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US20130319663A1 - Sagd water treatment system and method - Google Patents

Sagd water treatment system and method Download PDF

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Publication number
US20130319663A1
US20130319663A1 US13/905,940 US201313905940A US2013319663A1 US 20130319663 A1 US20130319663 A1 US 20130319663A1 US 201313905940 A US201313905940 A US 201313905940A US 2013319663 A1 US2013319663 A1 US 2013319663A1
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water
boiler
fouling
fouling organics
organics
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Ian Buchanan
Mark Owen
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Husky Oil Operations Ltd
Husky Energy Inc
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Husky Energy Inc
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Publication of US20130319663A1 publication Critical patent/US20130319663A1/en
Assigned to HUSKY OIL OPERATIONS LIMITED reassignment HUSKY OIL OPERATIONS LIMITED NUNC PRO TUNC ASSIGNMENT (SEE DOCUMENT FOR DETAILS). Assignors: OWEN, MARK, BUCHANAN, IAN
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E21B43/2406—Steam assisted gravity drainage [SAGD]

Definitions

  • the present invention relates to a method and system for treating water recovered from Steam Assisted Gravity Drainage (SAGD) operations prior to supply of such water to a boiler, and more particularly to a method and system for treating produced water or recycled boiler blowdown water being supplied to a boiler wherein such boiler is part of a system for supplying steam in a SAGD operation to an underground hydrocarbon-containing formation and recovering produced water and hydrocarbons from such underground formation.
  • SAGD Steam Assisted Gravity Drainage
  • SAGD Steam-Assisted Gravity Drainage
  • water that is produced to surface with the collected oil arrives in the form of free water, suspended water, and/or water-in-oil emulsions and/or oil-in-water reverse emulsions.
  • Such water in whatever form, is typically desired to be re-utilized for producing steam and re-injected downhole as steam in a closed-loop system, because sources of additional (surface) water may be severely restricted due to legal regulations, or as a result of water being in scarce supply at surface.
  • Produced oil in a SAGD oil recovery process is typically separated from the produced water by common de-oiler or oil separation devices, to the extent possible, which may be very difficult particularly if the produced fluids contain water-in-oil or oil-in-water emulsions.
  • De-oilers are effective in removing substantial quantities of the oil from the produced water, and are typically used as a “first pass”. However, such devices work poorly for predominantly water mixtures, namely “oil-in-water” emulsions, which de-oilers have difficulty separating the oil from the water.
  • Typical De-oiler systems include a Free water knock out, followed by a skim tank, induced gas floatation and an oil removal filter.
  • such water needs to generally be further purified as it typically contains common impurities including silica, alkali, and alkali earth salts, as well as any unremoved hydrocarbons including but not limited to asphaltenes, naphthenic acids, resins, phenols, amines and aromatics (“Fouling Organics”).
  • Such contaminants have a very detrimental effect on boilers, as such compounds tend to coat or form compounds on the interior of heating tubes within such boilers, thereby reducing the ability of the boiler to heat water efficiently in such boiler tubes or lead to hot spots and tube failures.
  • impurities such as Fouling Organics present in such water in emulsion format, may be unstable, and upon heating of any emulsion and removal of the water component, remain in the boiler causing aforementioned fouling of the boiler.
  • Fouling Organics were to pass into vapour with the steam and thereby not cause boiler fouling (typically, upon heating, such Fouling Organics may alternatively form coke, depending on temperatures reached in the boiler, likewise fouling the boiler) after being injected downhole into the underground formation such asphaltenes Fouling Organics may form a separate phase which plugs not only oil-bearing rock in the underground formation, but may also detrimentally plug injector well bores and flow lines, resulting in costly repair work to the horizontal steam injector wells, and horizontal production wells, to repair plugged production lines and steam injection piping.
  • WLS warm lime softening
  • Such process involves pre-treatment of the water with heated lime to reduce hardness, alkalinity and with the addition of magnesium oxide, silica content of the boiler feedwater, with subsequent treatment with a weak or strong acid cation exchange.
  • This system of pre-treatment accomplishes several functions: water softening, alkalinity and silica reduction (i.e. removal of inorganic particulates).
  • Fouling Organics comprise organic compounds and such process is typically directed at removing inorganic compounds, the WLS process is ineffective with respect to eliminating fouling of boilers due to Fouling Organics within the boiler feed water.
  • Membranes or filters have been attempted to be used in the prior art systems to remove Fouling Organics from boiler feed water, but have generally met with poor success, becoming easily clogged and requiring frequent maintenance and cleaning, and typically are unable to effectively filter Fouling Organics from water when such Fouling Organics are present in an “oil-in-water” reverse emulsion.
  • An alternative prior art method for removing Fouling Organics from boiler feed water employs firstly passing the boiler feed water through an evaporator, where the water may be evaporated, leaving behind Fouling Organics, prior to being provided to the boiler.
  • evaporator where the water may be evaporated, leaving behind Fouling Organics, prior to being provided to the boiler.
  • drum boilers may be used (discussed below).
  • such prior art method requires the use of expensive evaporators.
  • Prior art methods also encompass the use of pre-treating the boiler feed water stream with chemicals, such as solvents, dispersant/solvents, coagulants, and demulsifier compounds, which operate to reduce total organic content (TOC).
  • chemicals such as solvents, dispersant/solvents, coagulants, and demulsifier compounds, which operate to reduce total organic content (TOC).
  • TOC total organic content
  • OTSG boilers typically accept feed water with higher dissolved salt concentrations (typical chlorides concentrations of 2000-4000 ppm and organics of 400 ppm).
  • Drum boilers are accordingly generally preferred over OTSG boilers, as there are more suppliers of drum boilers than OTSG boilers and thus a more ready supply of such boilers, and even more importantly drum boilers typically generate steam quality of 99% or greater, and thus do not require expensive steam separators to separate steam from boiler blowdown as is necessary with OTSG boilers.
  • drum boilers are more susceptible to fouling, and for such reason cannot be used where Fouling Organics are present in boiler feedwater.
  • such invention comprises a method for treating boiler feed water containing Fouling Organics in a SAGD oil recovery process, wherein said water containing Fouling Organics is derived from SAGD oil recovery methods performed on an underground hydrocarbon-containing formation, comprising the steps of:
  • the water that is injected with the oxidizing agent may be from a produced water stream having been passed through an oil-water separator as an initial means of removing a portion of oil from within said water.
  • the water may be from a recycled boiler blowdown stream.
  • the water may be a combination of water from a produced water stream and a recycled boiler blowdown stream.
  • Oxidizing agents which are adapted to accomplish one or more of the above steps and thereby permit Fouling Organics to be separated by a filter and/or cause less fouling from such boiler feed water are known to those skilled in the art.
  • such oxidizing agent includes but are not limited to oxygen, air, ozone, alkali permanganate, chlorine dioxide, and hydrogen peroxide.
  • the oxidizing agent is oxygen contained in air.
  • the step of filtering comprises passing said water, after said air is injected into the boiler feedwater and prior to providing said water to said boiler, through a filter or membrane to filter Fouling Organics therefrom.
  • the water is passed through a semi-porous membrane.
  • Oxidizing agents in the feed water may negatively affect the boiler piping and may promote corrosion of such boiler components and piping.
  • the water is subject to deoxidation before being passed into said boiler, so as to thereby substantially remove such. Deoxidation may be achieved by methods known to those skilled in the art.
  • the water is subject to deaeration and/or deoxygenation subsequent to said oxidizing agent injection step.
  • deoxygenation and deaeration may take the form of any of the known prior art methods and apparatus commonly presently used and well known to persons of skill in the art, including addition of chemical oxygen scavengers (including without limitation hydrazine and sodium bisulfite) to the boiler feed line, or alternatively introducing pressure spray type or tray type deaerators in the boiler feed water supply lines to eliminate oxygen and air in the water prior to the supply to the boiler.
  • a system for treating water containing Fouling Organics in a SAGD oil recovery process.
  • water is recovered from within an underground hydrocarbon-containing formation during SAGD oil recovery methods performed on said underground formation, and re-injected as steam into said formation for heating hydrocarbons in said formation, such system comprising:
  • oxidizing agent injection means for injecting an oxidizing agent into a water stream obtained from said hydrocarbon-containing formation, which water stream contains Fouling Organics;
  • filter means for separating oxidized Fouling Organics and/or filter-separable compounds formed as a result of reaction between said oxidizing agent and said Fouling Organics, from said water stream;
  • boiler means for heating said water stream so as to form steam
  • injection means for re-injecting said steam into said hydrocarbon-containing formation.
  • the oxidizing agent injection means may comprise air injection means so as to permit injection of air into said water stream prior to said water stream passing through said filter means and subsequently to said boiler means.
  • the filter means preferably comprises at least one semi-permeable membrane adapted to separate oxidized Fouling Organics and/or filter-separable compounds formed as a result of reaction between said oxidizing agent and said Fouling Organics, from said water stream.
  • the aforesaid system very preferably possesses a de-oiler in the water stream, positioned at a location upstream from the filter means, and preferably upstream from both said oxidizing agent injection means and said filter means.
  • a de-oiler may comprise any one of the known de-oiler devices to persons of skill in the art, and may include or comprise weir-separator means for separating hydrocarbons from said water stream.
  • the system is further preferentially provided with deoxidation means for removing oxidation agents from said water subsequent to injection of such oxidation agent and prior to said water being provided to said boiler.
  • deoxidation means may, as noted previously, take the form of any of the known prior art apparatus commonly presently used and well known to persons of skill in the art.
  • deoxidation means will comprise deoxygenation and/or deaeration means for removing oxygen from said water subsequent to injection of air and prior to said water being provided to said boiler.
  • deoxygenation and deaeration means may, as noted previously, take the form of any of the known prior art apparatus commonly presently used and well known to persons of skill in the art, including chemical oxygen scavengers being provided in the boiler feed line, or alternatively pressure spray type or tray type deaerators being provided in the boiler feed water supply lines, to eliminate oxygen and air in the water prior to the supply to the boiler.
  • the aforesaid system may further possess, in the case of where an OTSG boiler is used, a boiler blowdown recycle means, namely provision for directing water exiting the boiler which has not been turned to steam, back to the boiler feedwater supply line, and preferably at a point in the supply line prior to the point in such supply line where the oxidizing agent is injected.
  • said recycled boiler water stream is thereby permitted to be re-exposed to said oxidizing agent.
  • the system is adapted for separately treating the recycled boiler water stream, wherein Fouling Organics could be more concentrated.
  • the oxidizing agent injection means and filter means are located downstream from said recycle means, whereby said recycled boiler water stream is injected with said oxidizing agent and filtered by said filter means to be subsequently combined with a produced water stream prior to entering said boiler means.
  • FIG. 1 shows a schematic drawing of a prior art system for de-oiling and treating boiler feedwater from a SAGD oil recovery operation, using a lime softener and weak acid cation exchange for removing inorganic materials from boiler feedwater, which prior art method typically has little effect in overcoming fouling caused by Fouling Organics in an OTSG boiler;
  • FIG. 2 is another schematic drawing of another prior art system for de-oiling and treating boiler feedwater from a SAGD oil recovery operation, which uses an evaporator and which while effective in removing Fouling Organics from boiler feedwater is expensive in terms of capital cost of the required evaporator, and effectively transfers the fouling problems caused by Fouling Organics from the boiler to the evaporator;
  • FIGS. 3 a and 3 b are schematic illustrations of the apparatus and method according to embodiments of the present invention, employing injection of an oxidizing agent, and separation via a porous thin-film membrane, prior to supply of such produced and/or recycled water to a boiler;
  • FIGS. 4 a , 4 b , 4 c , and 4 d are schematic illustrations of the apparatus and method according to embodiments of the present invention, employing injection of oxidizing agent and separation via a porous thin-film membrane, prior to supply of such produced and/or recycled water to an OTSG boiler, further using de-oxidation means to de-oxidize the feed water prior to the OTSG boiler;
  • FIG. 5 is a schematic illustration of the apparatus and method according to embodiments of the present invention, employing injection of oxidizing agent and separation via a porous thin-film membrane, prior to supply of such produced water to a drum boiler, further using de-oxidation means to de-oxidize the feed water prior to being supplied to the drum boiler, and which does not require steam separator means;
  • FIG. 6 is a schematic illustration of the apparatus and method according to embodiments of the present invention, adapted for use in a SAGD boiler feedwater system which uses an evaporator;
  • FIG. 7 is a photographic image comparison of boiler blowdown water sampled from the field before oxidation treatment by aeration (right) and after treatment (left);
  • FIG. 8 is a graphical representation of the permeate flux and fouling propensity profiles for oxidized (light-coloured, circle, data points) and non-oxidized (dark-coloured, diamond, data points) blower blowdown water samples filtered through Membrane 1.
  • FIG. 1 Prior art
  • produced water 30 from a hydrocarbon formation 60 in a SAGD oil recovery operation may have the following characteristics, namely:
  • feedwater 30 for most OTSG boilers 50 is typically required (depending on boiler throughput) to meet or exceed the following specifications, in order to substantially reduce boiler 50 fouling, namely:
  • FIG. 1 shows a method and apparatus 10 of the prior art for treating boiler feedwater in SAGD oil recovery operations, having a produced water stream 30 which emanates from an underground formation 60 from which oil is being recovered using steam assisted gravity drainage (SAGD) methods which employ injection of heated steam typically under pressures in the 8400 to 11,200 kPa range into the hydrocarbon formation 60 to mobilize oil in such formation 60 .
  • SAGD steam assisted gravity drainage
  • produced water stream 30 coming from a hydrocarbon formation 60 undergoing SAGD oil recovery methods is first passed through a de-oiler 34 , where such produced water stream 30 has separated therefrom, to the extent possible, oil contained in such produced water stream 30 .
  • De-oilers(s) 34 may take any form as provided in the prior art, such as a combination of oil-water separators which employ weirs to separate oil from water, induced gas flotation units where free oil floats to the surface and is removed, and oil removal filters where the free oil agglomerates on the surface of oleophilic surfaces.
  • An appropriate de-oiling system located upstream of the boiler is generally required to reduce the oil concentration to ⁇ 10 mg/L.
  • de-oilers 34 are capable of purifying the water to ⁇ 10 mg/L, and some oil typically in the form of oil-in-water emulsions, as well as Fouling Organics present in such oil and/or oil-water emulsion, remains in such produced water stream 30 , even after de-oiling.
  • produced water stream 30 is directed to a hot or warm lime “softener” (HLS/WLS) 36 , whose primary function is for silica removal and reduction of hardness by elimination of calcium carbonate concentrations typically found within such feedwater stream 30 .
  • HLS/WLS hot or warm lime “softener”
  • a HLS or WLS system 36 reduces the silica and in certain cases the Total Hardness (TH) concentrations of calcium carbonate.
  • Strongly acidic cation units (SAC) or weak acid cation unit (S) 38 operating in the sodium form reduce the Total Hardness (TH) to ⁇ 0.5 mg/L as CaCO 3 .
  • Boiler blowdown 70 may be recycled via recycle line 90 back into the feedwater stream 30 for re-use, or may simply need to be disposed of. Sometimes disposal may be by injection deep underground, which may not be permitted under certain regulations governing water treatment.
  • lime, magnesium oxide and a flocculent are added at a pH of 9.5 to 9.8.
  • the lime causes a reduction in the temporary hardness i.e. the calcium and magnesium combined with the bicarbonate alkalinity and the magnesium oxide facilitates the removal of the silica.
  • the flocculent aids the floc formation so that a sludge that settles more readily is formed, and can be removed (possibly by filtration) from the produced water stream 30 .
  • the lime softening system of FIG. 1 and the de-oilers employed does not remove all oil or Fouling Organics.
  • Filters may further be employed, but due to Fouling Organics usually being present in water emulsions, filtering or membrane separation is difficult, and typically filters or membranes become clogged thereby reducing the flow rate of feedwater stream 30 to boiler 50 . If filters are not used, boiler fouling results.
  • FIG. 2 shows another prior art boiler feedwater treatment system 15 .
  • produced water stream 30 coming from formation 60 is passed through de-oiler 34 which operates as described above, and thereafter passed into an evaporator unit 100 , where typically vacuum is applied to cause the water to evaporate, without impurities, and such stream 30 it is later subjected to recompression/condensation, thereby forming a pure distillate which can then be passed to an OTSG boiler, or more preferably a drum boiler 51 .
  • Stream 30 is turned to steam 41 of 98% quality, which is then injected under pressure into formation 60 .
  • the remaining 2% boiler blowdown 70 may be disposed of, or preferentially may be re-injected by means of recycle line 90 back into feedwater stream 30 , as shown in FIG. 2 .
  • evaporator units 100 consume high amounts of energy, and are relatively expensive to fabricate. Accordingly, another method and system is needed to prevent evaporator fouling.
  • a method and apparatus that reduces clogging problems in SAGD feed water systems.
  • the reduction of clogging problems further reduces the incidence of cooler and/or evaporator fouling in SAGD feed water systems that include such units and ultimately reduce the incidence of boiler fouling.
  • the described method and apparatus of the present invention avoids use of expensive evaporators of the prior art, and further not only reduces clogging problems but further reduces the incidence of boiler fouling.
  • produced water stream 30 is first directed to a de-oiler 34 , as described earlier.
  • Make up water 45 and optionally according to some embodiments recycled boiler blowdown water 70 , may further be added to feed stream 30 , and such stream thereafter flows to an oxidizing injection agent region 77 , where an oxidizing agent such as described earlier is injected into the feed stream 30 .
  • deoxidizing means 78 may further be provided downstream, as shown in the exemplary embodiments depicted in FIGS. 4( a - d ) & 5 , to avoid oxidizing agent in the feed stream passing into the boiler 50 and corroding pressure and heating tubing therein.
  • the deoxidizer is a deaeration and/or deoxygenation means such as described earlier.
  • a HLS/WLS system 95 as described above comprising a lime and magnesium softener 36 and a weak acid cation system 38 as described above, may further be provided as part of such HLS/WLS system 95 to remove quantities of silica and calcium carbonate from the boiler feed water.
  • the HLS/WLS system 95 typically includes an afterfilter that traps carryover of micron sized particles formed in the HLS/WLS system. The afterfilter, while sufficient to trap particles and/or flocs carried over from the HLS/WLS system, fails to filter out Fouling Organics which therefore would pass through.
  • a filter membrane 79 preferably but not limited to a porous thin-film membrane is provided in the boiler feedwater stream to remove the Fouling Organics which have chemically reacted with the oxidizing agent.
  • the filter membrane 79 is positioned downstream from oxidizing agent injection region 77 to specifically filter Fouling Organics.
  • the Fouling Organics will generally be nano-sized and accordingly in certain embodiments the filter membrane 79 will be a nano-filter.
  • the filter membrane 79 is a nano-sized porous thin-film membrane.
  • the filter membrane 79 is positioned downstream of oxidizing agent injection region 77 , to specifically filter Fouling Organics prior to the HLS/WLS system 95 in the boiler feedwater stream.
  • the HLS/WLS system will typically still require an afterfilter as described above.
  • the filter membrane 79 may be positioned downstream of both the oxidizing agent injection region 77 and the HLS/WLS system 95 to effectively remove any sludge such as silica which has been caused to be made filterable due to the addition of chemicals added by the HLS/WLS system 95 (lime, magnesium oxide, and flocculating agent) as well as the Fouling Organics which have chemically reacted with the oxidizing agent in the oxidizing agent injection region 77 .
  • the filter membrane 79 may replace the need for an afterfilter in the HLS/WLS system 95 .
  • additional filter means may further be added immediately downstream of oxidizing agent injection region 77 to specifically filter Fouling Organics, whereby the filter means may be removed for cleaning with no interruption in the boiler feedwater flow, assuming filter membrane 79 is not removed at the same time for cleaning.
  • feed streams 30 , 45 , and 70 flow to OTSG boiler 50 , 80% of which is converted to steam, and said steam is separated by means of conventional steam separator 42 and provided to underground formation 60 .
  • the remaining ⁇ 20% boiler blowdown 70 is typically recycled via recycle line 90 back into feed streams 30 , and 45 , as shown in FIG. 3 a.
  • FIGS. 4 a , 4 b , and 4 c show alternative embodiments of the boiler feed water system 24 of the present invention, which possess identical components to the system depicted in FIG. 3 a but in which deoxidizer means 78 are further provided, downstream of said oxidizing agent injection region 77 , so as to remove oxidizing agent from within the feed stream 30 to avoid undesirable oxidation of pressure feed and heating tubing in boiler 50 .
  • the system 24 may be specifically adapted for injection of oxygen or air as the oxidizing agent in region 77 , in such embodiments the deoxidizing means 78 is a de-oxygenator and/or de-aerator means.
  • the sequence of the components through which the feed stream is fed may be varied to some degree.
  • the process sequence of the HLS/WLS system 95 may be varied so long as the filter membrane 79 , followed downstream by the de-oxidizing means 78 , remain downstream of the oxidizing agent injection region 77 .
  • FIG. 5 shows yet another embodiment of a boiler feed water system 28 of the present invention, similar to the system of FIGS. 4 a , 4 b , and 4 c in that such system further provides for a de-oxidizing means 78 .
  • a chemical oxygen scavenger may be used or alternatively a de-aerator and/or de-oxygenator 78 may be provided.
  • deoxidizing means known to those skilled in the art may be used to deoxidize the feed stream prior to entry into the boiler.
  • FIG. 5 shows yet another embodiment of a boiler feed water system 28 of the present invention, similar to the system of FIGS. 4 a , 4 b , and 4 c in that such system further provides for a de-oxidizing means 78 .
  • a chemical oxygen scavenger may be used or alternatively a de-aerator and/or de-oxygenator 78 may be provided.
  • deoxidizing means known to those skilled in the art may be used to deoxidize the feed stream prior to entry
  • a drum boiler 51 is provided, which can operate in such a system due to the substantial reduction of Fouling Organics due to the injection of oxidizing agent 77 and the filter 79 within feed stream 30 , and which thereby, due to the efficiency of the drum boiler in being able to provide 98% quality steam to formation 60 , thereby dispenses with the need to include a steam separator 42 .
  • the remaining ⁇ 2% boiler blowdown 70 is typically recycled via recycle line 90 back into feed stream 30 , as shown in FIG. 5 , or alternatively may be sent to disposal.
  • the recycled boiler blowdown 70 will contain the greatest levels of Fouling Organics and, accordingly, can be a significant source of Fouling Organics. Reducing the concentration of Fouling Organics in the boiler blowdown to an acceptable level before recycling the water may, therefore, be advantageous. Accordingly, as shown in FIGS. 3 b and 4 d , injection of an oxidizing agent, such as oxygen or air, may occur at the boiler blowdown separator outlet 42 .
  • an oxidizing agent such as oxygen or air
  • the boiler blowdown stream 70 is directed to an oxidizing injection agent region 77 , where an oxidizing agent such as described earlier is injected into the boiler blowdown stream 70 . Thereafter, feed stream 70 from the oxidizing injection agent region 77 is fed into a filter membrane 79 . The treated feed stream 70 from the filter membrane 79 can then be mixed at the inlet of the HLS/WLS system 95 with de-oiled feed stream 30 and make up water 45 . As shown in FIG. 4 d , in such embodiments a de-oxidizer 78 may further be provided downstream of the HLS/WLS system 95 .
  • BBD water was sampled from the Tucker facility in Cold Lake, Alberta. Oxidized BBD water was prepared by bubbling supplied industrial air into the sample until the sample turned dark brown to black and transparency was virtually eliminated. The aeration time was 15 minutes for 8 liters of BBD water.
  • FIG. 7 a comparison of BBD water after air bubbling treatment is shown on the left as compared to a sample of the untreated BBD water on the right.
  • the oxidation treated BBD water sample 250 mL
  • the untreated BBD water sample full flask
  • the membrane filtration tests were conducted using a nanofiltration membrane of molecular weight cut-off (MWCO) of approximately 300 Da. Tests were also conducted using a higher molecular weight cut-off nanofiltration membrane of MWCO approximately 1000 Da. Both membranes exhibit relatively low salt (NaCl) rejection, and are primarily designed for removal of divalent cations.
  • MWCO molecular weight cut-off
  • Both membranes exhibit relatively low salt (NaCl) rejection, and are primarily designed for removal of divalent cations.
  • NaCl salt
  • the permeate flux through the membrane was recorded as a function of time during the experiments.
  • the typical experimental protocol included an initial membrane-conditioning run with deionized water for 2 hours, followed by switching to the un-conditioned feedwater.
  • Flux and fouling propensity profiles were conducted at the conditions described above at a constant pressure.
  • Feedwater was initially recirculated through the membrane at the native pH for one hour to study the fouling behavior at the native pH of the feedwater.
  • the pH of the feed was decreased to 8.5 by adding HCl to induce accelerated fouling of the membrane.
  • the flux behaviour of the feedwater at the lower pH was monitored for one hour.
  • the pH of the feed was adjusted back to the original pH of ⁇ 10.6 by adding NaOH, and flux behaviour monitored at the readjusted pH for another hour. Permeate samples were collected at regular intervals to further monitor the rejection of TOC and colour.
  • BBD water samples Preliminary analysis of non-oxidized and oxidized BBD water samples were conducted.
  • the BBD water was sampled from the Tucker facility in Cold Lake, Alberta, treated with the oxidation treatment as described above, and analyzed to determine the presence of organic and inorganic constituents. The samples were also examined to determine any additional observable changes resulting from oxidation of the BBD water.
  • Tables 1 and 2 show the effect of oxidation on solution pH, conductivity, TOC, DOC, colour, and the concentration of select ions.
  • colour increased from 9000 CU to 9600 CU with no significant change in TOC and DOC. This indicates that most of the Fouling Organics were still present in the water after oxidation treatment.
  • the colour change could be related to chemical reaction of asphaltenes, naphthenic acids, resins, phenols, amines, aromatics, etc.
  • Table 2 shows the inorganic nature of the oxidized and non oxidized boiler blowdown water.
  • membrane filtration performance profiles were conducted with non-oxidized and air-oxidized boiler blowdown water (BBD) samples that were freshly sampled from the Tucker facility.
  • BBD boiler blowdown water
  • the samples were treated through two commercial membranes with MWCO (molecular weight cut-off) at around 1000 Da (Membrane 1) and 300 Da (Membrane 2).
  • the tests were operated in cross flow mode at 50° C. with the initial permeate flux at 18 GFD (Gallons per square foot of membrane per day), volumetric feed flow rate at 1.0 GPM and 65 psi and 35 psi operational pressure for Membranes 1 and 2, respectively.
  • Permeate flux and fouling propensity was observed using the methodology described above. Specifically, as shown from FIG. 8 , flux through Membrane 1 was monitored over time under the operating conditions above.
  • the filtration was initially operated at the native pH of the boiler blowdown water. An applied pressure of 65 psi was required to reach the target initial flux of 18 GFD. As shown in FIG. 8 , the membrane flux for Membrane 1 was stable initially with flux through Membrane 1 at around 18 GFD. There was no measurable change in flux during this period. Following this, the pH was adjusted to 8.5 by adding HCl to induce accelerated fouling. Acidification to pH 8.5 resulted in a significant flux drop to occur with both the oxidized and non-oxidized samples, however, the oxidized sample had almost twice the membrane flux than the non-oxidized sample during this time. In light of the foregoing, this indicates that there is less membrane fouling caused by the oxidized sample compared to the non-oxidized sample. Oxidation, therefore, was shown to improve flux decline by approximately 30% during the accelerated fouling portion of the filtration test.
  • the most dramatic performance parameter was the colour removal, which was above 90% in each case of the oxidized sample.
  • the coloured components typically contain, but not limited to, amines, phenols, aromatic rings, carboxylic acids and asphaltenes. High rejection of colour indicates that the membrane is predominantly retaining these components.
  • the TOC and colour rejection performance between the non-oxidized and oxidized samples showed measurable difference. Filtration of the oxidized BBD resulted in higher TOC and colour rejection compared to the non-oxidized BBD, despite the non-oxidized sample started lighter in colour. This suggests that oxidation treatment of the BBD sample results in improved removal of Fouling Organics and/or other filterable compounds from the water.
  • the characteristics of the Fouling Organics is changed, which thereby permits improved membrane separation of such Fouling Organics.
  • the molecular size and/or weight of the organic matter may have been caused to increase or to floc or chelate with other inorganic impurities, or the solubility of the Fouling Organics may have been caused to be lowered.

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  • Fluid Mechanics (AREA)
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  • Geochemistry & Mineralogy (AREA)
  • Separation Using Semi-Permeable Membranes (AREA)
  • Physical Water Treatments (AREA)
US13/905,940 2012-05-30 2013-05-30 Sagd water treatment system and method Abandoned US20130319663A1 (en)

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US9284830B2 (en) 2012-03-22 2016-03-15 E I Du Pont De Nemours And Company Method for recovering hydrocarbon fluids using a hydraulic fracturing process
US10071928B2 (en) * 2013-11-06 2018-09-11 Fluor Technologies Corporation Systems and methods for de-oiling and total organic carbon reduction in produced water
US10131561B2 (en) 2012-09-13 2018-11-20 Bl Technologies, Inc. Treatment of produced water concentrate
US10132145B2 (en) * 2012-09-13 2018-11-20 Bl Technologies, Inc. Produced water treatment and solids precipitation from thermal treatment blowdown
US20190016611A1 (en) * 2017-07-12 2019-01-17 Conocophillips Company Processes for removing oil from separated water streams
US20190153833A1 (en) * 2017-11-17 2019-05-23 Husky Oil Operations Limited Thermal hydrocarbon recovery method
US11485649B2 (en) 2015-09-03 2022-11-01 Questor Technology Inc. System for reducing produced water disposal volumes utilizing waste heat
US11655168B2 (en) 2020-05-22 2023-05-23 Halliburton Energy Services, Inc. Methods for wastewater treatment using alcohol ethoxylate surfactants

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WO2015184521A1 (fr) * 2014-06-03 2015-12-10 Husky Oil Operations Limited Système et procédé de traitement d'eau par drainage gravitaire au moyen de vapeur
CN107792571A (zh) * 2017-10-09 2018-03-13 行愿环保科技有限公司 高品质餐厨油脂收集装置
CN113415928A (zh) * 2021-06-29 2021-09-21 福建安冠环境科技有限公司 低浓度石油污染应急处理一体化装置

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US9284830B2 (en) 2012-03-22 2016-03-15 E I Du Pont De Nemours And Company Method for recovering hydrocarbon fluids using a hydraulic fracturing process
US10131561B2 (en) 2012-09-13 2018-11-20 Bl Technologies, Inc. Treatment of produced water concentrate
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US11485649B2 (en) 2015-09-03 2022-11-01 Questor Technology Inc. System for reducing produced water disposal volumes utilizing waste heat
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US10753188B2 (en) * 2017-11-17 2020-08-25 Husky Oil Operations Limited Thermal hydrocarbon recovery method using circulation of surface-heated mixture of liquid hydrocarbon and water
US11655168B2 (en) 2020-05-22 2023-05-23 Halliburton Energy Services, Inc. Methods for wastewater treatment using alcohol ethoxylate surfactants

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