US20140305645A1

US20140305645A1 - Reduced blowdown steam generation

Info

Publication number: US20140305645A1
Application number: US14/251,278
Authority: US
Inventors: Scott Macadam
Original assignee: ConocoPhillips Co
Current assignee: ConocoPhillips Co
Priority date: 2013-04-11
Filing date: 2014-04-11
Publication date: 2014-10-16
Also published as: CA2902612A1; WO2014169245A1

Abstract

Steam is generated using high total dissolved solids (TDS) boiler feedwater while still maintaining relatively low boiler blowdown rates. In one embodiment, a boiler is adapted to generate low quality steam from the high TDS feedwater to maintain wet conditions in the boiler tubes to mitigate against fouling/scaling problems. The low quality steam is then separated into a vapor fraction and a liquid blowdown stream. The vapor fraction is superheated to superheated steam. The liquid blowdown stream is allowed to exchange heat with the thus-created superheated steam to vaporize a portion of the blowdown to form a finished steam and a waste stream. This reduces the blowdown to waste and creates more end user steam. The finished steam is routed to its end use, e.g., a hydrocarbon thermal recovery process. Advantages include lower cost, higher efficiency, and less equipment complexity.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a non-provisional application which claims benefit under 35 USC §119(e) to U.S. Provisional Application Ser. No. 61/810,779 filed Apr. 11, 2013, entitled “REDUCED BLOWDOWN STEAM GENERATION,” which is incorporated herein in its entirety.

FIELD OF THE INVENTION

The present invention relates generally to methods and systems for generating steam with reduced blowdown levels.

BACKGROUND

The recovery of some heavy crude oils, such as bitumen, benefit from the use of various thermal recovery methods. Because of their high viscosity, these heavy crude oils are often immobile at the initial viscosity of the oil at reservoir temperature and pressure. Indeed, such heavy oils may be quite thick and have a consistency similar to that of peanut butter or heavy tars, making their extraction from the reservoir especially challenging. Accordingly, conventional approaches to recovering these heavy oils often focus on methods for lowering the viscosity of the heavy oil so that the heavy oil may be produced from the reservoir.
Perhaps the most common of the thermal recovery methods used to recovery heavy oils is the steam assisted gravity drainage (SAGD) thermal recovery process. SAGD is an advanced form of steam stimulation in which a pair of horizontal wells is drilled into an oil reservoir, one a few meters above the other. Steam is continuously injected into the upper wellbore to heat the oil and reduce its viscosity, causing the heated oil to drain into the lower wellbore, where the oil is then pumped out and recovered. Like other thermal recovery processes, the SAGD process is highly energy intensive and requires a great deal of steam.
Other thermal recovery processes include steam flooding and the cyclic steam stimulation, otherwise known as the “huff and puff” method. Each of these methods typically has their steam requirements produced onsite in proximity to the reservoir steam injection wells.
For economic reasons, water produced from the formation is often used to produce the steam as this water is a much cheaper and economical source of water than using fresh water. Additionally, using the produced water allows the produced water to be recycled instead of having to costly treat and/or dispose of the produced water. Unfortunately, the produced water is often contaminated with a relatively high level of total dissolved solids (e.g. from about 3,000 to about 8,000 ppm Total Dissolved Solids). This contamination poses a fouling and scaling problem in boilers. To mitigate the fouling and scaling in the boilers in these situations, the boilers are often operated under wet conditions. That is, the boilers are operated to produce low quality steam (e.g. 75-80 percent quality steam) to maintain wet conditions in the boiler tubes to reduce fouling and scaling. While operating the boilers this way mitigates fouling and scaling problems that would otherwise result, it also results in high blowdown rates. Blowdown is the amount of water as a ratio of boiler feedwater that is discarded from the boiler, usually from mud drum of the boiler to provide an effluent stream for removing the dissolved solids that would otherwise build-up in the boiler.
While high blowdown rates allows the boiler to accept high TDS boiler feedwater and is effective for removing dissolved solids from the boiler system, high blowdown rates substantially increase both the capital costs and the operating costs of steam generation. Generally, these increased costs are due several reasons, namely (i) the complex heat recovery systems required to exchange heat between the blowdown and the boiler feedwater streams, (ii) the increased required capacity of the water treatment plant to handle the high blowdown operation, (iii) the increased volume of the waste discharge (e.g. to disposal well, to a control device, or other), and (iv) the consequent increase to the makeup water requirements.
Low boiler blowdown rates could be achieved by using low blowdown boilers such as drum boilers or forced circulation steam generators. These boilers would enable blowdown rates of only about 2-5% but would require feedwater with significantly lower TDS levels to mitigate against the scaling and fouling issues. Unfortunately, water with such lower TDS levels is typically not readily available at SAGD sites. While lower TDS levels could be attained by using alternate water treatment technologies such as mechanical vapor compression (MVC) evaporators, these technologies however would impose significant capital and operating cost on the SAGD surface facility. Such increased costs would make such conventional technologies economically unattractive.
Accordingly, enhanced methods for generating steam are needed that are able to leverage the use of high TDS boiler feedwater in a way that is economically attractive and that address one or more disadvantages of the prior art.

SUMMARY

The present invention relates generally to methods and systems for generating steam with reduced blowdown levels.
In certain embodiments, a method for generating steam for use in a steam assisted gravity drainage (SAGD) thermal recovery process using high total dissolved solids (TDS) boiler feedwater comprises the steps of: introducing the high TDS boiler feedwater to a boiler wherein the boiler comprises an evaporator; generating low quality steam in the evaporator from the high TDS boiler feedwater; separating the low quality steam into a vapor fraction and a liquid blowdown stream; introducing the vapor fraction to a superheater to superheat the vapor fraction into superheated steam wherein the superheater is external to the boiler; allowing the liquid blowdown stream to exchange heat with the superheated steam to vaporize a portion of the blowdown stream to form a finished steam and a waste stream; introducing the finished steam to the SAGD process.
In certain embodiments, a method for generating steam using high total dissolved solids (TDS) boiler feedwater comprises the steps of: introducing the high TDS boiler feedwater to a boiler wherein the boiler comprises an evaporator; generating low quality steam in the evaporator from the high TDS feedwater; separating the low quality steam into a vapor fraction and a liquid blowdown stream; introducing the vapor fraction to a superheater to superheat the vapor fraction into superheated steam; and allowing the liquid blowdown stream to exchange heat with the superheated steam to vaporize a portion of the blowdown stream to form a finished steam and a waste stream.
In certain embodiments, the superheater is a separately-fired heater external to the boiler and is retrofitted to an existing SAGD boiler system.
The features and advantages of the present invention will be apparent to those skilled in the art. While numerous changes may be made by those skilled in the art, such changes are within the spirit of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the present disclosure and advantages thereof may be acquired by referring to the following description taken in conjunction with the accompanying figures, wherein:

FIG. 1 illustrates a simplified example of a steam generation system using boiler feedwater with a high level of total dissolved solids (TDS) while still maintaining a relatively low boiler blowdown rate in accordance with one embodiment of the present invention.

FIG. 2 illustrates a simplified example of a steam generation system similar to FIG. 1 but where the superheater is a separately-fired heater from boiler. in accordance with one embodiment of the present invention.

FIG. 3 illustrates an evaporator with drum boiler.

FIG. 4 illustrates a process with superheated steam vaporization of evaporator blow-down.

While the present invention is susceptible to various modifications and alternative forms, specific exemplary embodiments thereof have been shown by way of example in the drawings and are herein described in detail. It should be understood, however, that the description herein of specific embodiments is not intended to limit the invention to the particular forms disclosed, but on the contrary, the intention is to cover all modifications, equivalents, and alternatives falling within the spirit and scope of the invention as defined by the appended claims.

DETAILED DESCRIPTION

The present invention relates generally to methods and systems for generating steam with reduced blowdown levels.
In certain embodiments, methods and systems are provided for generating steam using boiler feedwater with a high level of total dissolved solids (TDS) while still maintaining a relatively low boiler blowdown rate. In one embodiment, a method for generating steam uses high total dissolved solids (TDS) boiler feedwater. The high TDS boiler feedwater is introduced to a boiler. The boiler is adapted to generate low quality steam from the high TDS feedwater. The low quality steam maintains wet conditions in the boiler tubes to mitigate against fouling and scaling problems. The low quality steam is then separated into a vapor fraction and a liquid blowdown stream and the vapor fraction is introduced to a superheater to superheat the vapor fraction into superheated steam. The liquid blowdown stream, on the other hand, is allowed to exchange heat with the thus-created superheated steam to vaporize a portion of the blowdown stream to form a finished steam and a waste stream. This use of the superheated steam reduces the overall amount of blowdown routed to waste and has the added advantage of creating even more end user steam. The finished steam may then be routed to its ultimate end use, for example, a hydrocarbon thermal recovery process such as a SAGD process.
Advantages of the enhanced methods and systems described herein include one or more of the following advantages: lower cost, higher efficiency, and less equipment complexity. Other features, embodiments, and advantages will be apparent from the disclosure herein.
Reference will now be made in detail to embodiments of the invention, one or more examples of which are illustrated in the accompanying drawings. Each example is provided by way of explanation of the invention, not as a limitation of the invention. It will be apparent to those skilled in the art that various modifications and variations can be made in the present invention without departing from the scope or spirit of the invention. For instance, features illustrated or described as part of one embodiment can be used on another embodiment to yield a still further embodiment. Thus, it is intended that the present invention cover such modifications and variations that come within the scope of the invention.
FIG. 1 illustrates a simplified example of a steam generation system using boiler feedwater with a high level of total dissolved solids (TDS) while still maintaining a relatively low boiler blowdown rate in accordance with one embodiment of the present invention. In this example, steam generation system 100 is shown generating finished steam 153 from boiler feedwater 113.
More particularly, boiler feedwater 113 feeds boiler steam tubes 115 of boiler 105. Fuel 123 and oxidant 125 combust at burner 120 to produce hot combustion gases for heating boiler steam tubes 115. The combustion gases exit boiler 105 as flue gas 127. This heat of combustion converts boiler feedwater 113 to low quality steam 117. As used herein, the term low quality steam refers to steam having a quality of from about 60 percent to about 90 percent saturated steam. Unlike many other conventional boilers, maintaining wet conditions in boiler steam tubes 115 reduces the scaling and/or fouling problem that would otherwise occur when using a boiler feedwater having a high TDS level.
Low quality steam 117 is not ready yet for use by end users. The amount of water in low quality steam 117 would likely pose significant water hammer and erosion problems to downstream pipe if the water component were not removed before sending low quality steam 117 to end users. Accordingly, low quality steam 117 is routed to separator 130 to separate low quality steam 117 into vapor fraction 135 and blowdown stream 133.
Vapor fraction 135 must be further superheated before transmission to end user(s) 190. Failure to superheat vapor fraction 135 before sending to end user(s) 190 would result in undesirable condensate buildup from vapor fraction 135 due to heat losses and pressure drop that would inevitably occur during transmission of vapor fraction 135 to end user(s) 190. To superheat vapor fraction 135, vapor fraction 135 is routed to superheater 140 which heats vapor fraction 135 above its saturation temperature to form superheated steam 143.
Because of the high TDS level in boiler feedwater 113, the flowrate of blowdown stream 133 must be sufficiently high to remove the dissolved solids from boiler 105. This relatively high flowrate of blowdown stream 133 would ordinarily introduce a series of disadvantageous costs. First, all blowdown for which another end use is not found must be treated and disposed of. The treatment costs of boiler blowdown naturally increases with increased blowdown flowrate. Consequently, any reduction in the amount of boiler blowdown significantly reduces water treatment savings, by avoiding the larger water treatment that would otherwise be required and by realizing lower ongoing water treatment costs due to the reduced boiler blowdown.
One way of reducing the amount of blowdown is to allow superheated steam 143 to vaporize all or a portion of blowdown stream 133. In the example depicted in FIG. 1, superheated steam 143 exchanges heat with blowdown stream 133 in heat exchanger 150. Heat exchanger 150 is any heat exchanger suitable for exchanging heat between these two streams, including, but not limited to, a closed heat exchanger, a mixing vessel which allows the streams to intimately mix, or any combination thereof. Thus, heat exchanger 150 produces waste stream 155 and finished steam 153 suitable for routing to end user(s) 190. End user(s) 190 may include any hydrocarbon thermal recovery process, including, but not limited to, a SAGD process. Waste stream 155 is the remaining liquid stream or solids which were not vaporized by superheated steam 143 in heat exchanger 150. Thus, the total amount of blowdown from steam generation system 100 is reduced, which in turn reduces the amount of flow that must be treated in water treatment facilities.
FIG. 2 illustrates a system similar to FIG. 1, using like-reference numerals for like-elements where each like-reference numeral begins with a “2” instead of a “1.” Here however, boiler 205 and superheater 240 are separately-fired heaters. Boiler 205 is fired by fuel 223A and oxidant 225A at burner 220A to produce hot combustion gases 227A for vaporizing boiler feedwater 213 in superheater steam tubes 240A. Likewise, superheater 240 is a separately-fired heater fired by fuel 223B and oxidant 225B at burner 220B to produce hot combustion gases 227A. This heat of combustion converts boiler feedwater 213 to low quality steam 217. As used herein, the term low quality steam refers to steam having a quality of from about 60 percent to about 90 percent saturated steam. Low quality steam 217 is routed to separator 230 to separate low quality steam 217 into vapor fraction 235 and blowdown stream 233. Vapor fraction 235 must be further superheated before transmission to end user(s) 290. Vapor fraction 235 is routed to superheater 240 which heats vapor fraction 235 above its saturation temperature to form superheated steam 243.
FIG. 3 illustrates a system similar to FIG. 1, using like-reference numerals for like-elements where each like-reference numeral begins with a “3” instead of a “1.” Here, however, boiler 305 is preceded by a mechanical vapor compression evaporator 360
As most existing SAGD boilers do not include a superheater integral their boiler, the system described here is useful as it lends itself to retrofitting existing systems by allowing a separately-fired heater to be added to achieve the objectives of reducing boiler blowdown and/or being able to accept high TDS boiler feedwater with minimal capital cost (that is, avoiding the capital cost of replacing the entire existing boiler with a boiler having an integrated superheater).
All other aspects of the operation of this system are analogous to the system described with respect to FIG. 1. In this way, with minimal additional capital cost, existing SAGD boilers may be retrofitted with minimal additional equipment to reduce boiler blowdown and to allow the SAGD boiler system to accept higher TDS boiler feedwater.
It is recognized that any of the elements and features of each of the devices described herein are capable of use with any of the other devices described herein without limitation. Furthermore, it is recognized that the steps of the methods herein may be performed in any order except unless explicitly stated otherwise or inherently required otherwise by the particular method.
To facilitate a better understanding of the present invention, the following examples of certain embodiments are given. In no way should the following examples be read to limit, or define, the scope of the invention.

EXAMPLES

Example 1

Superheater with Blow-Down Evaporation

A process analysis was performed to quantify the performance of the embodiment depicted in FIG. 1. Two cases were investigated: (i) a once through steam generator (OTSG)=that produces 75% quality steam at 96.4 bar(g), and (ii) a system that produces the same 75% quality steam, superheats the steam to 427° C., and mixes the superheated steam with blowdown water. This temperature is the minimum temperature for full evaporation of the blowdown water. Temperatures below 427° C. will result in a liquid (rather than a solid) waste discharge from heat exchanger 150 depicted FIG. 1. The results for the two cases are compared in Table 1 below.

TABLE 1

OTSG vs Superheater with blow-down evaporation
(basis: 1,566 tonne/hr SAGD steam)

	OTSG	Superheater with Blow-
Parameter	Base Case	down Evaporation

Steam temperature	309° C.	427° C.
Steam pressure	96.4 bar (g)	96.4 bar (g)
Steam quality	75%	75%
Steam superheat level	0° C.	118° C.
Natural Gas Flowrate	71	72
(tonne/hr)
Feedwater Flowrate (tonne/hr)	2,088	1,566
Steam Flowrate (tonne/hI′)	1,566	1,566

As shown in the table, the 427° C. superheated blow-down reduces the feedwater flowrate, and consequently the capacity of the water treatment plant, by 25%, at the cost of a slight increase in the natural gas firing rate. The reduced water treatment capacity represents a significant savings to a SAGD surface facility.

Example 2

Enhanced Mechanical Vapor Compression Evaporator

FIG. 3 demonstrates water treatment and steam generation process utilized in some SAGD applications. De-oiled SAGD produced water and make-up water is delivered to a produced water evaporator as feed (stream 1). The evaporator is typically a mechanical vapor compression (MVC) evaporator that produces evaporator distillate, at near atmospheric pressure conditions. This distillate is relatively high in purity, with TDS levels <100 ppm, and is suitable as boiler feed water (BFW) for drum boilers. Note that this system is distinct from the other SAGD system comprising warm lime softening (WLS) and once through steam generators (OTSGs), where the OTSG BFW contains 2,000-8,000 ppm TDS. The drum boiler in FIG. 3 converts the clean BFW into saturated steam that is delivered to the SAGD well pads. The drum boiler blow-down, typically 2-5% of the BFW flowrate, is recycled to the MVC evaporator, but this is a clean stream due to the high purity of the BFW. The evaporator produces a blow-down stream that is treated and disposed of MVC evaporators typically operate at concentration factors (CFs) of 20-40, meaning that the evaporator blowdown flowrate is only 2.5-5.0% that of the feed rate, but 20-40 times more concentrated, with TDS levels of 40,000-100,000 ppm. The liquid that is circulated through the evaporator has the same high TDS levels. The high TDS levels raise the boiling point of the liquid in the evaporator, increasing the electrical load of the vapor compressor.
FIG. 4 refers to an example of how superheated steam can be used to enhance the MVC/drum boiler system. In one embodiment, the drum boiler includes a superheater that adds heat to the saturated steam from the drum, producing superheated steam. In another embodiment, the MVC evaporator is operated at a considerably lower CF. This improves the performance of the evaporator, but necessitates a much higher blowdown flowrate. This less concentrated blowdown stream is boosted in pressure and contacted with the superheated steam in a contactor. The superheated steam vaporizes part of the blow-down, producing saturated SAGD steam and a more concentrated blow-down stream that resembles the evaporator blow-down stream in FIG. 3.
The process in FIG. 4 offers two advantages. Firstly it enables the evaporator to operate at lower CFs and consequently lower TDS levels, lowering the boiling point elevation and load of the compressor. Secondly, it allows more steam to be generated at relatively low marginal costs. The cost is additional CAPEX for the superheater, blow-down pump, and contactor, and additional OPEX for the incremental gas burned in the drum boiler. Table I shows water and steam flowrates for the two cases. For simplicity, normalized mass units are used.
In the reference case, 100 units of evaporator feed are combined with 2 units of drum boiler blow-down to produce 98.6 units of BFW and 3.4 units of evaporator blow-down for disposal. The drum boiler converts 98.6 units of BFW into 96.6 units of SAGD steam and 2 units of boiler blow-down. Key assumptions are an evaporator CF of 30, and boiler blow-down of 2%.
In the superheated steam case shown in FIG. 4, the evaporator also produces 98.6 units of distillate, while the boiler also produces 96.6 units of saturated steam, which is converted to 96.6 units of superheated steam at 400° C. and 96.4 bar(g). However, the MVC evaporator is operated at a CF of only 6, resulting in a blow-down flowrate of 19.4 units. This blowdown is contacted with the 96.6 units of superheated steam to produced 112.5 units of saturated steam at 309° C. and 96.4 bar(g) and 3.5 units of concentrated blowdown for disposal. Steam tables show that there is sufficient enthalpy in 96.6 units of 400° C., 96.4 bar(g) superheated steam to vaporize 15.9 units of evaporator blowdown at 100° C.

TABLE II

Water and steam flowrates for processes in FIGS 1 and 2
(normalized mass units)

		Superheated Steam
Stream	Reference Case	Case

Evaporator feed (1)	100	116
Drum boiler blow-down (2)	2	2
Evaporator blow-down (3)	3.4	19.4
Evaporator distillate (4)	98.6	98.6
Saturated steam (5)	96.6	96.6
Superheated steam (6)	—	96.6
Saturated steam (7)	—	112.5
Evaporator blow-down (8)	—	3.5

In summary, Table I shows that the process in FIG. 4 can deliver 112.5 units of SAGD steam, versus the 96.6 units in the reference case. This demonstrates that utilizing 400° C. superheated steam can increase the steam output by 16%.
Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations and equivalents are considered within the scope and spirit of the present invention. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.

Claims

What is claimed is:

1. A method for generating steam using high total dissolved solids (TDS) boiler feedwater comprising the steps of:

introducing a high total dissolved solids (TDS) boiler feedwater to a boiler wherein the boiler comprises an evaporator;

generating a low quality steam in the evaporator from the high TDS boiler feedwater;

separating the low quality steam into a vapor fraction and a liquid blowdown stream;

introducing the vapor fraction to a superheater to superheat the vapor fraction into superheated steam; and

allowing the liquid blowdown stream to exchange heat with the superheated steam to vaporize a portion of the blowdown stream to form a finished steam and a waste stream.

2. The method of claim 1 wherein the high TDS boiler feedwater comprises from about 3,000 to about 8,000 ppm total dissolved solids including approximately 3,500 ppm TDS, 4,000 ppm TDS, 4,500 ppm TDS, 5,000 ppm TDS, 5,500 ppm TDS, 6,000 ppm TDS, 6,500 ppm TDS, 7,000 ppm TDS, 7,500 ppm TDS and 8,000 ppm TDS.

3. The method of claim 1 wherein the low quality steam has a quality from about 60% to about 90% saturated steam including approximately 60%, 65%, 70%, 75%, 80%, 85%, and 90% saturated steam.

4. The method of claim 1 wherein the liquid blowdown stream is generated at a high flowrate with high TDS boiler feedwater including a flowrate greater than approximately 15%, 16%, 17%, 18%, 19%, 20%, 21% 22%, 23%, 24% and 25% of the feed rate.

5. The method of claim 1 wherein the liquid blowdown stream exchanges heat with the superheated steam to vaporize a portion of the blowdown stream to form the finished steam occurs in a closed heat exchanger, occurs by mixing the superheated steam with the liquid blowdown stream, or a mixing vessel.

6. The method of claim 1 wherein the superheater is a separately fired heater from the boiler.

7. A method for generating steam using high total dissolved solids (TDS) boiler feedwater comprising the steps of:

introducing the high TDS boiler feedwater to a produced water evaporator wherein evaporator has a mechanical vapor compressor;

generating a low quality steam in the evaporator;

transferring the vapor fraction to the mechanical vapor compressor to produce a evaporator distillate;

transferring evaporator distillate to a boiler;

separating a boiler blowdown and a saturated steam;

returning the drum boiler blowdown to the produced water evaporator;

superheating the saturated steam to produce a superheated steam,

allowing the evaporator blowdown stream to exchange heat with the superheated steam to vaporize a portion of the blowdown stream to form a finished steam and a waste stream.

8. The method of claim 7 wherein the high TDS boiler feedwater comprises from about 3,000 to about 8,000 ppm total dissolved solids including approximately 3,500 ppm TDS, 4,000 ppm TDS, 4,500 ppm TDS, 5,000 ppm TDS, 5,500 ppm TDS, 6,000 ppm TDS, 6,500 ppm TDS, 7,000 ppm TDS, 7,500 ppm TDS and 8,000 ppm TDS.

9. The method of claim 7 wherein the low quality steam has a quality from about 60% to about 90% saturated steam including approximately 60%, 65%, 70%, 75%, 80%, 85%, and 90% saturated steam.

10. The method of claim 7 wherein the liquid blowdown stream is generated at a high flowrate with high TDS boiler feedwater including a flowrate greater than approximately 15%, 16%, 17%, 18%, 19%, 20%, 21% 22%, 23%, 24% and 25% of the feed rate.

11. The method of claim 7 wherein the liquid blowdown stream exchanges heat with the superheated steam to vaporize a portion of the blowdown stream to form the finished steam occurs in a closed heat exchanger, occurs by mixing the superheated steam with the liquid blowdown stream, or a mixing vessel.

12. The method of claim 7 wherein the superheater is a separately fired heater from the boiler.

13. A method for producing hydrocarbons from a subterranean formation comprising:

generating steam using high total dissolved solids (TDS) boiler feedwater wherein the steam is generated by:

allowing the liquid blowdown stream to exchange heat with the superheated steam to vaporize a portion of the blowdown stream to form a finished steam and a waste stream;

transferring the finished steam to a hydrocarbon formation, and

producing hydrocarbons from said formation.

14. The method of claim 13 wherein the high TDS boiler feedwater comprises from about 3,000 to about 8,000 ppm total dissolved solids including approximately 3,500 ppm TDS, 4,000 ppm TDS, 4,500 ppm TDS, 5,000 ppm TDS, 5,500 ppm TDS, 6,000 ppm TDS, 6,500 ppm TDS, 7,000 ppm TDS, 7,500 ppm TDS and 8,000 ppm TDS.

15. The method of claim 13 wherein the low quality steam has a quality from about 60% to about 90% saturated steam including approximately 60%, 65%, 70%, 75%, 80%, 85%, and 90% saturated steam.

16. The method of claim 13 wherein the liquid blowdown stream is generated at a high flowrate with high TDS boiler feedwater including a flowrate greater than approximately 15%, 16%, 17%, 18%, 19%, 20%, 21% 22%, 23%, 24% and 25% of the feed rate.

17. The method of claim 13 wherein the liquid blowdown stream exchanges heat with the superheated steam to vaporize a portion of the blowdown stream to form the finished steam occurs in a closed heat exchanger, occurs by mixing the superheated steam with the liquid blowdown stream, or a mixing vessel.

18. The method of claim 13 wherein the superheater is a separately fired heater from the boiler.

19. A method for producing hydrocarbons from a subterranean formation comprising:

generating a low quality steam in the evaporator;

transferring evaporator distillate to a boiler;

separating a boiler blowdown and a saturated steam;

returning the drum boiler blowdown to the produced water evaporator;

superheating the saturated steam to produce a superheated steam,

allowing the evaporator blowdown stream to exchange heat with the superheated steam to vaporize a portion of the blowdown stream to form a finished steam and a waste stream;

transferring the finished steam to a hydrocarbon formation, and

producing hydrocarbons from said formation.

20. The method of claim 19 wherein the high TDS boiler feedwater comprises from about 3,000 to about 8,000 ppm total dissolved solids including approximately 3,500 ppm TDS, 4,000 ppm TDS, 4,500 ppm TDS, 5,000 ppm TDS, 5,500 ppm TDS, 6,000 ppm TDS, 6,500 ppm TDS, 7,000 ppm TDS, 7,500 ppm TDS and 8,000 ppm TDS.

21. The method of claim 19 wherein the low quality steam has a quality from about 60% to about 90% saturated steam including approximately 60%, 65%, 70%, 75%, 80%, 85%, and 90% saturated steam.

22. The method of claim 19 wherein the liquid blowdown stream is generated at a high flowrate with high TDS boiler feedwater including a flowrate greater than approximately 15%, 16%, 17%, 18%, 19%, 20%, 21% 22%, 23%, 24% and 25% of the feed rate.

23. The method of claim 19 wherein the liquid blowdown stream exchanges heat with the superheated steam to vaporize a portion of the blowdown stream to form the finished steam occurs in a closed heat exchanger, occurs by mixing the superheated steam with the liquid blowdown stream, or a mixing vessel.

24. The method of claim 19 wherein the superheater is a separately fired heater from the boiler.