Process for removing scale in a steam generator for use in hydrocarbon recovery

Abstract

A process for removing scale in a steam generator for use in a hydrocarbon recovery process, includes introducing feed water into the steam generator and introducing particles and pressurized gas into the steam generator, at a pressure sufficient to cause turbulent flow of fluid including the feed water, the gas, and the particles, for removing scale from interior walls of tubes of the steam generator, wherein the particles have a sufficient hardness to remove the scale without damaging the tubes beyond a threshold associated with safe operation of the steam generator.

Description

4 4 4 4 4 and the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the cont PROCESS FOR REMOVING SCALE IN A STEAM GENERATOR FOR USE IN HYDROCARBON RECOVERY Technical Field

[0001] The present invention relates to steam generators utilized to produce steam for injection into an underground reservoir to mobilize hydrocarbons such as heavy oils and bitumen. Background

[0002] Extensive deposits of viscous hydrocarbons exist around the world, including large deposits in the northern Alberta oil sands that are not susceptible to standard oil well production technologies. The hydrocarbons in reservoirs of such deposits are too viscous to flow at commercially relevant rates at the temperatures and pressures present in the reservoir. For such reservoirs, thermal techniques may be utilized to heat the reservoir to mobilize the hydrocarbons and produce the heated, mobilized hydrocarbons from wells. One such technique for utilizing a horizontal well for injecting heated fluids and producing hydrocarbons is described in U.S. Patent No. 4,116,275, which also describes some of the problems associated with the production of mobilized viscous hydrocarbons from horizontal wells.

[0003] One thermal method of recovering viscous hydrocarbons using spaced horizontal wells is known as steam-assisted gravity drainage (SAGD). In the SAGD process, pressurized steam is delivered through an upper, horizontal, injection well (injector), into a viscous hydrocarbon reservoir while hydrocarbons are produced from a lower, parallel, horizontal, production well (producer) that is near the injection well and is vertically spaced from the injection well. The injection and production wells are typically situated in the lower portion of the reservoir, with the producer located close to the base of the hydrocarbon deposit to collect the hydrocarbons that flow toward the base of the deposit.

[0004] The SAGD process is believed to work as follows. The injected steam initially mobilizes the hydrocarbons to create a steam chamber in the reservoir around and above the horizontal injection well. The term steam chamber is utilized the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control to refer to the volume of the reservoir that is saturated with injected steam and from which mobilized oil has at least partially drained. As the steam chamber expands, viscous hydrocarbons in the reservoir and water originally present in the reservoir are heated and mobilized and move with aqueous condensate, under the effect of gravity, toward the bottom of the steam chamber. The hydrocarbons, the water originally present, and the aqueous condensate are typically referred to collectively as emulsion. The emulsion accumulates such that the liquid / vapor interface is located below the steam injector and above the producer. The emulsion is collected and produced from the production well. The produced emulsion is separated into dry oil for sales and produced water, comprising the water originally present and the aqueous condensate.

[0005] Steam that is injected into the reservoir through the injection well may be recycled by reheating the produced water that is produced from the wells in a steam generator, such as a once through steam generator (OTSG), and again injecting the steam into the reservoir. Accumulation of contaminants and the formation of scale on tubes within the steam generator is a problem, even after treatment of the produced water in a series of processes including, but not limited to skimming, flotation, oil filtering, warm lime softening, lime softener filtration, and primary strong acid and secondary weak acid ion exchange processes prior to feeding to the steam generator. Such processes may be beneficial to remove oil, silica, calcium, magnesium, and iron prior to passing treated produced water through the steam generator, but scale buildup on the inside of the tubes of the steam generator remains an issue. Scaling of the tubes of the steam generator reduces heat transfer and decreases the efficiency of the steam generator, and increases the cost of operating the steam generator.

[0006] Methods utilized for cleaning a steam generator, such as operating a pig (a device passed through the tubing for cleaning and / or inspection) within the steam generator, are time consuming, costly, and take the steam generator offline for many days per year.

[0007] Improvements in scale removal from the tubes in such steam generators are desirable. Summary

[0008] According to an aspect of an embodiment, there is provided a process for removing scale in a steam generator for use in a hydrocarbon recovery process. The process for removing scale includes introducing feed water into the steam generator and introducing particles and pressurized gas into the steam generator, at a pressure sufficient to cause turbulent flow of fluid including the feed water, the gas, and the particles, for removing scale from interior walls of tubes of the steam generator, wherein the particles have a sufficient hardness to remove the scale without damaging the tubes beyond a threshold associated with safe operation of the steam generator.

[0009] The particles may have a hardness greater than the hardness of the scale, the tubes, or both the scale and the tubes. The particles maybe thermally stable up to a temperature of at least 100°C and, optionally, up to at least 180°C.

[0010] The particles and the feed water may be introduced into the steam generator at a temperature of about 180°C.

[0011] The particles and the scale may be separated from the fluid. Optionally, steam may be produced in the steam generator and the steam separated prior to or after separating the particles and the scale from the fluid. The particles and the scale may be disposed of in a disposal receptacle in fluid communication with the steam generator.

[0012] The particles and pressurized gas may be introduced into the vessel and introduced into the steam generator from the vessel. The particles and pressurized gas may be introduced into the feed water prior to introducing the feed water and introducing the particles and pressurized gas into the steam generator. The particles may be introduced into a carrier solution, such as distilled water or methanol, in the vessel.

[0013] The particles may be glass, metal, ceramic, or a combination thereof. For example, the particles may be cut wire. The pressurized gas may be nitrogen or propane. Alternatively, the pressurized gas may comprise oxygen. the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control

[0014] A differential pressure may be monitored across at least a part of the steam generator during steam production and prior to introducing the particles and the pressurized gas, and the particles and the pressurized gas may be introduced in response to detecting a change in the differential pressure that exceeds a threshold.

[0015] Blocking of steam sampling lines from the steam generator by scale removed from the tubes of the steam generator may be inhibited by one of shutting in the steam sampling lines, creating a backflow of fluid in the steam sampling lines, and purging the steam sampling lines utilizing a blow-off connection to a blowdown tank.

[0016] According to another aspect, a system for producing steam for use in a hydrocarbon recovery process to recover hydrocarbons from a hydrocarbon reservoir is provided. The system includes a steam generator that has an economizer section for preheating feed water, a radiant section in fluid communication with the economizer section for generating steam from the feed water, and at least one inlet for receiving pressurized gas and particles into the economizer section to create turbulent flow of fluid including the feed water, the gas, and the particles, for removing scale from interior walls of tubes of the steam generator. The particles have a sufficient hardness to remove the scale without damaging the tubes beyond a threshold associated with safe operation of the steam generator. The system also includes a separator in fluid communication with the steam generator for separating the steam generated from the feed water for use in hydrocarbon recovery. Brief Description of the Drawings

[0017] Embodiments of the present invention will be described, by way of example, with reference to the drawings and to the following description, in which:

[0018] FIG. 1 is a sectional view through a reservoir, illustrating a SAGD well pair;

[0019] FIG. 2 is a sectional side view illustrating a SAGD well pair including an injection well and a production well; . . . . . . . . . . . . . . . . . . . . and the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the seco and the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the seco

[0020] FIG. 3 is a simplified schematic view illustrating a system and process for removing scale in a steam generator utilized in a hydrocarbon recovery process in accordance with an example;

[0021] FIG. 4 is a simplified schematic view illustrating a system and process for removing scale in a steam generator utilized in a hydrocarbon recovery process in accordance with another example;

[0022] FIG. 5 is a simplified schematic view illustrating a system and process for removing scale in a steam generator utilized in a hydrocarbon recovery process in accordance with yet another example;

[0023] FIG. 6 is a simplified schematic view illustrating a system and process for removing scale in a steam generator utilized in a hydrocarbon recovery process in accordance with yet a further example. Detailed Description

[0024] For simplicity and clarity of illustration, reference numerals may be repeated among the figures to indicate corresponding or analogous elements. Numerous details are set forth to provide an understanding of the examples described herein. The examples may be practiced without these details. In other instances, well-known methods, procedures, and components are not described in detail to avoid obscuring the examples described. The description is not to be considered as limited to the scope of the examples described herein.

[0025] The disclosure generally relates to a system and process for removing scale in a steam generator utilized in a hydrocarbon recovery process. The process for removing scale includes introducing feed water into the steam generator and introducing particles and pressurized gas into the steam generator, at a pressure sufficient to cause turbulent flow of fluid including the feed water, the gas, and the particles, for removing scale from interior walls of tubes of the steam generator, wherein the particles are thermally stable up to a temperature of at least 100°C.

[0026] Reference is made herein to an injection well and a production well. The injection well and the production well may be physically separate wells. Alternatively, the production well and the injection well may be housed, at least and the second section of the second section is a second section of the second section of the second section of partially, in a single physical wellbore, for example, a multilateral well. The production well and the injection well may be functionally independent components that are hydraulically isolated from each other, and housed within a single physical wellbore.

[0027] As described above, a steam-assisted gravity drainage (SAGD) process may be utilized for mobilizing viscous hydrocarbons. In the SAGD process, a well- pair, including a hydrocarbon production well and a steam injection well are utilized. One example of a well pair is illustrated in FIG. 1 and an example of a hydrocarbon production well 100 and injection well 108 is illustrated in FIG. 2. The hydrocarbon production well 100 includes a generally horizontal segment 102 that extends near the base or bottom 104 of the hydrocarbon reservoir 106. The injection well 108 also includes a generally horizontal segment 110 that is disposed generally parallel to and is spaced generally vertically above the horizontal segment 102 of the hydrocarbon production well 100.

[0028] During SAGD, steam is injected into the injection well 108 to mobilize the hydrocarbons and create a steam chamber 112 in the reservoir 106, around and above the generally horizontal segment 110. In addition to steam injection into the steam injection well, light hydrocarbons, such as the C3 through C10 alkanes, either individually or in combination, may optionally be injected with the steam such that the light hydrocarbons function as solvents in aiding the mobilization of the hydrocarbons. The volume of light hydrocarbons that are injected is relatively small compared to the volume of steam injected. The addition of light hydrocarbons is referred to as a solvent aided process (SAP). Alternatively, or in addition to the light hydrocarbons, various non-condensing gases, such as methane or carbon dioxide, may be injected. Viscous hydrocarbons in the reservoir are heated and mobilized and the mobilized hydrocarbons drain under the effect of gravity. Fluids, including the mobilized hydrocarbons along with connate water and condensed steam (aqueous condensate), are collected in the generally horizontal segment 102. The fluids may also include gases such as steam and production gases (e.g., methane, hydrogen sulfide) from the SAGD process. and the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the cont

[0029] The steam may be generated at least partially from the produced water, for example, recovered from the production well 100. The produced water, however, includes contaminants such as oil, silica, calcium, magnesium, and iron.

[0030] A simplified schematic illustrating a system and process for removing scale in a steam generator utilized in a hydrocarbon recovery process is shown in FIG. 3.

[0031] Water is pumped through, for example, a pump assembly 302 to introduce the feed water 308 at high pressure into a steam generator 304, which in the present example is a once through steam generator (OTSG). The steam generator 304 includes multiple tubes, referred to as passes, for heat exchange to heat the feed water and generate steam. The feed water 308 may include recycled water produced from the hydrocarbon recovery process or, for example, another hydrocarbon recovery process occurring in another reservoir, fresh water, water not previously utilized in the hydrocarbon recovery process, or a combination thereof.

[0032] Although not illustrated in FIG. 3, the produced emulsion from a production well, such as the production well 100, may be subjected to known separation and degassing techniques, to separate produced water from hydrocarbons in the emulsion and from produced gas. The produced water from the production well 100 is optionally treated in a de-oiling and water treatment sub- system to remove or reduce oil in the produced water. The de-oiling process may be, for example, a known mechanical de-oiling process followed by oil filtering. Produced water de-oiling may include treatment in a skim tank, an Induced Gas Flotation (IGF) Unit or an Induced Static Flotation (ISF) Unit, and use of an Oil Removal Filter (ORF). The produced water may also be treated in an evaporator, lime softener (e.g., warm lime softener (WLS), hot lime softener), or ion exchange equipment (e.g., Strong Acid Cation (SAC) exchange, Weak Acid Cation (WAC) exchange). The produced water may optionally be subjected to additional treatment processes such as electro-flocculation, column flotation, other oil removal or filtration processes, upset recovery, hydrocyclone treatment, graphene membrane separation processes, capacitive deionization, ceramic membrane filtration, and other processes, or a combination of the above processes. and the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contra

[0033] The steam generator 304 includes an economizer, also referred to as the convective section, for preheating the feed water 308 received from the pump assembly 302, and a radiant section in fluid communication with the economizer section for generating steam from the feed water.

[0034] In the present example, a vessel 306 is in fluid communication with the feed water for introducing particles 310 and a pressurized gas 312 into the feed water prior to receipt of the feed water in the steam generator 304. The vessel 306 may be, for example, a particle blowcase.

[0035] A carrier solution 311, for example, of distilled water, acid, methanol, or any other suitable solution, is fed to the vessel 306. The particles 310 are introduced to the vessel 306, into the carrier solution. The particles 310 may be any suitable particles that are thermally stable up to a temperature of at least 100°C. The particles 310 may be thermally stable up to a temperature of at least 180°C. The particles may be, for example, glass, metal, ceramic, or a combination thereof. One example of suitable particles is cut or chopped wire. The cut wire is utilized as a scouring medium within the tubes of steam generator 304. The particles 310 may have a hardness that is greater than the hardness of the metal tubes utilized in the steam generator 304 for removing the scale away from the metal tubes. Optionally, the particles 310 may have a hardness that is greater than that of the scale to remove the scale from the inner walls of the metal tubes of the steam generator 304. The tubes may have a hardness of about 4 to about 4.5 on the Mohs hardness scale. The hardness of the scale on the tubes may vary depending on the source of the water and the reservoir. The hardness of the scale on the tubes may be about 7 on the Mohs hardness scale.

[0036] The hardness of the particles may be selected based on bond strength of the scale to the tubes. For example, the hardness of the particles may be selected based on data from scale sample x-ray diffraction or other analyses of the steam generator that show the scale to be more or less strongly affixed (e.g., caked on) to the tubes. For example, if analysis of the tubes shows that the scale is more strongly affixed, particles of a greater hardness may be utilized. Alternatively, if analysis of the tubes shows that the scale is present but less strongly affixed, for and the control of the control of the control of the control of the control of the control of the control of the example, already partially dislodged, particles of a lesser hardness may be utilized. In an embodiment, the particles may have a sufficient hardness to remove the scale without damaging the tubes beyond a threshold associated with safe operation of the steam generator. A threshold associated with safe operation of the steam generator may be a temperature threshold or a pressure threshold. For example, for a typical ASTM SA106B / C high pressure seamless steel tube the carbonization temperature limit is about 427°C, above which carbonization of the tube walls may occur leading to a reduction of the wall stresses that the tube can withstand. Accordingly, operating above this carbonization temperature limit leads to a greater likelihood of failure of the tubes. The applicable threshold temperature may thus be a temperature that is lower than the carbonization temperature limit for the tubing, to provide an operating margin. In another embodiment the tubes may comply with ASTM A 335 P22 specification, and are able to withstand high operating stress at temperatures of up to about 454°C before allowable stresses begin to reduce with increasing temperatures above 454°C. A temperature threshold of about 400°C may be utilized to provide a safe operating margin.

[0037] Pressurized gas 312, such as nitrogen, methane, propane, or any other suitable pressurized gas is also introduced into the vessel 306. Any non- condensable gas, or condensable gas in vapour form at the operating temperature and pressure of the steam generator during the process for removing scale, may be utilized. The pressurized gas 312 is utilized to create turbulent flow within the steam generator 304 when the pressurized gas 312, the particles 310, and the carrier solution flow through the steam generator 304, along with the feed water 308, during the process of removing scale in the steam generator 304. A gas fraction of about 30% to 90% may be suitable for removing scale in the steam generator 304. Optionally, the pressurized gas 312 may be oxygen or air. Because the time during which the process of removing scale is carried out is relatively short, for example, about 2 hours, oxygen or air may be utilized as the time during which corrosion of the tubes of the heat exchanger may occur is limited.

[0038] Optionally, turbulent flow may be created within the steam generator 304 during the process of removing scale when the particles 310 and the . . . . . . . . . . . . . . . . . . . . The second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second o pressurized gas 312 are introduced into the steam generator 304 in the absence of the carrier solution and the feed water.

[0039] Optionally, turbulent flow may be created within the steam generator 304 during the process of removing scale when the particles 310, and the carrier solution 311, the feed water 308, or both the carrier solution 311 and the feed water 308, are introduced into the steam generator 304 in the absence of a pressurized gas.

[0040] Fluid 314 from the steam generator 304 flows to a steam separator 316. During a hydrocarbon recovery process, steam is separated from the remaining fluid to produce dry steam 318. The remaining fluid, which may be referred to as blowdown 320, may be subjected to filtering prior to disposal or further treatment to allow for recycling as boiler feed water for steam generation. A heat recovery process may be utilized to recover waste heat from blowdown 320 or other waste heat streams produced at the hydrocarbon recovery facility. Dry steam 318 produced from the steam separator 316 is transported via pipeline for injection into the underground reservoir to mobilize the hydrocarbons during hydrocarbon recovery.

[0041] In the example of a process for removing scale as illustrated in FIG. 3, the blowdown 320 is subjected to filtering in a hydrocyclonic filter 322 that is in fluid communication with the steam separator 316 for filtering out water 324 (referred to herein as clean blowdown) from the blowdown 320. The clean blowdown 324 may be disposed of or further treated to allow for recycling as BFW for steam generation, for example, by recycling the clean blowdown 324 to the pump assembly 302. A small volume, for example, about 2% to about 20% of the volume of blowdown 320, is recovered by the hydrocyclonic filtering. Other filters may be utilized.

[0042] The hydrocyclonic filter 322 may optionally be in fluid communication with a basket filter 326, or other porous filter. The basket filter 326 is for filtering out the particles 310 from the small volume of scale and particle blowdown 328 separated from the clean blowdown 324 and drained off by and received from the hydrocyclonic filter 322. After basket filtering, which is utilized to trap the particles and the second control of the second control of the second in a contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract of the contract 310 while leaving the scale with the resultant sludge, the scale and resultant sludge 330 flows to an optional flash tank 332, to flash off additional water, thus thickening the sludge, prior to disposal of the thickened sludge 334.

[0043] Various valves are utilized for controlling fluid flow and monitoring equipment is utilized for monitoring pressure and temperature throughout the process illustrated in FIG. 3.

[0044] During steam generation for use in hydrocarbon recovery, absent the process for removing scale, the feed water 308 is pumped through the pump assembly 302 and introduced at high pressure into the steam generator 304. The fluid 314 from the steam generator 304, which includes steam and remaining fluid (including liquid water and contaminants), flows to the steam separator 316. The steam is separated from the remaining fluid to produce the dry steam 318 that is transported via pipeline for injection into the underground reservoir. The blowdown 320 is subjected to filtering prior to disposal or further treatment to allow for recycling as BFW for steam generation, for example, by recycling back to the pump assembly 302.

[0045] During steam generation, several parameters may be monitored and utilized to indicate scale build-up. Increased differential pressure across the economizer, also referred to as the convective section, radiant section, or entire steam generator may indicate scale build-up. Increased differential temperature between the feed water at the inlet and steam generator stack exhaust temperature may indicate scale build-up. Increased tube wall temperatures may also indicate scale build-up. The process for removing scale may be initiated in response to an indication of scale build-up, such as increases in differential pressures, increases in differential temperatures, increased tube wall temperatures, or on a regular schedule. The differential pressures, differential temperatures, and tube wall temperature changes at which the process for removing scale is initiated are dependent on the operating range of the steam generator.

[0046] The fire in the steam generator may be reduced, referred to as a low fire condition, or extinguished, referred to as a no fire condition, by reducing or discontinuing a feed of combustion fuel. en de la companya de la companya de la companya de la companya de la companya de la companya de la companya de

[0047] In the process for removing scale as illustrated in FIG. 3, the carrier solution 311 is fed to the vessel 306 and the particles 310 are manually introduced to the vessel 306, into the carrier solution. The pressurized gas 312 is also introduced into the vessel 306 and the carrier solution 311, the particles 310, and the pressurized gas 312 are introduced into the feed water 308 prior to introduction of the feed water 308 into the steam generator 304.

[0048] The process of removing scale refers to introduction and flow of the mixture of pressurized gas 312, the particles 310, the carrier solution 311 along with the feed water 308 through the steam generator. The pressurized gas 312 is utilized to create turbulent flow within the steam generator 304 when the pressurized gas 312, the particles 310, and the carrier solution 311 flow through the steam generator 304, along with the feed water 308. The pressure, and thus the rate of flow, of the pressurized gas 312 is selected to provide a target Reynolds number for turbulent flow and dynamic pressure of from about 15,000 lb / ft2 (718) kPa) to about 60,000 lb / ft2 (2873 kPa) within the tubes of the steam generator to facilitate scale removal from the interior walls of the tubes of the steam generator 304. For example, a dynamic pressure of about 30,000 lb / ft² (1436 kPa) may be targeted. Thus, the turbulent flow caused by the introduction of the pressurized gas, strikes the particles against the interior walls of the steam generator 304 to scour off the interior walls of the steam generator 304 without excessive wear of the tubes of the steam generator 304. The feed water 308, along with the particles 310 and the pressurized gas 312 may be introduced into multiple tubes of the steam generator 304 simultaneously or may be introduced into the tubes, one at a time. There may be one process for removing scale per steam generator pass or there may be one process for removing scale that is utilized serially on each pass.

[0049] As indicated above, the particles 310 are thermally stable up to a temperature of at least 100°C and may be thermally stable up to a temperature of at least 180°C such that the particles are thermally stable and still useful for removing scale in the steam generator, which may still be hot during scale removal. The particles have a sufficient hardness to remove the scale without damaging the tubes beyond a threshold associated with safe operation of the steam generator. and the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the second of the seco

[0050] As indicated above, the process for removing scale may be initiated in response to an indication of scale build-up, such as increases in differential pressures, increases in differential temperatures, increased tube wall temperatures, or on a regular schedule. Sufficient scale may be removed when an acceptable range of differential pressures, differential temperatures, or wall temperatures is achieved during operation of the steam generator. Experimentation may be carried out to determine suitable particle hardness and time during which the process for removing scale is carried out.

[0051] The differential pressures, differential temperatures, and / or wall temperatures post the process for removing scale may be utilized as a baseline for monitoring for subsequent increases in one or more of these measurements, which may once again trigger implementation of the process for removing scale. This cycle may be repeated, for example, for as long as steam generation is required for hydrocarbon recovery. For example, for a 250 MM BTU / h OTSG, an increase in differential pressure from a baseline of about 1,500 kPag by up to about 300 kPag or higher, an increase in differential temperature from a baseline of about 20°C (between the feed water at the inlet and steam generator stack exhaust) by up to about 10°C or higher, and / or an increase in tube wall temperature from a baseline of about 350°C by up to about 50°C or higher may indicate scale build-up and embodiments of the process for removing scale may be initiated as described herein. A person of skill in the art will appreciate that boilers of a different size or type may have different normal and maximum operating ranges and indications of scale build-up may likewise be different prior to initiating the process for removing scale.

[0052] An indication that sufficient scale has been removed may be a decrease in differential pressure, differential temperature, and / or tube wall temperature. For example, differential pressure, differential temperature, and / or tube wall temperature may decrease to within a percentage of the baseline measurements for these parameters (e.g., about 0-10% or within a percentage that facilitates scale removal without damaging the tubes beyond a threshold associated with safe operation of the steam generator as discussed herein). and the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the control of the cont

[0053] In addition to the carrier solution, the pressurized gas, and the particles, other chemicals may be added for the purpose of descaling. For example, acid, chelant, silica inhibitor, and others may be added depending on the particular reservoir, water and facility.

[0054] Because the steam generator is operated under low or no fire conditions, little or no steam is generated in the steam generator 304 during the process for removing scale.

[0055] Steam samples 313 are taken from steam sampling lines to sample the fluid 314 from the steam generator 304. The steam samples are generally taken for the purpose of testing the quality of the steam generated. During the scale removal process, such steam lines may become blocked as a result of scale travelling into the sampling lines. To reduce the chance of blocking the steam sampling lines, the sample lines may be shut in or blocked to stop flow during the scale removal process. Alternatively, a blow-off connection to a blowdown tank may be utilized to purge the sampling lines. In yet another alternative, a gas, such as nitrogen, propane, methane, or any other suitable gas, or a liquid, may be introduced through the sampling lines to create a backflow and thereby inhibit flow out the sampling lines.

[0056] The fluid 314 from the steam generator 304 flows to the steam separator 316. During the process for removing scale, little or no steam is separated and the remaining fluid, which may be referred to as blowdown 320, continues to the hydrocyclonic filter 322 that is in fluid communication with the steam separator 316 for filtering out clean blowdown 324 from the blowdown 320 and disposal or further treatment of the clean blowdown 324 to allow for recycling as BFW for steam generation, for example, by recycling to the pump assembly 302. The small volume of fluid drained off from the hydrocyclonic filter 322, which includes the particles and scale, is optionally received in the basket filter 326 and the particles 310 are filtered out. Optionally, the particles 310 may be reused one or more times for removing scale in the steam generator 304. Alternatively, the particles may be discarded. After optional thickening in the flash tank 332, the thickened sludge 334, including the scale, is disposed of. and the second second second second second second second second second second second second second second second second second second second second second second second second second second second second second second seco

[0057] In the example described above, the steam generator 304 is operated under low or no fire conditions during the scale removal process. Alternatively, the scale removal process may be carried out while the steam generator 304 is operated such that some steam is generated without creating excessive dynamic pressure in the steam generator which may cause accelerated tube erosion.

[0058] The scale removal process may be carried out each month in a short period of time. For example, the process may be carried out once each month and may be carried out in about 2 hours.

[0059] A simplified schematic illustrating another example of a system and scale removal process in a steam generator utilized in a hydrocarbon recovery process is shown in FIG. 4. The system of FIG. 4 includes many elements that are similar to those of FIG. 3. Many of the similar elements are not described again in detail.

[0060] Water is pumped through, for example, the pump assembly 302 to introduce the feed water 308 at high pressure into the steam generator 304. The steam generator 304 includes an economizer for preheating the feed water 308 received from the pump assembly 302, and a radiant section in fluid communication with the economizer section for generating steam from the feed water.

[0061] A vessel 306 is in fluid communication with the feed water for introducing particles and pressurized gas into the feed water prior to receipt of the feed water in the steam generator 304. The vessel 306 may be, for example, a particle blowcase. The particles 310 are introduced to the vessel 306, into the carrier solution (not shown). Pressurized gas 312 is also introduced into the vessel 306 and the pressurized gas 312 is utilized to create turbulent flow within the steam generator 304 when the pressurized gas 312, the particles 310, and the carrier solution flow through the steam generator 304, along with the feed water 308.

[0062] In the present example, fluid 314 from the steam generator 304 flows to the steam separator 316 during a hydrocarbon recovery process and steam is separated from the remaining fluid to produce dry steam 318. The remaining fluid, which may be referred to as blowdown 320, is disposed of. en al company de la company de la company de la company de la company de la company de la company de la company de la company de la company de la company de la company de la company de la company de la company de la compan

[0063] During the scale removal process however, fluid from the steam generator 304 does not flow to the steam separator 316. Instead, the fluid 314, including the scale and particles 310, from the steam generator 304 is directed to a disposal receptacle such as a pond or other disposal site 440.

[0064] In the example illustrated in FIG. 4. The fluid from the steam generator 304 is directed to the steam separator 316 during the hydrocarbon recovery process, and is disposed of during the process for removing scale.

[0065] During the steam generation for use in hydrocarbon recovery, without the process for removing scale, the feed water 308 is pumped through the pump assembly 302 and introduced at high pressure into the steam generator 304. The fluid 314 from the steam generator 304, which includes steam and water, flows to the steam separator 316. The steam is separated from the remaining fluid to produce the dry steam 318 that is transported via pipeline for injection into the underground reservoir. The blowdown 320 is disposed of, as described above.

[0066] In the scale removal process, the fire in the steam generator may be reduced, referred to a low fire condition, or extinguished, referred to as no fire by reducing or discontinuing a feed of combustion fuel.

[0067] The carrier solution is introduced to the vessel 306 and the particles 310 are manually introduced to the vessel 306, into the carrier solution. The pressurized gas 312 is also introduced into the vessel 306 and the carrier solution, the particles 310, and the pressurized gas 312 are introduced into the feed water 308 from the pump assembly 302, prior to introduction into the steam generator 304. The turbulent flow caused by the introduction of the pressurized gas, pounds the particles against the interior walls of the steam generator 304 to scour of the interior walls of the steam generator 304 without excessive wear of the tubes of the steam generator 304. Fluid 314 from the steam generator 304, including the particles and the scale is disposed of.

[0068] In an alternative embodiment, the pressurized gas 312 and the particles 310 are introduced into the feed water 308, with the carrier solution being optional. graduate and a supply and a second of the first section in

[0069] A simplified schematic illustrating still another example of a system and process for removing scale in a steam generator utilized in a hydrocarbon recovery process is shown in FIG. 5. The system of FIG. 5 is similar to the system of FIG. 4 and is therefore not described again in its entirety. In the example shown in FIG. 5, however, the particles 310 are introduced into a carrier solution in a vessel, which in this example is a fluid tank 506. The carrier solution and the particles are together pumped, via a pump 550, into the feed water 308, prior to introduction of the feed water 308 into the steam generator 304. Pressurized gas 312, is fed from a pressurized gas storage vessel 552 into the feed water 308, prior to introduction of the feed water into the steam generator 304. Thus, in the present example, the particles 310 and carrier solution are introduced into the feed water 308 separate of the introduction of the pressurized gas 312 into the feed water 308.

[0070] The remaining elements of the present example are similar to those described with reference to FIG. 4 and are therefore not further described herein.

[0071] A simplified schematic view of yet a further example of a system and process for removing scale in a steam generator utilized in a hydrocarbon recovery process is shown in FIG. 6. The system of FIG. 6 is similar to the system of FIG. 4 and is therefore not described again in its entirety. In the example shown in FIG. 6, however, the particles 310 are introduced into an eductor 606 that is utilized to introduce the particles into the feed water 308, prior to introduction of the feed water 308 into the steam generator 304.

[0072] A motive fluid 654 is utilized with the eductor 606 to pump the particles 310 into the feed water 308. The motive fluid may be, for example, boiler feed water, as is illustrated in the line 656 extending from the feed water 308, through a flow control valve (FCV) 658 and into the eductor 606. Alternatively, other motive fluids may be utilized, such as brackish water, blowdown water, air, nitrogen, or other gases. Optionally an acid, such as HCl, or a base, such as NaOH, may be mixed with boiler feed water, brackish water, or blowdown water for use as the motive fluid 654. Control of the Control of the Control of the Control of the Control of the Control of the Control of the Control of the Control of the Control of the Control of the Control of the Control of the Control of the Control of t

[0073] The particles 310 are introduced into the eductor 606, via the eductor suction. The particles 310 may include, for example cut wire, ceramic balls, sand, or other particles in air. The particles 310 may alternatively be introduced into the eductor in an aqueous medium such as the motive fluids referred to above. In yet another alternative, the particles 310 may be introduced into the eductor from a pressurized vessel including the particles 310 in a gas such as air, nitrogen, propane, or any other suitable gas.

[0074] Thus, in the present example, the particles may be introduced into the boiler feed water without a pressurized gas while still providing turbulent flow for removal of the scale. Alternatively, a carrier solution for introduction of the particles 310 into the boiler feed water is optional as the particles 310 may be introduced utilizing a gas through the eductor 606.

[0075] During the scale removal process, fluid from the steam generator 304 does not flow to the steam separator 316. Instead, the fluid 314, including the scale and particles 310, from the steam generator 304 is directed to, for example, a blowdown pond or other disposal site 440.

[0076] The remaining elements of the present example are similar to those described with reference to FIG. 4 and are therefore not further described herein.

[0077] In each of the examples described above the particles along with the feed water may be introduced into the steam generator for removal of the scale at any suitable temperature. For example, the particles along with the feed water may be introduced at a temperature of about 5°C to greater than 180°C. The feed water may already be at or near a temperature of about 180°C. The temperature of the particles and feed water may be in the range of about 100°C to about 180°C and the temperature may increase slightly in the steam generator as a result of residual heating. Optionally, the particles along with the feed water may be introduced into the steam generator at a temperature as low as 5°C for removal of the scale, however. The use of feed water below about 50°C or above about 150°C may facilitate scale removal by causing cracking of the scale as a result of differing thermal expansion rate of the scale compared to the thermal expansion rate of the metal tubes. Such cracks may facilitate removal by the fluidized particles. The use The second of the second of en en en en en en en en en en en en en e of an acid or base in addition to feed water and / or carrier solution in the steam generator above about 150°C may also facilitate removal as the acid or base may attack the scale boundaries.

[0078] Advantageously, the particles, such as metal cuttings, chopped wire, metal beads, ceramics, glass beads, or other suitable particles in the steam generator 304 scour the internal walls of the tubes, thereby removing scale that would otherwise reduce heat transfer and decrease efficiency. Thus, pre-treatment of the feed water may be reduced. In addition, scale removal in the steam generator may be carried out in a matter of hours utilizing the present process, reducing time and expense for removing scale by comparison to known methods of operating a pig within the steam generator.

[0079] The described embodiments are to be considered in all respects only as illustrative and not restrictive. The scope of the claims should not be limited by the preferred embodiments set forth in the examples, but should be given the broadest interpretation consistent with the description as a whole. All changes that come with meaning and range of equivalency of the claims are to be embraced within their scope.

Claims

1. A process for removing scale in a steam generator for use in a hydrocarbon recovery process, the process comprising: introducing feed water into the steam generator; introducing particles and a pressurized gas into the steam generator, at a pressure sufficient to cause turbulent flow of fluid including the feed water, the gas, and the particles, for removing scale from interior walls of tubes of the steam generator, wherein the particles have a sufficient hardness to remove the scale without damaging the tubes beyond a threshold associated with safe operation of the steam generator.

2. The process according to claim 1, wherein the particles are thermally stable up to a temperature of at least 180°C.

3. The process according to claim 1, wherein the particles and the feed water are introduced into the steam generator at a temperature of about 180°C.

4. The process according to claim 1, comprising separating the particles and the scale from the fluid.

5. The process according to claim 1, wherein the particles and pressurized gas are introduced into a vessel and the particles and pressurized gas are introduced into the steam generator from the vessel.

6. The process according to claim 5, wherein the particles are introduced into a carrier solution in the vessel.

7. The process according to claim 1, comprising generating steam in the steam generator and monitoring a differential pressure across at least a part of the steam generator prior to introducing the particles and the pressurized gas, and wherein the particles and the pressurized gas are introduced in response to detecting a change in the differential pressure that exceeds a threshold.

8. The process according to claim 1, comprising inhibiting blocking of steam sampling lines from the steam generator by scale removed from the tubes of the steam generator by one of shutting in the steam sampling lines, creating a backflow of fluid in the steam sampling lines, and purging the steam sampling lines utilizing a blow-off connection to a blowdown tank.

9. A system for producing steam for use in a hydrocarbon recovery process to recover hydrocarbons from a hydrocarbon reservoir, the system comprising: a steam generator comprising: an economizer section for preheating feed water; a radiant section in fluid communication with the economizer section for generating steam from the feed water; and at least one inlet for receiving pressurized gas and particles into the economizer section to create turbulent flow of fluid including the feed water, the gas, and the particles, for removing scale from interior walls of tubes of the steam generator, wherein the particles have a sufficient hardness to remove the scale without damaging the tubes beyond a threshold associated with safe operation of the steam generator; and a separator in fluid communication with the steam generator for separating the steam and remaining fluid generated from the feed water, the steam for use in hydrocarbon recovery.

10. The system according to claim 9, wherein the particles and the feed water are introduced into the steam generator at a temperature of about 180°C.

11. The system according to claim 9, comprising a vessel coupled to the steam generator for introducing the pressurized gas and the particles into the inlet of the steam generator.

12. The system according to claim 11, wherein the vessel is coupled to a feed water line coupled to the at least one inlet for receiving the pressurized gas, the particles, and the feed water into the steam generator.

13. The system according to claim 9, comprising a cyclonic filter in fluid communication with the separator for filtering out clean blowdown from the remaining fluid.

14. The system according to claim 9, wherein the pressurized gas is introduced into the steam generator at a sufficient pressure to produce turbulent flow in the tubes of the steam generator.

15. The system according to claim 12, wherein the vessel is configured to receive the particles and a carrier solution.

16. The system according to claim 9, wherein the separator is configured to be coupled to an injection well for injection of the steam into the hydrocarbon reservoir.

17. The system according to claim 9, comprising a disposal receptacle in fluid communication with the steam generator for receiving the particles and the scale.

18. The system according to claim 9, comprising measurement equipment for monitoring a differential pressure across at least a part of the steam generator and utilizing the monitored differential pressure to determine whether to introduce the pressurized gas and particles into the steam generator through the inlet.

19. The system according to claim 9, comprising a steam sampling line for sampling steam from the steam generator, and a blow-off connection connecting the steam sampling line to a blowdown tank for purging the steam sampling line.