US20150308231A1

US20150308231A1 - Liquid based boiler

Info

Publication number: US20150308231A1
Application number: US14/682,191
Authority: US
Inventors: David W. Larkin
Original assignee: ConocoPhillips Co
Current assignee: ConocoPhillips Co
Priority date: 2014-04-24
Filing date: 2015-04-09
Publication date: 2015-10-29
Also published as: CA2887935A1

Abstract

Methods and systems generate steam for oil recovery operations. The systems may limit feedwater pretreatment expenses and fouling issues. In the method, dirty feedwater introduced into a vessel containing a hot liquid hydrocarbon, e.g., an already hot produced hydrocarbon, contacts the hydrocarbon and is vaporized into steam. The steam collects in a top of the vessel and may be conveyed to the wellhead for downhole injection. The hydrocarbon remains heated by a closed circulation loop passing back and forth through a lower half of the vessel containing the hydrocarbon. The fluid in this loop remains isolated from contaminates in the water to limit fouling in tubes, which form the loop and can employ normal metallurgy to save on capital costs. The hydrocarbon can be treated as needed to remove accumulating salts and/or entrained water and recycled.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims benefit of U.S. Patent Application Ser. No. 61/983,742 filed Apr. 24, 2014 entitled “LIQUID BASED BOILER,” which is hereby incorporated by reference.

FIELD OF THE INVENTION

The invention relates to method and system for generating steam with minimal or eliminated fouling resulting largely from the use of contaminated feedwaters. The invention limits fouling problem by spraying dirty feedwater directly onto a hot hydrocarbon for steam generation.

BACKGROUND

Steam Assisted Gravity Drainage (SAGD) is an enhanced oil recovery technology for producing heavy crude oil and bitumen. It is an advanced form of steam stimulation wherein a pair of horizontal wells are drilled into the oil reservoir, one a few meters above the other. High pressure steam is continuously injected into the upper wellbore to heat the oil and reduce its viscosity, causing the heated oil and any condensed steam (hot water) to gravity drain into the lower wellbore, where it can be pumped to the surface. The produced oil is a mixture of heated oil plus water. Because water is as precious a resource as oil, the “produced water” is then cleaned and returned to the boiler, where it is converted into steam and injected back into the ground.
Due to the recycling of water in SAGD operations, and the fact that the water encounters petroleum deposits as well as any additives used in production, the feedwater used to make steam is typically far from pure. Produced water and brackish well water are the main boiler feedwater sources for SAGD and other steam based oil recovery process. The water at time of being generated into the steam may still contain: at least about 500 parts per million (ppm), at least 1000 ppm, at least 10,000 ppm or at least 45,000 ppm total dissolved solids; at least 100 ppm, at least 500 ppm, at least 1000 ppm or at least 15,000 ppm organic compounds or organics; and at least 1000 ppm free oil.
“Fouling” is the contamination of heating surfaces by these mineral scales, and the build-up of scale eventually decreases the heat-flux and thus the heating efficiency. Therefore, the boiler has to be shut down several times a year to remove the fouling layer and/or repair the tubing. In addition to the repair cost, the down-time further increases the cost of the SAGD operation. To minimize fouling, boiler feed-water (BFW) quality is critical because dissolved solids are the major cause of boiler failure and efficiency losses. Therefore, the total dissolved solids (TDS) for BFW needs to be controlled under a certain level to prevent or alleviate the scaling issue, and this is usually done by pre-treating feedwater prior to use to reduce TDS.
The two most common types of steam generators used for oil sands recovery are once through steam generators (OTSG) and drum boilers, which are also called water tube boilers. Coal-fired steam generators, downhole steam generators, fluidized bed combustion boilers and vapor therm steam generators have previously been reported to be used in Alberta fields, but they are no longer found in recent field applications.
The OTSG is a large continuous tube type steam generator wherein steam is produced at the outlet of the continuous tube, as shown in in FIG. 1. Feedwater supplied at one cold end of the tube undergoes the preheating-evaporation cycle as it travels along the continuous tube. As steam is produced in a traditional OTSG, the steam quality is usually around 75-80%, i.e. not all the feedwater vaporizes.
In drum type steam generators, in contrast, preheated water evaporates as it circulates in heated tubes between the steam drum and the feedwater drum, as shown in FIG. 2. Saturated steam and water rises into the steam drum due to the lowered density compared with the water in downcomer tube. Saturated steam is drawn off the top of the drum and sent to the superheater section.
OTSG systems require frequent cleaning, which leads to the increased down-time and costly repair. Fouling also reduces the thermal efficiency 1% to 15% depending on the amount of deposits, as they act as an insulating layer on the heating tubes. The shutdown to clean the scale increases operating costs, and the pre-treatments needed to de-oil and clean the feedwater before use also contributes significantly to cost.
Therefore, there is a need for an improved steam production scheme that can minimize fouling issues and reduce the downtime and reduce both operating and initial capital costs for SAGD and other steam based oil recovery operations.

SUMMARY OF THE DISCLOSURE

Embodiments of the invention use a hot liquid, such as the produced heated hydrocarbons, or fractions thereof, to directly vaporize non-treated boiler feedwater. This hot hydrocarbon receives its thermal energy from another hot fluid, such as molten sodium, molten sodium-potassium, or another hydrocarbon that may include butane, DOWTHERM™ or THERMINOL™ heat transfer fluid, within coils in a closed circulation loop traveling from a standard heater to the vessel containing the hot hydrocarbon. Contaminants from the water being vaporized may thus buildup in the hot liquid requiring treatment of the hot liquid. The fluid in the coils transfers heat to the hot liquid without relying on transfer of the hot liquid to the heater. Thus, the fluid in the coils circulates to maintain a desired heat balance providing a benefit by enabling decoupled circulation of the hot liquid for treatment, such as desalting, at a rate wanted for removal of the contaminants independent of a flow needed for the heating.
The use of a hot hydrocarbon such as DOWTHERM™ enables more conventional metallurgies to be used for the coils, thus minimizing CAPEX costs. Further, the contaminants remain in the hot liquid outside the coils without passing to the heater to avoid problems inside the circulation loop.
The hydrocarbon heat steam generation system is a replacement to the current OTSGs de-oiling and water treatment facilities, which are otherwise essential to prevent rapid fouling and tube corrosion that occurs in either drum boilers or OTSG systems. Use of the oil and desalting of the oil mitigates contaminant concentration buildup in the oil and fouling within the steam generation system.
The hot hydrocarbon may give up some lighter molecular weight elements to the steam, thus providing a small amount of solvent, and essentially converting the SAGD process to an ES-SAGD process, which may reduce steam usage since the solvent has the effect of diluting and thinning the heavy oil or bitumen. Typically, C1-C5 hydrocarbons, and even C6-C8 hydrocarbons, may vaporize and be carried along with the steam, albeit in low amounts.
The invention produces high pressure steam or steam-plus-solvent which can be used in a SAGD reservoir or in other steam stimulation processes, such as cyclic steam generation (CSS) or steam drive (SD) also called steam flooding, and combinations and variations thereof.
Of course, the hot hydrocarbon picks up the dissolved solids and any entrained oil in the dirty feedwater, but the oils are not a problem, and the dissolved solids (which may no longer be dissolved) can be removed in a cleaning loop using known technology. Treatment units can include one or more of a variety of treatment units, including e.g., a filter, coalescer, desalter, dehydrator, visbreaker or electrostatic separator.
Salts in crude oil feedstocks can cause severe problems downstream, including corrosion by acids formed by chloride salt decomposition in fractionator overhead equipment, fouling of heat exchangers by salt deposition, and poisoning of catalysts in down-stream units. Therefore, crude is typically desalted before being charged to the distillation train. Crude can also contain suspended solids, such as sand, clay, and iron oxide particles.
The two most typical methods of crude-oil desalting, chemical and electrostatic separation, use hot water as the extraction agent. In chemical desalting, water and chemical surfactant (demulsifiers) are added to the crude, heated so that salts and other impurities dissolve into the water or attach to the water, and then held in a tank where they settle out. Electrical desalting is the application of high-voltage electrostatic charges to concentrate suspended water globules in the bottom of the settling tank. Surfactants are added only when the crude has a large amount of suspended solids. Both methods of desalting are continuous. A third and less-common process involves filtering heated crude using diatomaceous earth.
For example, an electrostatic dehydration system is an efficient method to remove high salinity formation water from the crude oil stream. This process relies on establishing a high voltage AC electrical field in the oil phase of dehydrator/desalter vessels. The electrical field imposes an electrical charge on water droplets entrained in the oil stream, thus causing them to oscillate as they pass through the electrodes. During this oscillation the droplets are stretched or elongated and then contracted during reversal of the imposing AC electrical field. During this agitation, the water droplets co-mingle and coalesce into droplets of sufficient size to migrate, by gravity, back into the lower water phase of the vessel for disposal.
Alternatively, Ultrafiltration (UF) can be used primarily to remove the emulsified oil droplets, followed by the removal of total dissolved solids (TDS) via reverse osmosis (RO).
The liquid boiler system described herein improves SAGD economics by:

- Eliminating the need for de-oiling, water pre-treatment plants and conventional steam boiler plants.
- Enhancing the heavy oil recovery by including lower molecular weight hydrocarbons combined with the produced steam. These hydrocarbons aid in reducing the heavy oil viscosity in the reservoir along with the steam, thus, enhancing oil production.
- Overall SAGD steam demand may also decrease due to the presence of hydrocarbon within the steam, in much the same manner that ES-SAGD reduces steam requirements.

The invention includes one or more of the following embodiments, in any combination thereof:
A steam generator system for heavy oil production, comprising: a vessel comprising a hot hydrocarbon; a pump for pressurizing a dirty feedwater stream fluidly connected to nozzles in said vessel, said nozzles spraying said dirty feedwater onto said hot hydrocarbon; and an exit port near a top of said vessel for collecting pressurized steam and transporting said pressurized steam to a wellhead injection system for injecting steam into an oil reservoir; wherein these elements are fluidly connected.
A closed heat transfer fluid circulation loop that passes in part through said vessel can be used to heat said hot hydrocarbon. The closed heat transfer fluid circulation loop can comprise a heat transfer fluid, a heater, and a pump, circulating through closed coils which pass, in part, through the liquid boiler vessel.
The liquid boiler vessel can also comprise a hot hydrocarbon treatment loop in fluid connection with said vessel, wherein said hot hydrocarbon treatment loop either clean or upgrades the hot hydrocarbons. Exemplary treatments include filtering, desalting, dehydrating, coalescing, visbreaking, electrostatic separating, and the like.
A liquid steam generator, comprising a vessel comprising a hot hydrocarbon in a lower portion of said vessel; a closed heat transfer fluid circulation loop containing a heat transfer fluid, said loop passing in part through said lower half of said vessel to heat said hot hydrocarbon, the remainder passing to a heater and a pump to heat and circulate said heat transfer fluid; a hot hydrocarbon treatment loop for cleaning said hot hydrocarbon, said hot hydrocarbon treatment loop including a pump and a desalter; a pump for pressurizing a dirty feedwater stream fluidly connected to nozzles in an upper portion of said vessel, said nozzles spraying said dirty feedwater onto said hot hydrocarbon; and an exit port near a top of said vessel for collecting pressurized steam and transporting said pressurized steam to a wellhead injection system for injecting steam into an oil reservoir; wherein the elements (except for the closed circulation loop) are fluidly connected.
Exemplary hydrocarbon heat transfer fluids are selected from butane, molten sodium, molten sodium-potassium, DOWTHERM or THERMINOL.
The dirty feedwater can be any water that is not pretreated before use, including produced water, brackish water, well water, brine, surface water and combinations thereof. The dirty feedwater may be produced water originating from any convenient source.
The hot hydrocarbon fluid can be any conveniently available hot hydrocarbon, especially being a produced hydrocarbon separated from said produced water, or a fraction thereof.
The liquid boiler can produce a pressurized steam that is a mixture of steam and low molecular weight hydrocarbons, such as butane, pentane, and the like.
One embodiment is an improved method of steam assisted gravity drainage (SAGD), the method comprising pretreating produced water for a steam generator to remove oil and salts, making pressurized steam from said pretreated water, pumping said pressurized steam into a wellbore in an amount sufficient to mobilize heavy oil, and gravity draining said mobilized heavy oil to a production well, the improvement comprising spray injecting pressurized dirty water into a vessel containing a hot heavy oil and collecting pressurized steam for use in SAGD, without said water pretreating step.
Another improved method of steam production for the mobilization of heavy oil, the method comprising pretreating produced water for a steam generator to remove oil and salts, making pressurized steam from said pretreated water, pumping said pressurized steam into a wellbore in an amount sufficient to mobilize heavy oil, and producing said mobilized heavy oil, the improvement comprising spray injecting pressurized dirty water into a vessel containing a hot hydrocarbon and collecting pressurized steam for use in mobilizing heavy oil, without said water pretreating step, wherein said hot hydrocarbon is heated with a closed circulation loop comprising a pump and a furnace to circulate a heat transfer fluid through said closed circulation loop.
By “dirty water” what is meant is that the water can be recycled from oil recovery processes and used as is, without expensive de-oiling or desalting pre-treatments applied to it.
The use of the word “a” or “an” when used in conjunction with the term “comprising” in the claims or the specification means one or more than one, unless the context dictates otherwise.
The term “about” means the stated value plus or minus the margin of error of measurement or plus or minus 10% if no method of measurement is indicated.
The use of the term “or” in the claims is used to mean “and/or” unless explicitly indicated to refer to alternatives only or if the alternatives are mutually exclusive.
The terms “comprise”, “have”, “include” and “contain” (and their variants) are open-ended linking verbs and allow the addition of other elements when used in a claim.
The phrase “consisting of” is closed, and excludes all additional elements.
The phrase “consisting essentially of” excludes additional material elements, but allows the inclusions of non-material elements that do not substantially change the nature of the invention.
The following abbreviations are used herein:


	ABBREVIATION	TERM

	ATM	Atmosphere
	BFW	Boiler feed-water
	CAPEX	Capitol expenses
	CPF	Central processing facility
	CSS	Cyclic steam stimulation
	ES-SAGD	Expanding solvent SAGD
	OPEX	Operating expenses
	OTSG	Once-through steam generator
	RO	Reverse osmosis
	SAGD	Steam-assisted gravity drainage
	SD	Steam drive
	TDS	total dissolved solids
	Ts	Saturation temperature
	UF	Ultrafiltration

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a highly simplified view of a modern OTSG system and used for SAGD steam production.

FIG. 2 presents a simplified drum boiler system.

FIG. 3 illustrates a simplified schematic of the liquid boiler system of the invention, which can be beneficially used with SAGD and other steam-based enhanced oil recovery methods

FIG. 4 is a schematic of an alternative arrangement to contact a mixture of water and oil with more of the oil that has been heated to thus vaporize the water and potentially result in visbreaking of the oil, according to one embodiment of the invention.

DETAILED DESCRIPTION

The disclosure provides a novel method for generating steam with minimized or eliminated fouling. The disclosure also provides a novel system for implementing the method.
In general, an improved method of generating steam for SAGD and other heavy oil production uses is provided, wherein a hot liquid hydrocarbon is used to convert water to steam, and wherein the steam may thus contain lower molecular weight components stripped from the hot liquid hydrocarbon.
FIG. 3 gives one example of a liquid boiler process for SAGD. As seen in the figure, dirty feedwater 101 that is not de-oiled or pre-treated to remove dissolved solids enters the system. Pump 103 brings the dirty water to high pressure and then it is injected via spray nozzles 105 into the liquid boiler vessel 109. Since the water is pressurized there is little fouling of the components up to this point.
Hot liquid 113 (e.g., produced heavy hydrocarbons, etc.) vaporizes the dirty boiler feed water sprayed into the vessel. The resulting produced steam (with potentially some hydrocarbons in it) exits 111 out the top of the liquid-boiler and is sent by line 113 to the SAGD reservoir. Any dissolved solids or oil from the dirty feedwater remains with the hot liquid hydrocarbons.
The hot liquid receives its thermal energy from another heat transfer fluid in a closed circulation loop 157 via heat transfer within coils 155. The heat transfer fluid (such as butane, molten sodium, molten sodium-potassium, DOWTHERM or THERMINOL) within the coils receives its heat via an external furnace 151, and in that sense the boiler is an indirect boiler, heat coming from an outside source. In some embodiments, the heat transfer fluid, such as butane, may be condensed for pumping prior to being vaporized in the furnace 151 and circulated through the coils 155 in the vessel 109. To the extent that produced hydrocarbons are used in the process, they already have a certain heat, decreasing initial heating costs. The hot hydrocarbons used to vaporize the produced water may be treated by an external hydrocarbon treatment unit 173, such as a desalter, to remove the accumulating contaminants from the dirty feedwater.
The method allows the boiler to produce steam with non-treated (dirty) boiler feed water. This, therefore, reduces the CAPEX and OPEX costs associated with de-oiling and water treatment plants. Using a liquid such as DOWTHERM or THERMINOL as the heat transfer liquid allows for conventional coil metallurgy, thus, minimizing the CAPEX for the indirect boiler, as well as minimizing any fouling of these coils.
FIG. 4 illustrates a hot hydrocarbon-based system with a steam generator vessel 200, an injection well 201 and a production well 202 that are operated for steam generation. A feed pump 216 pressurizes the dirty feedwater mixture 204 that can optionally be preheated in a furnace or heat exchanger 217 prior to introduction into the vessel 200. In some embodiments, the mixture 204 may receive pre-heat from a sales portion 210 of the hydrocarbons.
Upon entry into the vessel 200, some flashing of the water in the mixture 204 may occur upon expansion into relative lower pressure conditions of the vessel 200. However, most of the water in the mixture 204 vaporizes upon contact with hot hydrocarbon 220 collected in the lower half of the vessel 200. The hydrocarbons 220 may be partially heated, if for example, produced hydrocarbons are used, and/or can be further heated in closed circulation loop 257 consisting of furnace 251, pump 253 and heating coils 255 that pass through the hot hydrocarbon 220.
A second circulation loop 222 contains a recycle pump 221 that passes the hot hydrocarbon 220 from the vessel 200 to a treatment unit 223 before returning the hot hydrocarbon 220 to the vessel 200. Treatment unit 223 can include one or more of a variety of treatment units, including e.g., a filter, coalescer, desalter, dehydrator, visbreaker or electrostatic separator. The desalter or other treatment unit 223 removes inorganic material from the hot hydrocarbon 220. Some of the hot hydrocarbon 220 exiting the desalter 223 can provide the sales portion 210 of the hydrocarbons for pipeline or transport to a refinery for further processing.
For some embodiments, overhead from the vessel 200 passes through a separation device 229 that may include demisters, separators, fractionators and/or particulate filters. The device 229 removes entrained liquids and/or solids 233 and/or condensable hydrocarbons 231 vaporized by the hot hydrocarbon 220 or resulting from cracking of the hot hydrocarbon 220. The condensable hydrocarbons 231 may mix back into the sales portion 210 of the hydrocarbons or have a portion mixed back for injection into the formation as a solvent. However, it is anticipated that the overhead steam can be used as is, and that any light hydrocarbons that may have evaporated along with the steam (e.g., naptha), will reduce the steam oil ratio (SOR) needed to produce a barrel of oil.
Steam 230 exits the device 229 and is conveyed to the injection well 201. Since separation of the mixture 204 occurs with the vessel 200, this approach eliminates need for independent de-oiling equipment.
Residence time of the hot hydrocarbon 220 in the vessel 200 may even provide sufficient soak time for visbreaking of the hydrocarbon 220. A visbreaker thermally cracks large hydrocarbon molecules in the oil by heating in a furnace to reduce its viscosity and to produce small quantities of light hydrocarbons (LPG and gasoline). The process name of “visbreaker” refers to the fact that the process reduces (i.e., breaks) the viscosity of the residual oil, and generally the process is non-catalytic.
Alternatively, a visbreaker can be provided in the second circulation loop 222. Exemplary soaking times may range from 5 minutes to 1 hour with the bitumen heated in the visbreaker to at least 385° C. The circulation loop 222 may incorporate various approaches to enhance the visbreaking, such as radiation thermal cracking or hydrodynamic cavitation. The visbreaking lowers viscosity and density of the heavy oils or bitumen 220 and hence the sales portion 210 making the sales portion 210 more valuable and easier to transport while requiring less diluents than the bitumen without such upgrading.
In some embodiments, the water supplied for generation of the steam may include boiler blowdown from another steam generator, such as a once-through steam generator. The methods disclosed herein may provide for treatment of such blowdown. Further, the steam generated by such treatment may be at pressures lower than desired for injection and may be recycled for mixing with boiler feed water prior to generation of steam for injection.
Based on the above illustrations, it is clearly shown that the methods and systems herein described pressurize the feedwater before it enters the heating mechanism and thereby avoids the nucleate boiling phase that directly contributes to fouling. Downtime for pigging/repairing the boiler and pipes can be greatly reduced, therefore cutting down the operation cost.
The following documents are incorporated by reference in their entirety:
Gwak et al., A Review of Steam Generation for In-Situ Oil Sands Projects, Geosystem Engineering, 13(3), 111-118 (September 2010).

Claims

What is claimed is:

1. A steam generator system for heavy oil production, comprising:

a vessel comprising a hydrocarbon;

a closed heat transfer fluid circulation loop that passes in part through the vessel to heat the hydrocarbon;

a pump for pressurizing a feedwater stream and fluidly connected to nozzles in the vessel, wherein the nozzles spray the feedwater onto the hydrocarbon to produce steam; and

a wellhead injection system for conveying the steam into an oil reservoir and coupled to an exit port near a top of the vessel for collecting the steam.

2. The steam generator system of claim 1, wherein the closed heat transfer fluid circulation loop includes a heat transfer fluid, a heater and a pump.

3. The steam generator system of claim 1, wherein the closed heat transfer fluid circulation loop includes a heat transfer fluid selected from butane, molten sodium, molten sodium-potassium, DOWTHERM and THERMINOL.

4. The steam generator system of claim 1, further comprising a hydrocarbon treatment loop in fluid connection with the vessel, wherein the hydrocarbon treatment loop desalts the hydrocarbon.

5. The steam generator system of claim 2, further comprising a hydrocarbon treatment loop in fluid connection with the vessel, wherein the hydrocarbon treatment loop desalts the hydrocarbon.

6. The steam generator system of claim 3, further comprising a hydrocarbon treatment loop in fluid connection with the vessel, wherein the hydrocarbon treatment loop desalts the hydrocarbon.

7. A liquid steam generator, comprising:

a vessel comprising a hydrocarbon in a lower portion of the vessel;

a closed heat transfer fluid circulation loop containing a heat transfer fluid, wherein the loop passes in part through the lower half of the vessel to heat the hydrocarbon and a remainder of the loop passes to a heater and a pump to heat and circulate the heat transfer fluid;

a hydrocarbon treatment loop for cleaning the hydrocarbon, wherein the hydrocarbon treatment loop includes a pump and a desalter;

a pump for pressurizing a feedwater stream fluidly connected to nozzles in an upper portion of the vessel, wherein the nozzles spray the feedwater onto the hydrocarbon to produce steam; and

8. The steam generator system of claim 7, wherein the hydrocarbon heat transfer fluid is selected from butane, molten sodium, molten sodium-potassium, DOWTHERM and THERMINOL.

9. The liquid steam generator of claim 7, wherein the feedwater is untreated produced water.

10. The liquid steam generator of claim 9, wherein the hydrocarbon fluid is a produced hydrocarbon separated from the produced water.

11. The liquid steam generator of claim 7, wherein a mixture of the steam and at least some of the hydrocarbons with less than eight carbon atoms per molecule output the vessel through the exit port.

12. The liquid steam generator of claim 7, wherein the treatment loop includes a visbreaker.

13. A method of generating steam, comprising:

circulating a heat transfer fluid through a closed loop for transfer of thermal energy from a heater along the loop to hydrocarbons in a vessel as a portion of the loop passes through the vessel; and

introducing feedwater into contact with the hydrocarbons in the vessel to vaporize the feedwater into steam.

14. The method of claim 13, wherein the feedwater is untreated produced water.

15. The method of claim 13, wherein the feedwater is blowdown from one of a steam generator and an evaporator.

16. The method of claim 13, wherein the heat transfer fluid is selected from butane, molten sodium, molten sodium-potassium, DOWTHERM and THERMINOL.

17. The method of claim 13, further comprising injecting the steam into an oil reservoir.

18. The method of claim 13, further comprising desalting the hydrocarbon in the vessel.

19. The method of claim 13, wherein an output from the vessel includes a mixture of the steam and at least some of the hydrocarbons with less than eight carbon atoms per molecule.

20. The method of claim 13, further comprising circulating the hydrocarbons into contact with the steam output from the vessel.