SAGD WATER TREATMENT SYSTEM AND METHOD

A method and system for treating a water stream which contains Fouling Organics, where the water stream is recovered from an underground hydrocarbon-containing formation during SAGD oil recovery operations conducted on said formation. The method comprises injecting an oxidizing agent, preferably air, into the water stream when first recovered from the underground formation, and using a porous membrane to separate oxidized Fouling Organics and/or filter separable compounds formed due to injection of the oxidizing agent into the water stream, prior to transferring the water stream to a boiler for re-heating the water stream and turning same to steam for re-injection into said formation.

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Description
FIELD OF THE INVENTION

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.

BACKGROUND OF THE INVENTION

In Steam-Assisted Gravity Drainage (SAGD) oil recovery operations, 98% or greater quality steam is typically injected into a hydrocarbon-containing underground formation to heat viscous oil in the formation and render it mobile, so that it flows downwardly through the formation to horizontal collector wells where it is collected and thereafter pumped (produced) to surface.

Typically, 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.

Thereafter, as regards the remaining produced water used as boiler feed water, 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.

In addition, 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.

Even if 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.

Thus it is extremely advantageous in closed-loop SAGD oil recovery operations to remove Fouling Organics from boiler feed water supply lines.

There are a number of prior art methods for purifying boiler feedwater where such feedwater is used in SAGD operations and is desired to be heated to steam and re-injected into the formation to heat and thereby reduce the viscosity of oil in such underground hydrocarbon formation to aid in recovery of such oil from the formation.

One prior art method of boiler feed water treatment is the commonly employed “warm lime softening”, or “WLS”. 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).

Disadvantageously, however, as 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. In such instance, particularly if used in combination with the warm or hot lime process, drum boilers may be used (discussed below). Disadvantageously, however, 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). Such chemical treatment processes typically require continuous treatment of the boiler inlet feed stream with such chemicals, and such becomes expensive.

Other prior art methods and systems for removing Fouling Organics from boiler feed water streams include:

    • HERO1, an acronym for high efficiency reverse osmosis filtration system offered by GE Water Systems, a division of General Electric Company, which uses cation exchange to reduce average hardness, degasification, and increased pH, followed by reverse osmosis (RO) to remove dissolved solids and other contaminants;
    • vapour compression distillation (“VCD”); and
    • multiple effect distillation (MED).

Each of the foregoing prior art methods and systems adds substantial expense and complexity to the feed water treatment system, and are unsatisfactory for such reasons.

Typically, the boilers used in such SAGD oil recovery operations are a particular type of boiler known in the industry as a “once-through steam generation” (OTSG) type boilers. OTSG boilers differ from conventional boilers such as drum boilers, in that OTSG type boilers typically accept feed water with higher dissolved salt concentrations (typical chlorides concentrations of 2000-4000 ppm and organics of 400 ppm).

Since SAGD operations typically require at least 98% quality steam for maximum heating of an underground formation, and because OTSG's typically only produce steam quality in the range of 70-80%, steam separators are required at the OTSG boiler outlet to separate the steam and divert the boiler “blowdown” (i.e. the 20-30% of the OTSG feedwater not converted to steam) to disposal, or back to the boiler inlet. If such water is disposed, the SAGD water utilization system is not a closed loop system, and water is being wasted. Alternatively, if such boiler blowdown water is recycled back to the boiler inlet, typically this results in concentrating the impurities and Fouling Organics 1Registered US trademark 3423991 of Debasish Mukhopadhyay, licensed for use by General Electric Company in the boiler feedwater, eventually resulting in boiler fouling due to the concentration of impurities.

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. However, as noted above, drum boilers are more susceptible to fouling, and for such reason cannot be used where Fouling Organics are present in boiler feedwater.

SUMMARY OF THE INVENTION

Accordingly, a real need exists for an effective and low cost process and apparatus to reduce Fouling Organics present in boiler feedwater and thereby avoid fouling of boilers used in SAGD oil recovery operations.

It is thus an object of the present invention to provide an effective and relatively low cost method and system which reduces Fouling Organics present in boiler feedwater, and which allows further cost savings by increasing blow-down recycle volumes and reducing disposal quantities as the stream will have a lower fouling tendency.

Accordingly, in a broad aspect of the present invention, 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:

(i) obtaining water from an underground hydrocarbon-containing formation during SAGD oil recovery methods performed on said underground formation, wherein said water contains Fouling Organics, said water having been passed through an oil-water separator as an initial means of removing a portion of oil from within said water, said water continuing to have Fouling Organics remaining therein;

(ii) Injecting an oxidizing agent into said water;

(iii) Filtering said Fouling Organics from said water to separate said Fouling Organics and thereby reduce the concentration of Fouling Organics in said water;

(iv) subsequently supplying said water having a reduced concentration of Fouling Organics therein to a boiler and turning said water into steam; and

(v) injecting said water, now in the form of steam, into said hydrocarbon-containing formation during said SAGD oil recovery operation.

According to some embodiments, 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. In other embodiments, the water may be from a recycled boiler blowdown stream. In further embodiments, the water may be a combination of water from a produced water stream and a recycled boiler blowdown stream.

Without being limited by theory, it is theorized that injection of the oxidizing agent into the boiler feed water containing Fouling Organics, causes said oxidizing agent to chemically react with said Fouling Organics present in said water to:

    • (a) change the surface structure of said Fouling Organics to have less affinity to a membrane surface so as to thereby result in less fouling of said membrane surface;
    • (b) cause said Fouling Organics to agglomerate or polymerize to an increased molecular size and/or molecular weight so as to thereby permit being filtered out of said water;
    • (c) form a compound of lower solubility in said water than said Fouling Organics;
    • (d) cause said Fouling Organics to form flocs or chelate with other inorganic impurities in said water; or
    • (e) change the surface functional groups to be amphipathic so as to cause foaming.

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. According to some embodiments, such oxidizing agent includes but are not limited to oxygen, air, ozone, alkali permanganate, chlorine dioxide, and hydrogen peroxide. In a further preferred embodiment, the oxidizing agent is oxygen contained in air.

In a further refinement of the above method, 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. In a further preferred embodiment, 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. To avoid such negative effects, subsequent to said oxidizing agent injection step 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.

In certain embodiments wherein oxygen or air is used as the oxidizing agent, the water is subject to deaeration and/or deoxygenation subsequent to said oxidizing agent injection step. Such 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.

In another embodiment of the present invention a system is provided for treating water containing Fouling Organics in a SAGD oil recovery process. In such system 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:

(i) 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;

(ii) 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;

(iii) boiler means for heating said water stream so as to form steam, and

(iv) injection means for re-injecting said steam into said hydrocarbon-containing formation.

Similar to the method of the present invention, in the above system 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.

To reduce the oil and Fouling Organics present, 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. Such 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.

Again, 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. Such 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.

As described herein, in embodiments using oxygen or air as the oxidizing agent, 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. Such 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. In such embodiments, said recycled boiler water stream is thereby permitted to be re-exposed to said oxidizing agent.

In alternative embodiments, the system is adapted for separately treating the recycled boiler water stream, wherein Fouling Organics could be more concentrated. In such embodiments, 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.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings illustrate one or more exemplary embodiments of the present invention and are not to be construed as limiting the invention to these depicted embodiments:

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. 3a and 3b 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. 4a, 4b, 4c, and 4d 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.

 DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS

Reference is to be had to FIG. 1 (prior art).

Typically, produced water 30 from a hydrocarbon formation 60 in a SAGD oil recovery operation may have the following characteristics, namely:

Total Dissolved Solids 8000-10000 ppm Silica 300-400 ppm Hardness (as CaCO3) <50 ppm Oil (Measured as Total Petroleum Hydrocarbon) 20-250+ ppm

However, 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:

Total Dissolved Solids 1000-5000 ppm Silica <50 ppm Hardness (as CaCO3) <1 ppm Oil (Measured as Total Petroleum <5 ppm (i.e. <10 mg/l) Hydrocarbon)

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.

As may be seen from FIG. 1, 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.

Not all 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.

Thereafter in the lime softener prior art process shown in FIG. 1, 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.

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 CaCO3.

Thereafter, the OTSG boiler 50 generates steam at 80% quality, and a steam separator 42 removes the 20% water phase (“boiler blowdown” 70) from the steam 40, which steam 40 is then sent to the underground reservoir/formation 60 as 100% quality. 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.

In the lime softening process of FIG. 1, 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.

Notably, however, the lime softening system of FIG. 1 and the de-oilers employed, does not remove all oil or Fouling Organics. Filters (not shown) 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.

In order to overcome the expense and filter clogging problems with the HLS/WLS system 10 of FIG. 1, FIG. 2 shows another prior art boiler feedwater treatment system 15.

In the prior art system 15 of FIG. 2 (which system 15 may also employ a brine injection system (not shown) similar to the HLS/WLS system 10 shown in FIG. 1), 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.

Disadvantageously, however, 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.

According to embodiments of the present invention, a method and apparatus is described that reduces clogging problems in SAGD feed water systems. In certain embodiments, 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. In other embodiments, 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.

As may be seen from FIG. 3a, 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. According to some embodiments, 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. In certain embodiments, where air or oxygen is used as the oxidizing agent, the deoxidizer is a deaeration and/or deoxygenation means such as described earlier.

Injection of the oxidizing agent into the feed stream 30 exposes the Fouling Organics contained therein to chemically react with the oxidizing agent. This chemical reaction changes the character of the Fouling Organics. According to embodiments of the present invention, change in the character of the Fouling Organics resulting from chemical reaction with the oxidzing agent can lead to:

    • a. a change in the surface structure of the Fouling Organics resulting in less affinity of the Fouling Organics to the membrane surface thereby causing less fouling;
    • b. lower solubility of Fouling Organics in said water;
    • c. agglomeration or polymerization of Fouling Organics to an increased molecular size and/or molecular weight;
    • d. flocculation or chelation reaction with other inorganic impurities to form flocs or chelates; and/or
    • e. a surface functional change to an amphipathic (both hydrophobic and hydrophilic groups) character which can create foaming.

Thereafter, and again referring to FIG. 3a, 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. In such systems, 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. In preferred embodiments, the filter membrane 79 is a nano-sized porous thin-film membrane.

In some embodiments, as shown in FIG. 3a, 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. In such embodiments, the HLS/WLS system will typically still require an afterfilter as described above. In other embodiments (for example, FIGS. 4a and 4c), 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. In such embodiments, the filter membrane 79 may replace the need for an afterfilter in the HLS/WLS system 95.

In further embodiments, additional filter means (not shown) 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.

Thereafter, 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. 3a.

FIGS. 4a, 4b, and 4c show alternative embodiments of the boiler feed water system 24 of the present invention, which possess identical components to the system depicted in FIG. 3a 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. In certain embodiments, 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.

As illustrated in the exemplary embodiments shown in FIGS. 4a, 4b, and 4c, the sequence of the components through which the feed stream is fed may be varied to some degree. For example, 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. 4a, 4b, and 4c in that such system further provides for a de-oxidizing means 78. As described, in certain embodiments in which the oxidizing agent is adapted particularly for use of oxygen and/or air as the oxidizing agent, a chemical oxygen scavenger may be used or alternatively a de-aerator and/or de-oxygenator 78 may be provided. Where oxygen or air is not used as the oxidizing agent, deoxidizing means known to those skilled in the art may be used to deoxidize the feed stream prior to entry into the boiler. Advantageously, in the embodiment shown in FIG. 5, 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.

It is further contemplated, as will be apparent to those skilled in the art, that the method and apparatus described herein for reducing Fouling Organics by the injection of oxidizing agent 77 and the filter 79 within feed stream 30, can be adapted to other SAGD feed water systems. In this way, fouling can be reduced in not only the boiler 50, 51 but also in other processing units within the feed stream. As illustrated in FIG. 6 for example, such processing units can include, but are not limited, to coolers and evaporators 100.

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. 3b and 4d, injection of an oxidizing agent, such as oxygen or air, may occur at the boiler blowdown separator outlet 42.

In such embodiments, 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. 4d, in such embodiments a de-oxidizer 78 may further be provided downstream of the HLS/WLS system 95.

EXAMPLES

The effect of an oxidation treatment on SAGD produced water was evaluated and the efficacy of combining the oxidation treatment with membrane filtration was studied. The efficacy of a combined process of oxidation treatment and filtration was studied using a model process of aerating SAGD boiler blowdown (BBD) water followed by membrane filtration.

Materials and Methods: Oxidization Treatment of BBD Water

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.

Referring to 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. As shown, the oxidation treated BBD water sample (250 mL) is markedly darker and non-transparent as a result of the treatment, compared to the untreated BBD water sample (full flask) which is tea-coloured and transparent. This observed change in the BBD water confirms the occurrence of the Fouling Organics undergoing a chemical reaction as a result of the oxidation.

Standard Measurements

Standard procedures for examining water (A. D. Eaton, M. A. H. Franson (Eds.), Standard Methods for the Examination of Water and Wastewater, 21st Ed. American Public Health Association (APHA), (2005)) were used throughout the studies to measure the following parameters.

    • Various ion concentrations were determined using an inductively coupled plasma optical emission spectrometry analysis (ICP-OES, TJA Radial Iris 1000);
    • Total organic carbon (TOC) and dissolved organic carbon (DOC, TOC concentration after filtration through a 0.22 μm filter) were measured using a TOC-V Model Shimadzu TOC analyzer (the standard procedure of subtracting the total inorganic carbon (TIC) from the total carbon (TC) was employed to report the TOC (or DOC) value);
    • pH and conductivity were measured using standard pH and conductivity meters (Accumet XL 60); and
    • Color of the samples was measured using a Hach DR 5000 colourimeter.

Membrane Filtration Tests

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. The two membranes selected for conducting filtration studies were:

    • “Membrane 1”—an oleophobic, thin-film polymeric nanofiltration membrane with a molecular weight cut off (MWCO) of 150-300 Daltons (GE Water and Process Industries-DL Series);
    • “Membrane 2”—an oleophobic, thin-film polymeric nanofiltration membrane with a molecular weight cut off (MWCO) of approximately 1000 Da (Hydranautics/Nitto Denko-HydraCoRe 50).

Filtration tests were performed in crossflow mode at constant applied pressure and with full recirculation of both the concentrate and permeate. The operating conditions for the membrane filtration tests were set as follows:

Initial Permeate Flux 18 GFD Volumetric Feed Row Rate 1.0 GPM Temperature 50° C.

Flux and Fouling Propensity Profile

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. To examine the effect of accelerated fouling on flux decline and rejection, 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. To examine the extent of reversible fouling and flux recovery, 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.

Example 1 Characterization of Non-Oxidized and Oxidized 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.

TABLE 1 Water quality of oxidized and non-oxidized boiler blowdown (BBD) samples Sample Conductivity Colour TOC DOC BBD Water pH (mS/cm) (CU) (ppm C) (ppm C) Non-Oxidized 10.8 56.0 9000 656 586 Oxidized 10.7 56.9 9600 626 576

TABLE 2 Inorganic water quality of oxidized and non-oxidized BBD samples [Al] [Ca] [Fe] [K] [Mg] [Na] [Si] Sample (mg/ (mg/ (mg/ (mg/ (mg/ (mg/ (mg/ BBD Water L) L) L) L) L) L) L) Non- — * — * — * 243.8 — * 13003 61.26 Oxidized Oxidized — * — * — * 249.8 — * 12805 51.33 * Non-detectable concentration below 10 ppb

As shown by Table 1, the water quality of the BBD water changes after oxidation. For example, 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.

Example 2 Membrane Filtration Performance Profiles

As described above, 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. 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 Profile

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.

Readjustment of the pH to highly alkaline conditions reversed the fouling, indicating that the fouling of the membrane was reversible. This could have implications in the choice of membrane used and cleaning regime.

Permeate Rejection Profile

TOC and colour rejection performance of non-oxidized and oxidized boiler blowdown samples through Membranes 1 and 2 separation was observed, and recorded as shown in Tables 3 and 4 below.

Of particular interest is the effect of oxidation treatment on the rejection performance of membrane separation of TOC and colour, as both these parameters indicate levels of Fouling Organics relevant to the present invention.

TABLE 3 Membrane separation results from non-oxidized and oxidized boiler blowdown samples for Membrane 1 Feed Permeate TOC Feed Permeate Colour Sample TOC TOC Rejection Colour Colour Rejection BBD Water (ppm C.) (ppm C.) (%) (CU) (CU) (%) Non- 698 123 ± 2.9 82.4 ± 0.4 9050 1180 ± 100 87.0 ± 1.2 Oxidized Oxidized 666  99 ± 1.9 85.1 ± 0.3 9700  260 ± 158 97.3 ± 1.6

TABLE 4 Membrane separation results from non-oxidized and oxidized boiler blowdown samples for Membrane 2 Feed Permeate TOC Feed Permeate Colour Sample TOC TOC Rejection Colour Colour Rejection BBD Water (ppm C.) (ppm C.) (%) (CU) (CU) (%) Non- 613 298 ± 14 51.4 ± 2.2 8900 2720 ± 213 69.4 ± 2.4 Oxidized Oxidized 587 262 ± 13 55.3 ± 2.3 9400  844 ± 379 91.0 ± 4.0

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. By chemical reaction of the oxidative agent with the Fouling Organics, it is suggested, without being held to theory, that the characteristics of the Fouling Organics is changed, which thereby permits improved membrane separation of such Fouling Organics. For example, 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.

Oxidation improved TOC and colour rejection by approximately 4% and 11%, respectively, with Membrane 1, and approximately 4% and 22%, respectively, with Membrane 2.

The above disclosure represents embodiments of the invention recited in the claims. In the preceding description, for purposes of explanation, numerous details are set forth in order to provide a thorough understanding of the embodiments of the invention. However, it will be apparent that these and other specific details are not required to be specified herein in order for a person of skill in the art to practice the invention

The scope of the claims should not be limited by the preferred embodiments set forth in the foregoing examples, but should be given the broadest interpretation consistent with the description as a whole, and the claims are not to be limited to the preferred or exemplified embodiments of the invention.

Claims

1. 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:

(i) obtaining water from an underground hydrocarbon-containing formation during SAGD oil recovery methods performed on said underground formation, wherein said water contains Fouling Organics, said water having been passed through an oil-water separator as an initial means of removing a portion of oil from within said water, said water continuing to have Fouling Organics remaining therein;
(ii) injecting an oxidizing agent into said water;
(iii) filtering said Fouling Organics from said water to separate said Fouling Organics and thereby reduce the concentration of Fouling Organics in said water;
(iv) subsequently supplying said water having a reduced concentration of Fouling Organics therein to a boiler and turning said water into steam; and
(v) injecting said water, now in the form of steam, into said hydrocarbon-containing formation during said SAGD oil recovery operation.

2. The method for treating said boiler feedwater containing Fouling Organics in said SAGD oil recovery process of claim 1, wherein said water is from a produced water stream.

3. The method for treating said boiler feedwater containing Fouling Organics in said SAGD oil recovery process of claim 1, wherein said water is from a recycled boiler water stream.

4. The method for treating said boiler feedwater containing Fouling Organics in said SAGD oil recovery process of claim 1, wherein said water is a combination of water from a produced water stream and a recycled boiler water stream.

5. The method for treating said boiler feedwater containing Fouling Organics in said SAGD oil recovery process of claim 1, wherein said oxidizing agent chemically reacts with said Fouling Organics present in said water to:

(a) change the surface structure of said Fouling Organics to have less affinity to a membrane surface so as to thereby result in less fouling of said membrane surface;
(b) cause said Fouling Organics to agglomerate or polymerize to an increased molecular size and/or molecular weight so as to thereby permit being filtered out of said water;
(c) form a compound of lower solubility in said water than said Fouling Organics;
(d) cause said Fouling Organics to form flocs or chelate with other inorganic impurities in said water; or
(e) change the surface functional groups to be amphipathic so as to cause foaming.

6. The method for treating boiler feedwater containing Fouling Organics in said SAGD oil recovery process of claim 5, wherein said oxidizing agent is an oxidizing agent selected from the group of oxidizing agents consisting of oxygen, air, ozone, alkali permanganate, chlorine dioxide, and hydrogen peroxide.

7. The method of claim 6, wherein said oxidizing agent is oxygen contained in air.

8. The method for treating said boiler feedwater containing Fouling Organics in said SAGD oil recovery process of claim 7, wherein said step of filtering comprises:

passing said water, after said air is provided to said water and prior to providing said water to said boiler, through a filter or membrane to filter Fouling Organics therefrom.

9. The method of claim 8, wherein said filter is a nano-filter.

10. The method of claim 8, wherein said water is passed through a semi-porous membrane.

11. The method for treating said boiler feedwater containing Fouling Organics as claimed in claim 6, wherein subsequent to said oxidizing agent injection step said water is subject to deoxidation before being passed into said boiler.

12. The method of claim 11, wherein said oxidizing agent is air or oxygen, and subsequent to said oxidizing agent injection step said water is subject to both deaeration and deoxygenation before being passed into said boiler.

13. The method for treating said boiler feedwater containing Fouling Organics as claimed in claim 6, comprising the step of adding chemical oxygen scavengers to remove oxygen from said water.

14. A method for treating boiler feedwater containing Fouling Organics in a SAGD oil recovery process, wherein said water containing oil and Fouling Organics is recovered during SAGD oil recovery methods performed on an underground hydrocarbon-containing formation, and said Fouling Organics are at least partly removed from said water so as to reduce the concentration of said Fouling Organics in said water prior to heating of said water and re-injection of said water in the form of steam into said underground formation, comprising the steps of:

obtaining water from an underground hydrocarbon-containing formation during SAGD oil recovery methods performed on said underground formation, wherein said water contains Fouling Organics, said water having been passed through an oil-water separator as an initial means of removing at least a portion of oil from within said water, said water continuing to have Fouling Organics remaining therein;
(i) injecting air into said water to oxidize said Fouling Organics present in such water;
(ii) filtering said water by passing said water through a membrane to separate said Fouling Organics from said water and thereby reduce the concentration of Fouling Organics in said water;
(iii) deaerating and/or deoxygenating said water;
(iv) subsequently supplying said filtered water to a boiler and using said boiler to turn said water into steam; and
(v) injecting said water, now in the form of steam, into said hydrocarbon-containing formation during said SAGD oil recovery operation.

15. The method for treating said boiler feedwater containing Fouling Organics in said SAGD oil recovery process of claim 14, wherein said water is from a produced water stream.

16. The method for treating said boiler feedwater containing Fouling Organics in said SAGD oil recovery process of claim 14, wherein said water is from a recycled boiler water stream.

17. The method for treating said boiler feedwater containing Fouling Organics in said SAGD oil recovery process of claim 14, wherein said water is a combination of water from a produced water stream and a recycled boiler water stream.

18. A system for treating water containing Fouling Organics in a SAGD oil recovery process, wherein said 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, comprising:

(i) 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;
(ii) 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;
(iii) boiler means for heating said water stream so as to form steam; and
(iv) injection means for re-injecting said steam into said hydrocarbon-containing formation.

19. The system as claimed in claim 18, wherein said oxidizing agent injection means comprises air injection means so as to permit injection of air into said water stream prior to said water stream passing through said filter means.

20. The system as claimed in claim 18, wherein said filter means 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.

21. The system as claimed in claim 18, wherein said water stream is a produced water stream.

22. The system as claimed in claim 18, further comprising recycle means for said water stream exiting said boiler which has not been turned to steam, to permit same to be re-exposed to said oxidizing agent.

23. The system as claimed in claim 18, wherein said oxidizing agent injection means and filter means are located downstream from a recycle means, said recycle means for a recycled boiler water stream exiting said boiler, whereby said recycled boiler water stream is separately 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.

24. The system as claimed in 18, further comprising de-oiling means in said water stream, positioned in said water stream at a location upstream from said filter means.

25. The system as claimed in claim 24, wherein said de-oiling means is located upstream from said oxidizing agent injection means and said filter means.

26. The system as claimed in claim 25, wherein said de-oiling means comprises weir-separator means for separating hydrocarbons from said water stream.

27. The system as claimed in claim 18, said system further comprising deoxidizing means for removing oxidizing agent from said water subsequent to injection of said oxidizing agent, and prior to said water being provided to said boiler.

28. The system as claimed in claim 27, wherein said oxidizing agent is air or oxygen and said dexodizing means is deaeration and/or deoygenation means for removing oxygen from said water subsequent to injection of said air or oxygen, and prior to said water being provided to said boiler.

Patent History
Publication number: 20130319663
Type: Application
Filed: May 30, 2013
Publication Date: Dec 5, 2013
Applicant: HUSKY ENERGY LTD. (Calgary)
Inventors: Ian Buchanan (Calgary), Mark Owen (Calgary)
Application Number: 13/905,940
Classifications
Current U.S. Class: Steam As Drive Fluid (166/272.3)
International Classification: E21B 43/24 (20060101);