Method To Stabilize Base Metal Catalysts By Overcoating Via Atomic Layer Deposition And Resulting Product (Wisconsin Alumni Research Foundation)

Method To Stabilize Base Metal Catalysts By Overcoating Via Atomic Layer Deposition And Resulting Product (Wisconsin Alumni Research Foundation)
United States Patent Application 20160361708
Dumesic; James A. ;   et al.   December 15, 2016
Applicant: Wisconsin Alumni Research Foundation
Abstract
A method for stabilizing a metal or metal-containing particle supported on a surface is described, along with the resulting composition of matter. The method includes the steps of depositing upon the surface a protective thin film of a material of sufficient thickness to overcoat the metal or metal-containing particle and the surface, thereby yielding an armored surface; and then calcining the armored surface for a time and at a temperature sufficient to form channels in the protective thin film, wherein the channels so formed expose a portion of the metal- or metal-containing particle to the surrounding environment. Also described is a method of performing a heterogeneous catalytic reaction using the stabilized, supported catalyst.
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Method And System For Lining A Tubular (Shell)

Method And System For Lining A Tubular (Shell)
United States Patent Application 20160362968
Kriesels; Petrus Cornelis ;   et al.   December 15, 2016
Applicant: Shell Oil Company
Abstract
A liner having an outer surface coated with a fluid absorbing coating is cladded to a tubing string by inserting the folded liner into the tubing string and then unfolding the liner against the tubing string. The liner may be a long single thin foil corrosion resistant liner coated with a sticky glue and a hygroscopic and/or other fluid absorbing coating to absorb fluid pockets trapped between the tubing and liner and inhibit corrosion and leakage of, the elongate tubing string.
BACKGROUND OF THE INVENTION
[0001] The invention relates to method and system for internally lining a tubing string to protect the tubing string against corrosion and/or leakage.
[0002] Wellbores for the exploration and production of oil, gas or other minerals from subterranean reservoir layers are typically provided with protective tubing, casing and/or other liner strings. These may include a pipe string lowered into an openhole section of the wellbore and cemented in place. Herein, the term casing is typically used to indicate a pipe string extending from surface into the wellbore, whereas liner may typically be used to indicate a pipe string which extends from a downhole location further down the wellbore. Hereinafter, the term casing will be primarily used, but the invention is equally applicable to liner.
[0003] The casing or liner strings may be designed to withstand a variety of forces, such as collapse, burst, and tensile failure, as well as chemically aggressive brines. The casing string is typically assembled from multiple interconnected pipe sections, having a length of for instance about 10 metres each. Casing connections connect adjacent pipe sections. The casing sections may be fabricated with male threads on each end, wherein shorter-length casing couplings with female threads are used to join the individual sections of casing together. Alternatively, pipe sections may be fabricated with male threads on one end and female threads on the other.
[0004] Casing may be run to protect fresh water formations, isolate a zone of lost returns or isolate formation layers with significantly different pressure gradients. The operation during which the casing is put into the wellbore is commonly called "running pipe."
[0005] Inside the innermost casing, a wellbore may typically be provided with another tubing string, typically referred to as production string or production tubing. Herein, the production tubing may be assembled with other completion components to make up the production string. The production string is the primary conduit through which reservoir fluids are produced to surface. The production string is typically assembled with tubing and completion components in a configuration that suits the wellbore conditions and the production method. The tubing itself may be made up from interconnected pipe sections, in a similar fashion to the casing strings. An important function of the production string is to protect the primary wellbore tubulars, including the casing and liner, from corrosion or erosion by the reservoir fluid.
[0006] Interior surfaces of the production tubing and their associated connections are frequently subjected to one or more of relatively high temperatures, high pressures and highly corrosive fluids. Temperatures may range up to 175.degree. C. or more. Pressures may be as high as 1400 bars or more. The reservoir fluids may be highly corrosive, for instance due to the combination of hydrocarbons, CO.sub.2 and/or H.sub.2S in the presence of water. The use of secondary and tertiary enhanced recovery methods in hydrocarbon production, such as gas injection, water flooding and chemical flooding, may further aggravate the situation.
[0007] Pipe sections for wellbore tubulars, including the casing or production tubular, are usually manufactured from plain carbon steel with varying compositions that is heat-treated to varying strengths. Alternatively, pipe sections may be specially fabricated of stainless steel, nickel alloys, aluminium, titanium, fiberglass and other materials.
[0008] Materials have different resistance to corrosion. Carbon steel for instance is relatively inexpensive, but also more prone to corrosion than the other materials listed above.
[0009] Several types of corrosion mechanisms exist, including: erosion-corrosion (also known as impingement), stress corrosion cracking, sulphide stress cracking, pitting, and galvanic corrosion.
[0010] Corrosion in metals may be caused by the flow of electricity from one metal to another metal or from one part of the surface of one piece of metal to another part of the same metal where conditions permit the flow of electricity. Further, a moist conductor or electrolyte must be present for this flow of energy to take place. Energy passes from a negative region to a positive region via the electrolyte media.
[0011] Electrical contact or coupling of dissimilar metals frequently causes increased corrosion. This form of corrosion is generally referred to as galvanic corrosion. Galvanic corrosion is quite prevalent and troublesome, occurring in a wide variety of circumstances. For example, coupling aluminium and iron pipe together will result in very rapid corrosion of the aluminium pipe section. The galvanic corrosion mechanism may be illustrated by considering the effect of electrically connecting zinc to platinum immersed in sea water. Under these conditions, the platinum is inert and does not corrode, while the zinc is attacked. The reactions occurring on the surface of the zinc are the anodic oxidation of zinc to zinc ions, and the cathodic reduction of dissolved oxygen to hydroxide ions. If the electrical potentials of these two metals are measured, the platinum would be found to have a positive potential, while the zinc would be found to have a negative potential. As may be appreciated, as the potential difference increases, galvanic corrosion increases.
[0012] Obviously, from a corrosion standpoint, the replacement of steel tubulars and associated hardware with materials less subject to corrosion would be highly desirable in gas and oil applications, if it were practical or economically viable. Non-metallic components, such as fiberglass casing, tubing, sucker rods and the like are finding their way into oil field applications. Performance limitations, including service loads, pressures and temperatures, restrict the across-the-board replacement of metallic hardware, however. On the other hand, pipe sections made of solid corrosion resistant alloy (CRA), such as stainless steel and nickel alloy, may provide sufficient corrosion resistance. But tubular sections made of solid corrosion resistant alloys are typically much more expensive than carbon steel. The latter may render projects uneconomical. In addition, newly developed hydrocarbon reservoirs are producing increasingly corrosive hydrocarbons, for instance including a greater percentage of H.sub.2S, requiring higher grade Corrosion Resistant Alloys (CRAs). And higher grade CRAs are increasingly more expensive. For instance, compared to API grade P110 carbon steel, the same pipe section made of CRA may be up to 5, 10 or even 25 times more expensive (when made of 316L, SM25CRW-110/125, or C22 CRA respectively).
[0013] Several manufacturing methods have been developed for producing corrosion resistant clad or lined carbon steel tubular, for instance for transporting oil and gas, to achieve economic advantages over solid corrosion resistant alloy (CRA) tubular such as stainless steel and nickel alloy. However, the use of these clad or lined tubulars has not gained acceptance for downhole tubular primarily due to the lack of a thread connection that has demonstrated adequate corrosion resistance performance.
[0014] To guard against galvanic corrosion, insulating coatings may be applied. In order for a coating to be used on tubular sections and threaded couplings to protect the metal substrate from corrosion, the coating must be resistant to attack and maintain its adherence to the metal substrate under the harsh downhole conditions referred to above.
[0015] In various oil and gas applications, steel pipe is provided with a lining of corrosion-resistant material. For example, it is known to bond various epoxy-based coatings to the interior of the pipe, as well as coatings containing polyethylene, polyvinyl chloride and other thermoplastic and thermosetting materials.
[0016] Of the various polymeric coating materials, arylene sulfide polymers have gained wide acceptance, see for instance U.S. Pat. No. 3,354,129. Generally, these polymers consist of a recurring aromatic structure coupled in repeating units through a sulfur atom. Commercially available arylene sulfide polymers which have been used for coating oil and gas pipes and pipe couplings are polyphenylene sulfides. The polyphenylene sulfides used in oil and gas applications exhibit high melting points, outstanding chemical resistance, thermal stability and are non-flammable. They are also characterized by high stiffness and good retention of mechanical properties at elevated temperatures as well as the ability to deform smoothly, thereby, for example, preventing the galling of threads, even at high thicknesses.
[0017] U.S. Pat. No. 3,744,530 describes polyphenylene sulfide coated pipes, wherein the polyphenylene sulfide coating also contains a filler, such as iron oxide, in an amount of between 5% to 30%.
[0018] While polymeric coated pipes and couplings have gained wide acceptance in applications requiring corrosion protection, the cracking of such coatings during installation and in use tends to limit their insulating effect, increasing the likelihood that galvanic corrosion will take place. This is particularly relevant in the female part or pin-end of the connections, where cracking may occur during assembly of the connection. Moreover, the polymeric coatings of threaded couplings are particularly prone to cracking due to the stresses imparted during assembly of connections. In addition to cracking, many polymers allow diffusion of hydrogen and other light hydrocarbons through the thickness of the coating or liner, thereby allowing gas to accumulate between layers, which, in the case of a corrosion resistant liner could result in collapse if the pressures in the bore and annulus become unbalanced.
[0019] JP 60 109686 A (KAWASAKI HEAVY IND LTD) 15 Jun. 1985 provides a pipe system for transport of corrosive fluids. The pipe system comprises a tubular member made of a corrosion prone metal. Each tubular member is provided with an inner lining of a corrosion resistant material. At each end, the tubular member and the inner lining are connected to a threaded coupling member, which is made of a corrosion resistant material. The tubular member and the liner are connected to the threaded coupling member by a weld seam. But the welding of solid CRA couplings to a carbon steel pipe body, or the welding related method, can cause issues in itself. See for instance the description of galvanic corrosion above. In addition, the cost saving from using clad steel rather than solid CRA is particularly valid when the total wall thickness of the pipe increases. When the product of outer diameter (OD) times wall thickness (T) decreases however, the cost benefit of corrosion resistant alloy clad pipe versus solid CRA pipe decreases rapidly. For instance for pipe clad with Incoloy 825, the cost benefit is reduced to nil for tubulars having smaller OD.times.T. The latter however are typically used for production tubing.
[0020] While the use of corrosion resistant alloys for corrosion control has demonstrated superior corrosion resistance properties, they are quite costly and exhibit complex manufacturing and handling constraints. The price of high-performance steel, such as 18-8 stainless steel, may be about 5 times as expensive as carbon steel. Nickel alloys for instance, which may also include high percentages of chromium (e.g. more than 10%) and/or molybdenum, may exceed the price of carbon steel with a factor of about 20 to 30. Nickel alloys, however, are often the material of choice in environments containing relatively large volumes of H.sub.2S. For instance when the H.sub.2S partial pressure exceeds 5 to 10 bars, nickel alloys may be required.
[0021] In oilfield applications, polymeric coatings will be unsuitable when the partial pressures of either CO.sub.2, H.sub.2S and/or water exceed a certain threshold, as these materials may permeate through the polymeric coating, which may lead to corrosion of the carbon steel base material. Also, the temperature range wherein polymeric coatings can be applied is typically limited to a maximum of about 100 to 150 degree C.
[0022] US-2007/0095532 discloses an apparatus to deploy a patch comprising an inner metal tube and an outer resilient sealing member. Suitably, the inner metal tube is formed from steel, preferably, carbon steel. The outer resilient sealing member is formed from an elastomeric material. Suitably, the patch may be from 10 to 1000 feet in length.
[0023] As a disadvantage, in the disclosure of US-2007/0095532, the length of the liner patch is inherently limited by the apparatus described. The liner patch is clamped by extending and retracting slips attached to the apparatus, so the weight of the liner patch is carried by the friction these slips exert on the liner. The force applied by these slips determines the frictional force. The extending and retracting slips will have insufficient capacity to support liner exceeding a certain length, such as several kilometres. Furthermore, in the case of a very thin liner, the pressure that the slips can exert before deforming the liner is minimal, minimizing the friction force also. Although a thin liner is lighter than a thicker patch, the weight of the liner is still typically in the order of 1.3 kg/m. This would provide a total weight of several thousand kilograms if one would consider lining the production tubing along the length of the wellbore.
[0024] As hydrocarbon wellbores extend to ever greater target depths, for instance in the range of five to ten kilometres or even more, the apparatus of US-2007/0095532 would be unsuitable to provide a liner patch to the entire inner surface of the production tubing.
[0025] Furthermore, the apparatus of US-2007/0095532 is supported by a wireline which, in the configuration as disclosed, would have to travel through the liner. For longer lengths, the practicalities of threading several kilometres of wireline through the liner patch, while still supporting the weight of the liner by the wire line while running into the well, are unrealistic. This is supported by the exemplary length of liner patch as disclosed in US-2007/0095532, which is limited to 1000 feet (about 300 metres).
[0026] US-2010/0247794-A1 wellbore tubing lining method wherein a polymer layer is cured downhole actinic radiation. The liner is introduced in the borehole via an apparatus attached to a wireline, which would than expand the liner via a vessel or bladder on a wire line. The bladder will inflate along the full length of the liner to expand the liner. The system is limited to the delivering of a polymer liner. Also, the system can only be applied for limited lengths. The fabrication of a bladder or vessel to expand the liner will inherently limit the length of the liner to be expanded. Providing a bladder which extends along the entire length of the production tubing will be impossible. Moreover, the necessity to run such a vessel into the hole will further limit the maximum length thereof.
[0027] U.S. Pat. No. 3,785,193 discloses a liner expanding apparatus and a method including lowering and affixing a liner by means of wireline. The liner is crimped onto an expansion tool, and hangs down from it. This configuration has similar limitations to patent documents US-2007/0095532 and US-2010/0247794-A1 described above, in that the clamping of the liner is based on friction. The friction is insufficient for longer lengths of liner, particularly for thinner liner, given the limited frictional force which can be generated. Also, given that the apparatus is suspended from a wireline, running in the liner will prove impossible above a certain threshold length of liner, due to problems at the surface. As a result, the system of U.S. Pat. No. 3,785,193 is unsuitable to line production tubing along its entire length, which may be in the order of several kilometres.
[0028] Other methods and system for expanding a liner within a surrounding tubular string are disclosed in International patent application WO 98/21444 and US patent applications US 2006/052936, US2007/095532 and US 2010/247794.
[0029] A general problem with the known tubing lining systems and methods is that pockets of fluids may be trapped between the liner and tubing, which may result in detachment of the liner from the inner wall of the tubing and collapse of the liner.
[0030] There is a need for an improved method and system to protect tubulars against corrosion and leakage by use of a tubing liner assembly that automatically removes fluid from the residual space between the liner and tubing, thereby inhibiting formation of fluid pockets and/or longitudinal leakage paths between the liner and tubing and reducing the risk of detachment of the liner from the inner surface of the tubing and the associated risk of subsequent collapse of the liner.
SUMMARY OF THE INVENTION
[0031] The present invention therefore provides a method for lining a tubing string, comprising; [0032] inserting a folded liner having an outer surface which is at least partially coated with a fluid absorbing coating into the tubing string; [0033] unfolding the liner to expand the liner against an inner surface of the tubing string; and [0034] inducing the coating to absorb fluid trapped between an inner surface of the tubing string and an outer surface of the expanded liner.
[0035] The coating may comprise bonding and liquid absorbing additives, such as a sticky glue and a hygroscopic material, such as silicagel and/or a cross-linked acrylate polymer described in U.S. Pat. No. 7,144,980, which is generally known as a Super Absorbent Polymer (SAP) or hydrogel, which absorbs any substantial pockets of water and/or other fluid trapped, and thereby enhances the bond, between the tubing string and the expanded liner.
[0036] In accordance with another aspect of the invention there is provided a system for lining a tubing string in a wellbore, comprising a liner, which is configured to be folded in a collapsed state into the tubing string and to be unfolded against an inner surface of the tubing string and which is at least partially coated with a fluid absorbing coating that is configured to absorb fluid trapped between the inner surface of the tubing string and the expanded liner.
[0037] The method and system according to the invention enable continuous cladding of a kilometres long oil and/or gas well tubing and/or casing string by a single thin foil corrosion resistant liner that may be coated with hygroscopic and sticky glue to enhance the bonding of the liner to, and inhibit corrosion and leakage of, the tubing and/or casing string.
[0038] These and other features, embodiments and advantages of the method and system according to the invention are described in the accompanying claims, abstract and the following detailed description of non-limiting embodiments depicted in the accompanying drawings, in which description reference numerals are used which refer to corresponding reference numerals that are depicted in the drawings.
[0039] Similar reference numerals in different figures denote the same or similar objects. Objects and other features depicted in the figures and/or described in this specification, abstract and/or claims may be combined in different ways by a person skilled in the art.
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Water Treatment System And Method (Mitsubishi)

Water Treatment System And Method (Mitsubishi)
United States Patent Application 20160367936
Ukai; Nobuyuki ;   et al.   December 22, 2016
Assignee: Mitsubishi Heavy Industries, Ltd.
Abstract
The water treatment system includes: a wet desulfurization device that removes sulfur oxide present in boiler flue gas; a dewatering device that separates gypsum from desulfurization waste water containing gypsum slurry; a reaction tank to which separated water from the dewatering device is introduced, and which immobilizes heavy metals present in the separated water by inputting a chelating agent; a solid-liquid separation unit that performs solid-liquid separation with respect to heavy metal sludge present in the separated water; a mixing unit that mixes the separated water obtained with effluent generated in a plant facility; a desalination device that removes salt content from the mixed water mixed by the mixing unit; and a spray drying device that includes a spray unit, which sprays concentrated water in which the salt content has been concentrated by the desalination device, and that performs spray drying using a part of the boiler flue gas.
FIELD
[0001] The present invention relates to a water treatment system and a method therefor for effluent generated in a boiler plant or a chemical plant facility, for example.
BACKGROUND
[0002] For example, in a process plant of a power plant or a chemical plant, effluent is generated in, for example, a boiler, a reactor, a wet cooling tower of a condenser, a water treatment device, and so on. There are various kinds of treatment devices proposed to treat such effluent, but there may be a problem in which any of these treatment devices requires high cost. To solve such a problem, there is a proposed boiler provided with a waste water treatment device in which alkaline blow water is neutralized by spraying, into a flue gas duct, cooling water (blow water) of a cooling tower of a boiler as mists having a droplet diameter from 20 to 120 .mu.m (Patent Literature 1).
[0003] Further, there is another proposed waste water treatment device in which an amount of waste water which can be evaporated by spraying effluent into a flue gas duct is increased (Patent Literature 2).
SUMMARY
Technical Problem
[0006] However, according to the invention of Patent Literature 1, the waste water can be treated easily and at low cost, but there is problems in which treatment may not be performed in the case an amount of the waste water is increased relative to thermal energy (temperature, flow rate) of flue gas and an energy amount required to evaporate the increased waste water becomes large.
[0007] Further, according to the invention of Patent Literature 2, an amount of waste water can be reduced by a concentration device, but there is a problem in which output of a steam turbine may be decreased because a part of steam generated in a boiler is bled in the concentration device.
[0008] Furthermore, since the flue gas discharged from a boiler plant may contain trace amounts of toxic substances such as mercury in addition to nitrogen oxide and sulfur oxide, a countermeasure against mercury is required in order to perform water treatment by mixing waste water in other plant facility.
[0009] Therefore, providing an effective treatment technology is strongly demanded, according to which, the effluent generated in a process plant of, for example, a power plant or a chemical plant, such as the effluent discharged from a boiler, a reactor, a wet cooling tower of a condenser, a water treatment device, and the like can be treated at low cost in consideration of a countermeasure against mercury discharge without deteriorating efficiency of the boiler.
[0010] In consideration of the above problems, the present invention is directed to providing a water treatment system and a method therefor for effluent generated in a plant facility.
Solution to Problem
[0011] In order to solve the above-mentioned problem, the first aspect of the present invention is a water treatment system including: a wet desulfurization device that removes sulfur oxide from boiler flue gas; a dewatering device that separates gypsum from desulfurization waste water which contains gypsum slurry and which is obtained from the wet desulfurization device; a mercury removing unit to which is introduced separated water that is obtained from the dewatering device, and which immobilizes heavy metals present in the separated water by inputting a chelating agent; a solid-liquid separation unit that performs solid-liquid separation with respect to solid content present in separated water obtained from the mercury removing unit; a mixing unit that mixes separated water obtained from the solid-liquid separation unit with effluent generated in a plant facility; a desalination device that removes salt content from mixed water obtained by the mixing unit; and a spray drying device that includes a spraying unit, which sprays concentrated water in which salt content has been concentrated by the desalination device, and that performs spray drying using a part of the boiler flue gas.
[0012] The second aspect of the present invention is a water treatment system including: a wet desulfurization device that removes sulfur oxide from boiler flue gas; a dewatering device that separates gypsum from desulfurization waste water which contains gypsum slurry and which is obtained from the wet desulfurization device; a mixing unit that mixes separated water obtained from the dewatering device with effluent generated in a plant facility; a reaction tank to which mixed water obtained by the mixing unit is introduced and which immobilizes heavy metals present in separated water by inputting a chelating agent; a solid-liquid separation unit that performs solid-liquid separation with respect to solid content present in mixed water obtained from the reaction tank; a desalination device that removes salt content from mixed water subjected to solid-liquid separation; and a spray drying device that includes a spraying unit which sprays concentrated water in which salt content has been concentrated by the desalination device, and that performs spray drying using a part of the boiler flue gas.
[0013] The third aspect of the present invention is the water treatment system according to the first or the second aspect further including a membrane treatment unit that performs treatment using a membrane having univalent selectivity with respect to separated water obtained after separation performed by the solid-liquid separation unit.
[0014] The fourth aspect of the present invention is the water treatment system according to any one of the first to the third aspects, wherein the desalination device removes bivalent salt content present in the effluent.
[0015] The fifth aspect of the present invention is the water treatment system according to any one of the first to the fourth aspects, wherein the desalination device includes a scale prevention agent supplying unit that supplies a scale prevention agent to the mixed water containing bivalent ions such as Ca ions; a first desalination device that is disposed at a downstream side of the scale prevention agent supplying unit and that separates the mixed water into reclaimed water and concentrated water in which the Ca ions have been concentrated; a crystallization tank that is disposed at a downstream side of the first desalination device and that is used in crystallizing gypsum from the concentrated water; a separating unit that separates the gypsum crystallized and concentrated water obtained from the first desalination device; and a second desalination device that is disposed at a downstream side of the separating unit and separates the concentrated water into reclaimed water and concentrated water in which the Ca ions have been concentrated.
[0016] The sixth aspect of the present invention is the water treatment system according to the fifth aspect, wherein the desalination device further includes a separating unit that separates concentrated water obtained from the second desalination device; and a third desalination device that is disposed at a downstream side of the separating unit and that separates the concentrated water into reclaimed water and concentrated water in which the Ca ions have been concentrated.
[0017] The seventh aspect of the present invention is the water treatment system according to the fifth aspect of the invention, further including an oxidation-reduction potentiometer that measures the oxidation-reduction potential of mixed water to be introduced into the first desalination device.
[0018] The eighth aspect of the present invention is the water treatment system according to the seventh aspect of the invention, wherein a value (X) of the oxidation-reduction potential of the mixed water, which is measured by the oxidation-reduction potentiometer, satisfies -0.69V<X<1.358V.
[0019] The ninth aspect of the present invention is a water treatment method including: wet-desulfurizing that includes removing sulfur oxide from boiler flue gas; dewatering that includes separating gypsum from desulfurization waste water which contains gypsum slurry and which is obtained from the wet-desulfurizing; mercury-removing that includes introducing separated water which is separated at the dewatering, and immobilizing heavy metals present in the separated water by inputting a chelating agent; solid-liquid-separating that includes performing solid-liquid separation with respect to solid content present in separated water obtained from the mercury-removing; mixing separated water obtained from the solid-liquid separation unit with effluent generated in a plant facility; desalinating that includes removing salt content from mixed water obtained at the mixing; and spray-drying that includes performing spray drying of concentrated water in which the salt content has been concentrated at the desalinating, using a part of the boiler flue gas.
[0020] The tenth aspect of the present invention is a water treatment method including: wet-desulfurizing that includes removing sulfur oxide from boiler flue gas; dewatering that includes separating gypsum from desulfurization waste water which contains gypsum slurry and which is obtained from the wet-desulfurizing; mixing separated water obtained from the dewatering with effluent generated in a plant facility; depositing that includes introducing mixed water obtained at the mixing and immobilizing heavy metals present in separated water by inputting a chelating agent; solid-liquid-separating that includes performing solid-liquid separation with respect to solid content present in mixed water obtained at the depositing; desalinating that includes removing salt content from mixed water subjected to solid-liquid separation; and spray-drying that includes performing spray drying of concentrated water in which salt content has been concentrated at the desalinating, using a part of the boiler flue gas.
[0021] The eleventh aspect of the present invention is the water treatment method according to the ninth or the tenth aspect, further including membrane-treating that includes performing treatment using a membrane having univalent selectivity with respect to separated water obtained after separation performed at the solid-liquid-separating.
[0022] The twelfth aspect of the present invention is the water treatment method according to any one of the ninth to the eleventh aspects, wherein the desalinating includes removing bivalent salt content present in the effluent.
[0023] The thirteenth aspect of the present invention is the water treatment method according to any one of the ninth to the twelfth aspects, wherein the desalinating includes scale-prevention-agent-supplying that includes supplying a scale prevention agent to mixed water containing bivalent ions such as Ca ions; first-desalinating that, at a downstream side of the scale-prevention-agent-supplying, includes separating the mixed water into reclaimed water and concentrated water in which the Ca ions have been concentrated; crystallizing that, at a downstream side of the first desalinating, includes crystallizing gypsum from the concentrated water; a separating unit that separates the gypsum crystallized and concentrated water obtained from the first-desalinating; and second-desalinating that, at a downstream side of the separating unit, includes separating the concentrated water into reclaimed water and concentrated water in which the Ca ions have been concentrated.
[0024] The fourteenth aspect of the present invention is the water treatment method according to the thirteenth aspect of the invention, wherein the desalinating further includes separating concentrated water obtained from the second-desalinating; and third-desalinating that, at a downstream side of the separating, includes separating the concentrated water into reclaimed water and concentrated water in which the Ca ions have been concentrated.
[0025] The fifteenth aspect of the present invention is the water treatment method according to the ninth aspect of the present invention, further including oxidation-reduction-potential-measuring that includes measuring the oxidation-reduction potential of mixed water to be introduced at the first-desalinating.
[0026] The sixteenth aspect of the present invention is the water treatment method according to the fifteenth aspect t of the present invention, wherein a value (X) of the oxidation-reduction potential of the mixed water, which is measured at the oxidation-reduction-potential-measuring, satisfies -0.69V<X<1.358V.
Advantageous Effects of Invention
[0027] According to the present invention, treating effluent discharged from a plant facility in an industrial waste water treatment facility becomes unnecessary, and the effluent generated in the plant can be eliminated or an amount effluent can be reduced, and further a countermeasure against mercury discharge can be implemented.
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