22 includes a steam drive DCSG 9. Solids rich water, like concentrated brine 8 from the distillation facility, is injected into the DCSG 9 where the water is mixed with super heated steam 7. The liquid water phase is converted to steam due to the high temperature of the driving steam 7. The DCSG can be a commercially available direct-contact rotary dryer or any other type of direct contact dryer capable of generating solid waste and steam from solid-rich brine water 8. The DCSG generates a stream of steam 10 with solid particles from the solid rich water 8. The DCSG in BLOCK 22 can generate its own driving steam 7 by recycling and heating a portion of the saturated produced steam 12, as described in FIGS. 3, 3A and 3B (not shown). The amount of water 8 is controlled to verify that all the water is converted into steam and that the remaining solids are in a dry form. The solid-rich steam gas flow 10 is directed to BLOCK 21 which separates the solids. The solids separation is in a dry solids separator 12. The dry solids separator is a commercially available package and it can be used in a variety of gas-solid separation designs. The solids lean flow 11 is mixed with saturated water 22 in a direct contact wash vessel 15. The solid remains carried with the steam are washed by saturated liquid water 22. The solids rich water 14 is discharged from the bottom of the vessel 22 and recycled back to dryer 9 where the liquid water is converted into steam and the solids are removed in a dry form for disposal. If the dry solid removal efficiency at 12 is high, it is possible to eliminate the use of the saturate water liquid scrubber 15. The produced saturated steam 23 is supplied to BLOCK 20, which is a commercially available distillation unit that produces distillation water 5. The brine water 8 is recycled back to the direct contact steam generator/solids dryer 15 where the liquid water is converted into steam and the dissolved solids remain in dry form. Distillation unit 19 is a Mechanical Vapor Compression (MVC) distillation facility. It receives de-oiled produced water 16 that has been separated in a commercially available separation facility (such as that currently in use by the industry) with additional make-up water (not shown). This water can be brackish, from deep underground formations or from any other water source that is locally available to the oil producers. The quality of the make-up water is suitable for the distillation facility 20, where there are typically very low levels of organics due to their tendency to damage the evaporator's performance or damage the boiler further in the process. The distilled water produced by distillation facility 19 is treated by the distillate treatment unit 17, typically supplied as part of the MVC distillation package. The treated distilled water 5 can be used in the boiler to produce 100% quality steam for EOR. The brine 8 and possibly the scrubbing water 14 are recycled back to the DCSG/dryer 9 as previously described. The heat from flow 23 is used to operate the distillation unit in Block 20. The condensing steam from flow 23 is recovered in the form of liquid distilled water 5. The high-pressure steam from the boiler in BLOCK 4 is injected into the injection well 21 for EOR or for other uses (not shown). With the use of a low pressure system (which includes a low pressure dryer), the thermal efficiency of the system is lower than using a high pressurized system with pressurized DCSG.

The following are examples for heat and material balance simulations:

Example 1

The graph in FIG. 22 simulates the process as described in FIG. 2A. The system pressure was constant at 25 bar. The liquid water 7 was at temperature of 25 C with a constant flow of 1000 kg/hour. The product 8 was saturated steam at 25 bar. The graph below shows the amount of drive steam 9 required to transfer the liquid water 7 into the gas phase as a function of the temperature of the driving steam 9. When 300 C driving steam is used, there is a need for 12.9 ton/hour of steam 9 to gasify one ton/hour of liquid water 7. When 500 C driving steam is used, there is a need for only 4.1 ton/hour of steam 9 to gasify one ton/hour of liquid water 7. The following are the results of the simulation:

Drive Steam 9     Drive Steam 9
Temperature(° C.) Flow (kg/hr)
600.00            3059.20
550.00            3502.50
500.00            4091.50
450.00            4914.46
400.00            6159.21
350.00            8290.00
300.00            12990.00
250.00            34950.00

Example 2

The graph in FIG. 23 simulates the process as described in FIG. 2A. The driving steam 9 temperature was constant at 450° C. The liquid water 7 was at temperature of 25° C. and had a constant flow of 1000 kg/hour. The produced steam product 8 was saturated. The graph shows the amount of drive steam 9 required to transfer the liquid water 7 into the gas phase as a function of the pressure of the driving steam 9. When the system pressure was 2 bar, 3.87 tons/hour of driving steam was needed to convert the water to saturated steam at temperature of 121° C. For a 50 bar system pressure, 5.14 tons/hour of driving steam was used to generate saturated steam at 256° C. The simulation results are summarized in the following table:

	Temperature	Driving
System	of Saturated	Steam
Pressure	produced	Flow
(bar)	Steam	(kg/hr)
100.00	311.82	5127.94
75.00	291.35	5161.78
50.00	264.74	5135.66
25.00	224.70	4914.46
20.00	213.11	4821.42
15.00	198.98	4696.41
10.00	180.53	4515.83
5.00	152.40	4218.44
3.00	134.03	4018.992
2.00	120.68	3870.57
1.00	100.00	3649.728

Example 3

The graph in FIG. 24 simulates the process as described in FIG. 2A where the water feed includes solids and naphtha. As the pressure increases, the saturated temperature of the steam also increases from around 100 C at 1 bar to around 312 C 100 bar. Thus, the amount of superheated steam input at 450 C also increases from around 2300 kg/hr to 4055 kg/hr. The graph in FIG. 24 represents the superheated driving steam input 9 and the total flow rate (including hydrocarbons) of the produced gas 8.

Flow Number	7	9	12	8
T, C	25.00	450.00	120.61	120.61
P, atm	2.00	2.00	2.00	2.00
Vapor Fraction	0.00	1.00	0.00	1.00
Enthalpy, MJ	−14885.08	−29133.36	−6692.49	−37325.62
Total Flow, kg/hr	1000.00	2311.54	414.73	2896.81
Water	600.00	2311.54	114.20	2797.34
Solids	300.00	0.00	300.00	4.14E−17
Naptha	100.00	0.00	0.53	99.47

Example 4

The following table simulates the process as described in FIG. 3 for insitue oilsands thermal extraction facilities, like SAGD, for two different pressures. The water feed is hot produced water at 200 C that includes solids and bitumen. The heat source Q′ for the simulation was 12 KW.

For a system pressure of 400 psi the total Inflow of water, solids and bitumen of flow 34 was 23.4 kg. 77% of the steam 31 is recycled as the driving steam 32 while 23% is discharged out of system at 283 C steam and hydrocarbons.

For a system pressure of 600 psi, the total Inflow of water, solids, and Bitumen of flow 34 was 22.5 kg. 80% of the steam 31 is recycled as the driving steam 32 while 20% is discharged out of system at 283 C steam and hydrocarbons.

	Flow Number
	34	35	31	32	36	33
T, C.	200	243.42	243.42	243.43	486.73	243.43
Press., psig	400	400	400	400	400.00	400.00
Vapor Fraction	0	0.00	1.00	1.00	1.00	1.00
Enthalpy, kW	−96.591	−5.06	−346.24	−266.80	−254.78	−79.69
Total Flow, kg/hr	23.4	1.17	96.89	74.66	74.66	22.30
Water, kg/hr	21.76	0.00	94.84	73.08	73.08	21.83
Solids	1.17	1.17	0.00	0.00	0.00	0.00
Hydrocarbons	0.470	0.000	2.048	1.578	1.578	0.471
T, C.	200	282.88	282.88	282.62	485.97	282.62
Press., psig	600	600.00	600.00	600.00	600.00	600.00
Vapor Fraction	0	0.00	1.00	1.00	1.00	1.00
Enthalpy, kW	−92.863	−4.78	−381.06	−305.04	−293.02	−76.26
Total Flow, kg/hr	22.5	1.12	107.11	85.74	85.74	21.43
Water, kg/hr	20.925	0.00	104.86	83.93	83.93	20.98
Solids	1.125	1.12	0.00	0.00	0.00	0.00
Bitumen	0.450	0.000	2.255	1.805	1.805	0.451

Example 5

The following process simulation described in FIG. 30 simulates a 600 psi system pressure. The graph in FIG. 30 simulates the impact of the produced water feed temperature on the overall process performance. Hot produced water that includes solids and bitumen contaminates is typical for insitue oilsands thermal extraction facilities like SAGD. The graph shows that for a constant heat flow, as the produced feed water temperature increases, the amount of produced steam increases accordingly. The heat source Q′ in the simulation was 12 KW. The driving steam 36 temperature was 482 C. 80% of the steam 31 is recycled to the heater as the driving steam 36 while 20% is discharged out of system at 283 C steam and hydrocarbons. The simulation shows that for feed water at a temperature of 20 C, 15.1 kg of produced steam is generated. For a temperature of 100 C, 17.4 kg of produced steam is produced and for a temperature of 220 C, 22.4 kg of produced steam is produced.

Example 6

The following table simulates the process as described in FIG. 4 for insitue oilsands thermal extraction facilities like SAGD. The water feed is hot produced water at 200 C that includes solids and bitumen. The heat source Q′ for the simulation was 12 KW and the system pressure was 600 psi. The total Inflow of water, solids, and bitumen of flow 47 was 22.5 kg. 79% of the steam 31 is recycled as the driving steam 36 while 21% is discharged out of system at 294 C steam and hydrocarbons.

In the simulation, 4.9 kw were removed at the flash/condensation unit 42 and used to pre-heat the water feed 47. The product was split from flow 31 (not shown on FIG. 4) replacing flow 46. Flows 44 and 45 were equal in this simulation.

		Product
	Flow Number	(split
	47	35	31	33	36	45	43	from 33)
T, C.	200	294.91	294.91	294.91	471.55	253.81	253.81	294.91
Press., psig	600	600.00	600.00	600.00	600.00	600.00	600.00	600.00
Vapor Fraction	0	0.00	1.00	1.00	1.00	1.00	0.13	1.00
Enthalpy, kW	−92.863	−4.76	−361.07	−285.24	−261.99	−274.01	−15.89	−75.82
Total Flow,	22.5	1.13	101.76	80.39	74.82	74.82	5.56	21.37
kg/hr
Water, kg/hr	20.925	0.00	99.64	78.72	74.82	74.82	3.90	20.92
SiO2	1.125	1.13	0.00	0.00	0.00	0.00	0.00	0.00
hydrocarbons	0.450	0.000	2.118	1.673	0.000	0.000	1.668	0.445

Example 7

The following table is the simulation results for the process described in FIG. 25. The water feed 1 is produced water from a SAGD separator and includes solids and hydrocarbons at a temperature of 200 C. The produced water 1 is mixed with superheated steam 7 at approximately 482 C. Recycled water 12 from scrubber 23 is recycled back to the water feed 1. Solid contaminates 3 are removed from separator 21. The produced steam 4 is divided into two flows—portion 6 of the produced steam (22%) at a temperature of 285 C and pressure of 600 psi is recovered from the system as the product for steam injection, or any other use. The remaining 78% of the produced steam 5 is cleaned in a wet scrubber with saturated water, potentially with additional chemicals that can efficiently removed silica and possibly other contaminates that were introduced with the produced water (like magnesium based additives, soda caustic, and others). Water 9 is fed into the scrubber 23 and the scrubbed water 12 is continually recycled back to the stage of steam generation. The scrubbed steam 8 is compressed by mechanical means or by steam ejector 24 to a heater 25. In the simulation, a 12 kw heater was used 25 to simulate a bench scale laboratory facility. In a commercial plant any heater can be used. The system simulation pressure was 600 psig. The superheated steam 7 is used as the driving steam to drive the process.

	Flow Number
	1	2	3	4	5	6
T, C.	200	284.78	284.78	284.78	284.77	284.77
Press., psig	600	600	600	600	600	600
Vapor Fraction	0	1	0	1	1	1
Enthalpy, kW	−74.29	−330.8	−3.82	−326.94	−255.03	−71.93
Total Flow, kg/hr	18	92.53	0.9	91.63	71.47	20.16
Water, kg/hr	16.74	90.01	0	90.01	70.21	19.8
Solids	0.9	0.9	0.9	0	0	0
Hydrocarbons	0.36	1.618	0	1.618	1.262	0.356
	Flow Number
		7	8	9	10	12
	T, C.	478.12	253.81	20	254.13	253.81
	Press., psig	600	600	600	601.46	600
	Vapor Fraction	1	1	0	1	0
	Enthalpy, kW	−255.05	−267.08	−13.25	−267.04	−1.21
	Total Flow, kg/hr	72.92	72.93	3	72.92	1.55
	Water, kg/hr	72.92	72.93	3	72.92	0.28
	Solids	0	0	0	0	0
	Hydrocarbons	0	0	0	6.99E−06	1.262

Another option to minimize the risk of build-ups in the injection piping is to recover the produced steam 6 from flow 8 (indicated on FIG. 25 as flow 6A). This option was simulated as described in the table below. In reality, flow 6A will be cleaner than flow 6, because the steam will be scrubbed by saturated liquid water 9. The scrubbing water 9 can include chemical to remove contaminates, like silica, from the produced steam 4. The simulation shows that this option do not affect the overall process efficiency. The size of scrubbing vessel 23 will increase with the increased flow.

	Flow Number
	1	2	3	4	5	6A
T, C.	200	267.16	267.16	267.16	267.16	253.81
Press., psig	600	600.00	600.00	600.00	600.00	600.00
Vapor Fraction	0	0.99	0.00	1.00	1.00	1.00
Enthalpy, kW	−75.7649	−340.01	−3.93	−336.03	−336.03	−76.38
Total Flow, kg/hr	18.36	96.85	0.92	95.93	95.93	20.86
Water, kg/hr	17.07	92.08	0.00	92.08	92.08	20.86
Solids	0.92	0.92	0.92	0.00	0.00	0.00
Hydrocarbons	0.370	3.848	0.000	3.848	3.848	0.000
	Flow Number
	7	8	9	10	12
T, C.	481.86	253.81	20.00	254.1276	253.81
Press., psig	600.00	600.00	600.00	601.4696	600.00
Vapor Fraction	1.00	1.00	0.00	1	0.00
Enthalpy, kW	−251.25	−263.09	−15.46	−263.249	−12.00
Total Flow, kg/hr	71.89	71.84	3.50	71.88519	6.73
Water, kg/hr	71.89	71.84	3.50	71.88519	2.88
Solids	0.00	0.00	0.00	0	0.00
Hydrocarbons	0.000	0.000	0.000	3.17E−06	3.848

Example 8

The following table are the simulation results for the process described in FIG. 26. The water feed 1 is produced water from a SAGD separator and includes solids and hydrocarbons at a high temperature of 200 C. (The produced water 1 is at a much lower flow of approx. 8 kg/hour compared to the flow of 18 kg/hour in example 25 because additional treated boiler feed water 10 is added later). The feed 1 is mixed with superheated steam 7 at approximately 482 C. Recycled water 12 from scrubber 23 is recycled back to the water feed 1. Solid contaminates 3 are removed from separator 21. The produced steam 4 is divided into two flows—portion 6 of the produced steam (75%) at a temperature of 271 C and pressure of 600 psi is recovered from the system as the product for steam injection in CSS, SAGD or any other steam use. Another option that wasn't simulated is to clean and scrub all the produced steam 4 to generate a cleaner produced steam for injection 6A. This option can be used in case contaminates in the produced steam 4 can damage the injection facility or block the formation over time. The remaining 25% of the produced steam 5 is cleaned in a wet scrubber with saturated water, potentially with additional chemicals to remove contaminates. Water 9 with a flow rate of 0.3 kg/hour and temperature of 20 C is fed into the scrubber 23 and the scrubbed water 12 is continually recycled back to the stage of the steam generation. The scrubbed steam 8 is condensed by direct contact with clean BFW 10 at a flow of 10 kg/hour and temperature of 20 C. The generated water 11 at a temperature of 250 C is pumped to low overpressure to generate circulation and compensate for the losses and is then transferred into superheated steam by a 12 kw heater 25 to simulate a bench scale laboratory facility. In a commercial plant any commercial boiler can be used to produce the superheated dry steam. The system simulation pressure was 600 psig. The superheated steam 7 at a flow of 16 kg/hour is used as the driving steam to drive the process.

	Flow No.
	1	2	3	4	5	6
T, C.	200.00	271.89	271.89	271.89	271.88	271.88
Press., psig	600.00	600.00	600.00	600.00	600.00	600.00
Vapor Fraction	0.00	0.99	0.00	1.00	1.00	1.00
Enthalpy, kW	−32.47	−87.32	−1.66	−85.64	−21.42	−64.27
Total Flow,	7.870	24.105	0.390	23.715	5.932	17.797
kg/hr
Water, kg/hr	7.320	23.500	0.000	23.500	5.879	17.636
Solids	0.390	0.390	0.390	0.000	0.000	0.000
Hydrocarbons	0.160	0.215	0.000	0.215	0.054	0.161
	Flow No.
	7	8	9	10	11	12
T, C.	660.37	253.81	20.00	20.00	250.31	253.81
Press., psig	600.00	600.00	600.00	600.00	600.00	600.00
Vapor Fraction	1.00	1.00	0.00	0.00	0.00	0.00
Enthalpy, kW	−53.87	−21.71	−1.32	−44.16	−65.87	−1.04
Total Flow,	15.927	5.927	0.300	10.000	15.927	0.305
kg/hr
Water, kg/hr	15.927	5.927	0.300	10.000	15.927	0.251
Solids	0.000	0.000	0.000	0.000	0.000	0.000
Hydrocarbons	0.000	0.000	0.000	0.000	0.000	0.054

To minimize the risk of build-ups in the downstream piping and equipment it is possible to recover the produced steam 6 from flow 8 (indicated on FIG. 25 as flow 6A). The following table are the simulation results for the process described in FIG. 26 with flow 6A as the produced steam exported from the system. The produced steam 6A is extracted from steam flow 8 after scrubbing in vessel 23 with water 9. Additional chemical can be added to the scrubbing water 9 to remove contaminates with stream 4.

	Flow No.
	1	2	3	4	5	6A
T, C.	200.00	253.81	253.81	253.81	253.81	253.81
Press., psig	600.00	600.00	600.00	600.00	600.00	600.00
Vapor	0.00	0.89	0.00	0.95	0.95	1.00
Fraction
Enthalpy,	−32.47	−104.51	−1.67	−102.07	−102.07	−71.18
kW
Total Flow,	7.870	28.770	0.390	28.380	28.380	19.436
kg/hr
Water, kg/hr	7.320	27.686	0.000	27.686	27.686	19.436
Solids	0.390	0.390	0.390	0.000	0.000	0.000
Hydro-	0.160	0.695	0.000	0.695	0.695	0.000
carbons
	Flow No.
	7	8	9	10	11	12
T, C.	482.16	253.81	20.00	20.00	239.99	253.81
Press., psig	600.00	600.00	600.00	600.00	600.00	600.00
Vapor	1.00	1.00	0.00	0.00	0.00	0.00
Fraction
Enthalpy,	−64.08	−23.73	−2.65	−52.3303	−76.06	−9.81
kW
Total Flow,	18.335	6.479	0.600	11.850	18.330	3.065
kg/hr
Water, kg/hr	18.335	6.479	0.600	11.850	18.330	2.370
Solids	0.000	0.000	0.000	0.000	0.000	0.000
Hydro-	0.000	0.000	0.000	0.000	0.000	0.695
carbons

Example 9

The following table are the simulation results for the process described in FIG. 27. The simulation is similar to Example 8 with a change to the production of the boiler feed water where instead of using clean Boiler Feed water to condense the generated steam for generating the superheated steam generator feed water, heat is recovered to condense the steam to BFW and is introduced back to the system to heat the feed water. By this arrangement, the need for fresh BFW is eliminated and replaced by condensation. Water feed 1 is heated with Q-in, that is a heat recovered from the condensation, and mixed with superheated steam 7. Recycled water 12 from scrubber 23 is recycled back to the water feed 1. Solid contaminates 3 are removed from separator 21. The produced steam 4 is divided into two flows—portion 6 of the produced steam (53%) at a temperature of 282 C and pressure of 600 psi is recovered from the system as the product for steam injection or any other use. The remaining 47% of the produced steam 5 is cleaned in a wet scrubber with saturated water, potentially with additional chemicals to remove contaminates. Water 9 at a flow of 4.1 kg/hour and temperature of 20 C is fed into the scrubber 23 and the scrubbed water 12 is continually recycled back to the stage of the steam generation. The scrubbed clean steam 8 is condensed by recovering the condensation heat Q-out that is returned back to the system for pre-heating the feed water as Q-in or for pre-heating other streams like 9. The generated water 11, at a temperature of 254 C, is pumped to low overpressure to generate circulation and compensate for the losses and is then generated into superheated steam by a 12 kw heater 25 to simulate a bench scale laboratory facility. In a commercial plant, any commercial boiler can be used to produce the superheated dry steam. The system simulation pressure was 600 psig. The superheated steam 7 at a flow of 18.7 kg/hour is used as the driving steam to drive the process. Another option to minimize the risk of build-ups in the injection piping is to recover the produced steam 6 from flow 8 (indicated on FIG. 25 as flow 6A).

	Flow No.
	1	2	3	4	5	6
T, C.	200.00	282.56	282.56	282.56	282.52	282.52
Press.,	600.00	600.00	600.00	600.00	600.00	600.00
psig
Vapor	0.00	0.99	0.00	1.00	1.00	1.00
Fraction
Enthalpy,	−86.378	−145.07	−4.46	−140.57	−66.07	−74.51
kW
Total	20.930	40.518	1.050	39.468	18.552	20.920
Flow,
kg/hr
Water,	19.460	38.678	0.000	38.678	18.180	20.501
kg/hr
Solids	1.050	1.050	1.050	0.000	0.000	0.000
Hydro-	0.420	0.791	0.000	0.791	0.372	0.419
carbons
	Flow No.
	7	8	9	11	12
T, C.	493.17	253.81	20.00	253.81	253.81
Press., psig	600.00	600.00	600.00	600.00	600.00
Vapor Fraction	1.00	1.00	0.00	0.00	0.00
Enthalpy, kW	−65.12	−68.38	−4.42	−77.12	−2.11
Total Flow,	18.671	18.671	1.000	18.671	0.881
kg/hr
Water, kg/hr	18.671	18.671	1.000	18.671	0.509
Solids	0.000	0.000	0.000	0.000	0.000
Hydrocarbons	0.000	0.000	0.000	0.000	0.372

Example 10

The following table are the simulation results for the process described in FIG. 28. The water feed 1 is tailings water from an open mine oilsands extraction facility. The feed water includes 30% solids and 3% solvents at a temperature of 20 C. The system is at a low pressure, close to atmospheric pressure. The produced water 1 is mixed with superheated steam 7 at 535 C. Solid contaminates 3 are removed from separator 21. The produced steam 4 is divided into two flows—portion 5 of the produced steam (70%) at a temperature 99.7 C is recycled, using mechanical compression, an ejector (not shown) or any other means, to generating the recycle flow. The recycled steam 5 is heated with a 12 kw heat source to generate superheated steam 7 at a temperature of 534 C. The remaining 30% of the produced steam 8 is condensed by direct contact mixture with process water 9 at a temperature of 20 C to generate 80 C process water that can used in the extraction process. The produced steam 4 can be further cleaned with any dry or wet commercially available cleaning systems, such as a wet scrubber (not shown) with saturated water, possibly with additional chemicals to remove contaminates. This cleaning can prevent build-ups at the recycling low pressure compressing unit and the heating unit 25. A total of 206 kg/hour of hot water is generated in this simulation from a 12 kw heat sorce.

	Flow Number
	1	2	3	4	5	6
T, C.	20.00	99.73	99.73	99.73	99.73	108.00
Press., atm	1.00	1.00	1.00	1.00	1.00	1.10
Vapor Fraction	0.00	0.88	0.00	1.00	1.00	1.00
Enthalpy, kW	−132.07	−293.79	−41.37	−248.71	−174.10	−173.88
Total Flow,	30.00	78.84	9.00	69.84	48.89	48.89
kg/hr
Water, kg/hr	20.10	66.85	0.00	66.85	46.79	46.79
Solids	9.00	9.00	9.00	0.00	0.00	0.00
N-Butane	0.45	1.50	0.00	1.50	1.05	1.05
N-Pentane	0.32	1.05	0.00	1.05	0.73	0.73
N-Hexane	0.14	0.45	0.00	0.45	0.31	0.31
	Flow Number
	7	8	9	10	11
T, C.	534.94	99.73	20.00	80.11	80.11
Press., atm	1.00	1.00	1.00	1.00	1.00
Vapor Fraction	1.00	1.00	0.00	1.00	0.00
Enthalpy, kW	−161.88	−74.61	−821.39	−0.61	−895.39
Total Flow, kg/hr	48.89	20.95	186.00	0.51	206.44
Water, kg/hr	46.79	20.05	186.00	0.10	205.95
Solids	0.00	0.00	0.00	0.00	0.00
N-Butane	1.05	0.45	0.00	0.26	0.18
N-Pentane	0.73	0.31	0.00	0.12	0.20
N-Hexane	0.31	0.13	0.00	0.03	0.11

Example 11

The following table are the simulation results for the process described in FIG. 29. The water feed 1 is tailings water from an open mine oilsands extraction facility. The feed water includes 30% solids and 3% solvents at a temperature of 20 C. The system is at a low pressure, close to atmospheric pressure. The produced water 1 is mixed with superheated steam 7 at 492 C. Solid contaminates 3 are removed from separator 21. The produced steam is condensed by direct contact mixture with process water 9 at a temperature of 20 C to generate 80 C process water that can be used in the extraction process. A portion of the produced water is heated in boiler 25 to generate superheated steam. The flow to produce the steam 5 can be further treated to remove contaminates to increase its quality to BFW quality water. Another option is to split the produced steam 4, scrub a portion, condense the clean scrubbed steam to water, possibly with water from an exterior source, and use the clean condensate to generate the super heated steam 7. This option was described in other figures but is not reflected in the current simulation.

	Flow No.
	1	2	3	4	5	6
T, C.	20	110.46	110.46	110.46	80.07	80.07
Press., atm	1	1.00	1.00	1.00	1.00	1.10
Vapor Fraction	0	1.00	0.00	1.00	0.00	0.00
Enthalpy, kW	−20.31	−68.23	−2.51	−65.72	−59.92	−59.92
Total Flow,	6	19.80	1.80	18.00	13.80	13.80
kg/hr
Water, kg/hr	4.02	17.81	0.00	17.81	13.79	13.79
Solids	1.8	1.80	1.80	0.00	0.00	0.00
Hydrocarbons	0.180	0.194	0.000	0.194	0.015	0.015
	Flow No.
	7	8	9	10	11
T, C.	492.40	80.07	20.00	80.07	80.07
Press., atm	1.00	1.00	1.00	1.00	1.00
Vapor Fraction	1.00	0.00	0.00	1.00	0.00
Enthalpy, kW	−47.91	−803.20	−737.48	0.00	−743.28
Total Flow, kg/hr	13.80	185.00	167.00	0.00	171.20
Water, kg/hr	13.79	184.81	167.00	0.00	171.02
Solids	0.00	0.00	0.00	0.00	0.00
Hydrocarbons	0.015	0.194	0.000	0.000	0.180

Example 12

The following table is a simulation of the method described in FIG. 3 that illustrated producing steam with the use of a heat source without using an external source for the driving steam and with the use of a high pressure steam ejector to generate the internal flow in the system. SD-DCSG 30 includes a hot and dry steam injection 36. In the simulation, the driving steam temperature was around 480 C—a typical re-heater temperature. Low quality produced water 34, at a temperature of 200 C with solids and bitumen contaminates, is injected into the steam. Inside the SD-DCSG the injected liquid water is converted into steam at 280 C temperature and is at the same 600 psi pressure as the dry driving steam 36. An 80% portion of the generated steam 32 is recycled through the ejector. The ejector is only designed to create the steam flow through heat exchanger 38 and create the flow through the SD-DCSG 30. High pressure steam 40 at a pressure of 1450 psi and a temperature of 311 C is injected through ejector to generate the required over pressure and flow in line 36. The produced low pressure steam flows to heat exchanger 38 where 12 kw heat is added to the recycled steam flow 32 to generate a heated “dry” steam 36 at 480 C. This steam is used to drive the SD-DCSG as it is injected into the steam generation enclosure 30 and the excess heat energy is used to evaporate the injected water and generate additional steam 31 at 280 C. The produced steam 31 or just the recycled produced steam 32 can be cleaned of solids carried with the steam gas by an additional commercially available system (not shown).

	Line Number
		Inside
		SD-
		DCSG				Ejector
	34	30	35	31	32	Discharge	36	33	40
T, C.	200	280.46	280.46	280.46	280.45	279.93	480.69	280.45	311.59
Press., psig	600	600.00	600.00	600.00	600.00	601.47	600.00	600.00	1450.38
Vapor	0	1.00	0.00	1.00	1.00	1.00	1.00	1.00	1.00
Fraction
Enthalpy,	−92.863	−387.97	−4.78	−383.14	−302.80	−306.85	−295.10	−80.49	−4.05
kW
Total Flow,	22.5	108.49	1.22	107.26	84.82	85.92	85.99	22.55	1.10
kg/hr
Water,	20.925	105.37	0.00	105.37	83.27	84.37	84.44	22.14	1.10
kg/hr
Solids	1.125	1.13	1.13	0.00	0.00	0.00	0.00	0.00	0.00
Bitumen	0.450	1.995	0.100	1.895	1.545	1.545	1.545	0.411	0.000

Example 13

The following table simulates the process as described in FIG. 3 for in-situ oilsands thermal extraction facilities, like SAGD, for 600 psi pressures. The water feed is hot produced water at 200 C that includes solids and bitumen. The heat source Q′ for the simulation was 12 KW. A portion of the heavy hydrocarbons are separated with the solids.

	Flow Number
	34	35	31	32	36	33
T, C.	200	283.24	283.24	283.08	486.97	283.08
Press., psig	600	600.00	600.00	600.00	600.00	600.00
Vapor Fraction	0	0.00	1.00	1.00	1.00	1.00
Enthalpy, kW	−92.863	−4.78	−380.72	−304.70	−292.68	−76.17
Total Flow, kg/hr	22.5	1.23	106.83	85.56	85.56	21.39
Water, kg/hr	20.925	0.00	104.77	83.85	83.85	20.96
Solids	1.125	1.13	0.00	0.00	0.00	0.00
Bitumen	0.450	0.108	2.055	1.713	1.713	0.428

The table and the graph in FIG. 30 show the produce steam amount as a function of the feed water temperature in the system, as described in example 13. The simulation shows that with 20 C feed water, 15.1 kg/hr steam at 600 psi and 280 C will be produced from 12 kw heat source. With 240 C produced feed water, 23.5 kg/hr steam at 600 psi and 280 C will be produced from 12 kw heat source. There is an advantage to using hot produced water as the heat energy within the produced water: it will increase the amount of the produced steam. A portion of the hydrocarbons with the produced water will be converted to gas and flow with the produced steam.

Claims

1. A method for steam production for extraction of oil, said method comprising the steps of: generating steam through indirect heat exchange;mixing said steam with liquid water having solids and organics contaminates, so as to transfer said liquid water from a liquid phase to a gas phase; andremoving solids to produce solids free gas phase steam.

2. A method for steam production for oil production, said method comprising the steps of: generating steam through indirect heat exchange;using the generated steam energy to directly gasify liquid water with solids and organic contaminated, so as to transfer said liquid water from a liquid phase to a gas phase;removing solids to produce solids free gas phase steam;condensing the generate steam to generate heat and water; andusing the generated heat and water for oil production.

3. A system for producing steam for extract heavy bitumen, the system comprising: a heat exchanger means for indirectly heating water to generate superheated steam;a steam drive direct contact steam generator, mixing steam generated by said heater with water containing levels of solids therein to form a steam stream and solids discharged streams, wherein said steam drive direct contact steam generator is in fluid connection to said heater; andan enhanced oil recovery facility in fluid connection to said steam drive direct contact steam generator.

4. A system for producing steam for extract oil production bitumen, the system comprising: a pressurized longitude mixing chamber means for directly mixing steam and water;an internal rotating element within the mixing chamber, said rotating element enhancing the mixture between the steam and the water; andan inlet for steam, an inlet for water, an outlet for waste and an outlet for steam.

5. A system for producing steam for extract oil production bitumen, the system comprising: a pressurized longitude mixing chamber means for directly mixing steam and water;a water inlet located at the upper section of the enclosure;a steam injection inlet located below the water inlet;a produced steam outlet located above the injection steam inlet; anda waste outlet located at the lower point of the system.

6. The method of claim 1, wherein a portion of said generated produced steam is recycled and heated indirectly before being mixed with the said liquid water having solids and organics contaminates.

7. The method of claim 1, wherein said generated superheated steam is generated in a boiler from treated water flow before mixed with said liquid water having solids and organics contaminates.

8. The method of claim 6, further comprising the step of: circulating the portion of the produced steam in a steam ejector, wherein steam for operating said steam ejector is added to the produced steam.

9. The method of claim 1, further comprising the step of: injecting the produced steam to recover oil through an oil injection well.

10. The method of claim 8, wherein the feed water is comprised of hydrocarbons that converted to gas and mixed with the steam.

11. The method of claim 9, further comprising the step of: adding solvents to the produced steam prior to injecting underground.

12. The method of claim 1, further comprising the step of: scrubbing a portion of the produced steam by mixing with saturated water and recycling the saturated water with the scrubbed contaminates back to the step of mixing the contaminated water with said super heated steam.

13. The method of claim 12, further comprising the step of: adding chemicals to said saturated scrubbing water so as to improve scrubbing performance of contaminates.

14. The method of claim 12, further comprising the step of: using a portion of the scrubbed steam as recycle fluid through an heater to generate said superheated steam.

15. The method of claim 2, further comprising the step of: separating non-condensable gases, having hydrocarbons and solvent remains, from the condensed hot water; andcombusting said non-condensable gases generating said superheated steam.

16. The method of claim 1, further comprising the steps of: producing oil and water from a production well;separating portion of the water from hydrocarbons, solvents, and solids contaminates; andmixing said produced water with said superheated steam.

17. The system of claim 3, further comprising: a production well producing a mixture of water, oil and gas;a separator fluidly connected to the production well for reparations portion of the produce water from the oil, being fluidly connected to said direct contact steam generator; anda heater for generating said superheated driving steam.

18. The system of claim 17, further comprising: a high pressure steam supply to an ejector; andan ejector means for recycling portion of said produced steam from said direct contact steam generator to said heater to generate said driving superheated driving steam.

19. The system of claim 17, wherein said direct contact steam generator and said heater are located on a well pad in proximity to the steam injection well.