Classifications

• • 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
  • E21B37/00—Methods or apparatus for cleaning boreholes or wells
• • 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
  • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
  • E21B21/08—Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure

Definitions

• Embodiments disclosed herein relate generally to methods and systems of treating a wellbore, and more particularly to the removal of filtercakes which form in wellbores.
• Hydrocarbons are typically obtained from a subterranean geologic formation (i.e., a "reservoir") by drilling a well that penetrates the hydrocarbon-bearing formation.
• a subterranean geologic formation i.e., a "reservoir”
• hydrocarbons In order for hydrocarbons to be "produced,” that is, travel from the formation to the wellbore (and ultimately to the surface), there must be a sufficiently unimpeded flowpath from the formation to the wellbore.
• One key parameter that influences the rate of production is the permeability of the formation along the flowpath that the hydrocarbon must travel to reach the wellbore.
• the formation rock has a naturally low permeability; other times, the permeability is reduced during, for instance, drilling the well.
• a drilling fluid is often circulated into the hole to contact the region of a drill bit, for a number of reasons such as: to cool the drill bit, to carry the rock cuttings away from the point of drilling, and to maintain a hydrostatic pressure on the formation wall to prevent production during drilling.
• the fluids may be circulated through a drill pipe and drill bit into the wellbore, and then may subsequently flow upward through wellbore to the surface.
• the drilling fluid may act to remove drill cuttings from the bottom of the hole to the surface, to suspend cuttings and weighting material when circulation is interrupted, to control subsurface pressures, to maintain the integrity of the wellbore until the well section is cased and cemented, to isolate the fluids from the formation by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the wellbore, to cool and lubricate the drill string and bit, and/or to maximize penetration rate.
• drilling fluid can be lost by leaking into the formation.
• filtercakes are formed when particles suspended in a wellbore fluid coat and plug the pores in the subterranean formation such that the filtercake prevents or reduce both the loss of fluids into the formation and the influx of fluids present in the formation.
• a number of ways of forming filtercakes are known in the art, including the use of bridging particles, cuttings created by the drilling process, polymeric additives, and precipitates.
• the filtercake may stabilize the wellbore during subsequent completion operations such as placement of a gravel pack in the wellbore.
• a fluid loss pill of polymers may be "spotted" or placed in the wellbore.
• Other completion fluids may be injected behind the fluid loss pill into a position within the wellbore which is immediately above a portion of the formation where fluid loss is suspected. Injection of fluids into the wellbore is then stopped, and fluid loss will then move the pill toward the fluid loss location to coat the formation and prevent or reduce future fluid loss.
• filtercake (formed during drilling and/or completion) on the side walls of the wellbore must typically be removed, because remaining residue of the filtercake may negatively impact production. That is, although filtercake formation and use of fluid loss pills are essential to drilling and completion operations, the barriers may be a significant impediment to the production of hydrocarbons or other fluids from the well, if, for example, the rock formation is still plugged by the barrier. Because filtercake is compact, it often adheres strongly to the formation and may not be readily or completely flushed out of the formation by fluid action alone.
• the filtercake must be removed during the initial state of production, either physically or chemically (i.e., via acids, oxidizers, and/or enzymes).
• the amount and type of drill solids affects the effectiveness of these clean up treatments.
• Also affecting the effectiveness of the clean up of the wellbore prior to production is the presence of polymeric additives, which may be resistant to degradation using conventional filtercake breakers.
• embodiments disclosed herein relate to methods of treating a wellbore including emplacing at least one electrolytic tool in a desired section of the wellbore, applying an electric charge to wellbore fluids present in the desired section of the wellbore, and generating oxidants in situ by electrolyzing components of the wellbore fluids.
• embodiments disclosed herein relate to methods of breaking a filtercake formed in a wellbore, including generating oxidants in situ by electrolyzing components of a wellbore fluid present in the wellbore; and allowing the oxidants to degrade filtercake components.
• embodiments disclosed herein relate to systems for breaking a filtercake formed on a surface of a wellbore, including a wellbore having a filtercake formed thereon; a fluid supply source for supplying an aqueous solution into the wellbore; and at least one electrolytic tool for generating oxidants in the wellbore.
• FIG. 1 is a schematic drawing of one embodiment of a drilling system.
• Figure 2 is a schematic view of an electrolytic tool, according to embodiments disclosed herein.
• Figure 3 is a block diagram of an oxidant generation system, according to embodiments disclosed herein.
• Figure 4 is a flow chart showing a process of a filtercake treatment, according to embodiments disclosed herein.
• embodiments disclosed herein relate to the use of electrolytic tools downhole.
• embodiments disclosed herein relate to methods of treating a wellbore including emplacing an electrolytic tool in a desired section of the wellbore, applying an electric charge to wellbore fluids present, and generating oxidants in situ by electrolyzing components of the wellbore fluid.
• embodiments disclosed herein relate to methods of breaking a filtercake formed in a wellbore, including generating oxidants in situ by electrolyzing components of a wellbore fluid present in the wellbore, and allowing the oxidants to degrade filtercake components.
• embodiments disclosed herein relate to systems for breaking a filtercake formed on a surface of a wellbore, including a wellbore having a filtercake formed thereon, a fluid supply source for supplying an aqueous solution into the wellbore and an electrolytic tool for generating oxidants in the wellbore.
• FIG. 1 a schematic drawing of a typical drilling system is shown.
• a drilling system 10 is provided for drilling a wellbore into an earthen formation 100 to exploit natural resources such as oil.
• the drilling system 10 includes a derrick 20, a drill string assembly 30, a fluid circulation system 40, an electrolytic tool 50, a winch unit 70, and a control unit 85.
• the derrick 20 is built on a derrick floor 21 placed on the ground.
• the derrick 20 supports the drill string assembly 30 which is inserted into a wellbore 101 and carries out a drilling operation.
• the drill string assembly 30 includes a drill string 31, a bottom hole assembly
• the drill pipe 31 is rotated by the drive system 33, and this rotation is transmitted through the bottom hole assembly 32 to the drill bit 34.
• the fluid circulation system 40 includes a fluid pump 41, a mud pit 42, a supply line 43, and a return line 44.
• the fluid circulation system 40 circulates a wellbore fluid through the drill string assembly 30 and into the wellbore 101.
• the fluid pump 41 pumps wellbore fluid, which is reserved in the mud pit 42, through the supply line 43, and then, the wellbore fluid is injected into the drill string 31.
• the wellbore fluid injected into drill string 31 is then discharged from the drill bit 34 to the bottom of the wellbore 101 and returns to the mud pit 42 through the return line 44.
• fluids that exit drill bit 34 and circulate through the wellbore 101 may form a thin, low-permeability filtercake to seal permeable formations 100 penetrated by the bit 34.
• a variety of drilling fluids including oil- based and water-based wellbore fluids may be used to drill a wellbore 101.
• These well fluids may consist of synthetic polymers or biopolymers (such as to increase the rheological properties (e.g. plastic viscosity, yield point value, gel strength) of the drilling mud), clays, polymeric thinners, flocculants, and organic colloids added thereto to obtain the required viscosity and filtration properties.
• Heavy minerals such as barite or carbonate, may also be added to increase density.
• additives from the formation are incorporated into the mud and often become dispersed in the mud as a consequence of drilling.
• some additives may be added to specifically impart desired properties to the filtercake, to prevent both the loss of fluids from the wellbore into the formation and the influx of fluids that may be present in the formation into the wellbore.
• various polymeric additives may also act as fluid loss control agents to prevent or reduce the loss of wellbore fluid to the surrounding formation by reducing the permeability of filtercakes formed on the newly exposed rock surface.
• biodegradation-resistant polymeric additives include biopolymers; synthetic polymers, such as polyacrylamides and other acrylamide- based polymers; cellulose derivatives, such as dialkylcarboxymethylcellulose, hydroxyethylcellulose; and the sodium salts of carboxy-methylcellulose, chemically modified starch, guar gum, phosphomannans, scleroglucans, glucans, and dextrans.
• bridging agents such as calcium carbonate or fibrous materials may be added to bridge fractures or pores in a formation. While the filtercake serves an important role in drilling operations, the barrier can be a significant impediment to the production of hydrocarbons from the formation. Thus, once drilling and completion operations are complete, and production is desired, this coating or filtercake must be removed.
• oxidants for degrading a filtercake in accordance with embodiments disclosed herein may be generated in situ downhole by use of an electrolytic tool.
• FIG 2 a schematic of a simple electrolytic cell 51 according to some embodiments disclosed herein is shown.
• the electrolytic cell 51 includes at least one inlet port 54, through which a brine solution present in the wellbore may enter electrolytic cell 51, and at least one outlet port 56, through which generated oxidants may exit into the wellbore.
• the electrolytic cell 51 may contain at least one reaction chamber 57, for the housing of electrodes.
• the electrodes may be of any type or configuration known in the art.
• the electrolytic cell may contain at least two electrodes wherein at least one electrode is a positive electrode or an anode 58, and at least one electrode is a negative electrode or a cathode 59.
• the electrolytic tool may further include at least one control circuit (not shown) for selectively providing an electrical potential between the at least one cathode and the at least one anode, and an energy source (not shown) in electrical contact with the control circuit for delivering a controlled electrical charge to the control circuit.
• the at least one control circuit may be in electrical contact with the cathode 59 and the anode 58.
• Non-limiting examples of various electrolytic cells that may be used and/or modified for use downhole in the methods and system of the present disclosure include those described in U.S. Patent Nos. 4,761,208, 5,385,711, 6,261,464, 6,524,475, 6,558,537, 6,736,966, 6,805,787, 7,005,075, and 7,008,523, all of which are herein incorporated by reference.
• electrolytic cells may be incorporated into hardware typically used in downhole.
• completion hardware such as slotted liners and sand screens may be used as electrodes for the generation of oxidants within the wellbore in some embodiments of the present disclosure.
• a brine solution may enter and generated oxidants may exit the electrolytic cell 51.
• an electrolyte solution capable of transmitting an electrical charge upon which the electrolytic cell 51 may act.
• the capacity to transmit an electrical charge is known to be related to the ionic character of the electrolyte.
• the wellbore fluid may act as an electrolyte.
• Use of the wellbore fluid as an electrolyte is environmentally friendly and provides cost savings because no additional fluids need to be introduced into the wellbore.
• the wellbore fluid acting as an electrolyte may be a water-based fluid.
• the wellbore fluid may include an aqueous solution as the base fluid including at least one of fresh water, sea water, brine, mixtures of water and water-soluble organic compounds and mixtures thereof.
• the aqueous solution may be formulated with mixtures of desired salts in fresh water.
• Such salts may include, but are not limited to alkali metal chlorides, hydroxides, or carboxylates, for example.
• the wellbore fluids disclosed herein may include seawater, aqueous solutions wherein the salt concentration is less than that of sea water, or aqueous solutions wherein the salt concentration is greater than that of sea water.
• Salts that may be found in seawater include, but are not limited to, sodium, calcium, aluminum, magnesium, potassium, strontium, lithium, and salts of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, sulfates, silicates, phosphates and fluorides. Salts that may be incorporated in brines include any one or more of those present in natural seawater or any other organic or inorganic dissolved salts.
• brines that may be used in the drilling fluids disclosed herein may be natural or synthetic, with synthetic brines tending to be much simpler in constitution.
• a brine may include halide or carboxylate salts of mono- or divalent cations of metals, such as cesium, potassium, calcium, zinc, and/or sodium. The presence of these salts enhances the ionic character of the wellbore fluid, thereby increasing its ability to transmit an electric charge and enhancing its properties as an electrolyte.
• an electrical potential may be provided by a control unit (shown in Figure 3 as 85), and may be conducted between the electrodes 58 and 59 by the wellbore fluid.
• a controlled electrical charge passes through the wellbore fluid from the at least one cathode 59 to the at least one anode 58, thereby generating at least one oxidant in the electrolytic solution.
• the wellbore fluid flows through the reaction chamber 57 of the electrolytic cell 51, and an electrical current is passed between the anode 58 and the cathode 59, several chemical reactions occur that involve the water, as well as one or more of the other salts or ions contained in the wellbore fluid.
• the electrical current polarizes the electrodes 58, 59 and causes dissociation of the wellbore fluid into component ions.
• the wellbore fluid includes a solution of sodium chloride (NaCl)
• NaCl brine may dissociate into sodium and chlorine ions which would migrate to the cathode and to the anode, respectively:
• the anode is known to be electron deficient, and without being bound by any particular theory, it is believed that the anode withdraws electrons from the water and other ions adjacent to the anode, which results in the formation of oxidative species in the wellbore electrolyte. For instance, the following chlorine generating reaction may occur at the anode surface:
• the chlorine gas (Cl 2 ) generated by the chlorine reaction may dissolve in the water to generate hypochlorite ions (OCl " ) which are an oxidative species useful in embodiments of this disclosure:
• the protons generated (H + ) may in turn combine with free electrons at the electron-rich cathode to generate hydrogen gas, which may be vented from the electrolytic tool by any means known in the art:
• oxidant generation has been illustrated by using NaCl brines as an example, one skilled in the art would appreciate that these principles apply to the generation of oxidants from any ionic solution by electrolysis.
• the present disclosure relates to the production of one or more oxidants and may include, for example, hypochlorite, chlorine, bromine, chlorine dioxide, ozone, hydrogen peroxide, and other chloro-oxygenated and bromo-oxygenated species.
• Flow dynamics which include the movement of molecules in a flowing solution by turbulence, predict that the conversion of salts will increase as the solution flow path nears the anode surface layer.
• methods and systems of the present disclosure preferably maximize the flow of the wellbore electrolyte over the anode in order to maximize the generation of oxidants.
• Flow of the wellbore fluid may be enhanced by any means known in the art, for example mixers such as propellers, etc.
• pumping devices 60, 61 may be set between the positive electrode 58 and the negative electrode 59.
• the pumping devices may have propeller blades, valves, or any means known in the art to generate a fluid stream in the reaction chamber 57 so that the wellbore fluid surrounding the electrolytic tool is induced into the reaction chamber 57 of the electrolytic cell 51 through inlet port 54, passes through the reaction chamber 57 of the electrolytic cell 51, and is released from the outlet port 56.
• the inlet port 54 may include an inlet port mechanism such as a valve, or any other mechanism known in the art to seal the inlet port after the wellbore fluid has entered the cell. Once generated, the oxidant-rich wellbore fluid may exit the electrolytic cell 51 via the outlet port 56.
• the local concentration of oxidants present in the exiting wellbore fluid may be measured by any instrument known in the art, for example, an oxidant sensor. Once the oxidant sensor has detected that the local concentration of oxidant is sufficient to break the filtercake, the electrical potential applied across the electrodes of the electrolytic cell may be removed and the electrolytic tool may then be removed from the wellbore.
• the oxidants now present in the wellbore fluid may degrade the filtercake by any mechanism known in the art.
• filtercakes may comprise polymers such as polysaccharides. Oxidants are known to attack the glycosidic linkage between the rings, causing chain scission. Accordingly, as the polymer breaks down to shorter chains, the filtercake degrades, and may be removed by the circulating wellbore fluid. The oxidant becomes reduced by this process, and the reduced form may be reoxidized by the electrolytic tool, if deemed necessary. Alternatively, one skilled in the art would appreciate that the electrolytic tool may continuously (or intermittently) generate oxidants until it has been determined that the filtercake has been sufficiently removed.
• the applicants have also found that the ability to generate oxidants in situ for the breaking of filtercakes provides advantageous control over the timing of the breaking of the filtercake. Because the electrolytic tool may be emplaced at the site of the filtercake desired to be removed (e.g., at the producing interval), thereby generating an oxidant-rich environment in close proximity to the filtercake, the timing of the breaking of the filtercake may be triggered by the providing of an electrical potential across the electrodes of the electrolytic cell. For example, this technique may provide greater controllability as compared to conventional emplacement of breaker fluids, which may react too fast or too slow depending on the presence or absence of delay mechanisms.
• an electrolytic tool may be placed downhole to generate oxidants in situ which are able to kill bacteria which may be present in the wellbore.
• the drilling process initiates communication between the surface and the subsurface oilfield environments.
• wellbore fluids may be circulated from the surface to the bit to remove cuttings, and to control formation pressures downhole.
• chemicals and bacteria from the surface may be circulated into the deep subsurface energy-rich, oil-bearing strata, and the hydrocarbon laden cuttings may be brought into the oxygen-rich, moderate temperature surface environment.
• microbiological activity may be initiated in the surface and subsurface environments. While this typically does not occur normally, this may lead to bacterial contamination of the wellbore.
• organic polymers present as viscosifiers and fluid loss control agents in a wellbore fluid tend to be of plant or microbiological origin and may act as a ready food source for growth of naturally occurring oilfield bacteria. If bacterial growth is excessive, the consumption of these organic wellbore fluid components may result in a loss of the rheological properties of the mud, microbial corrosion of well tubulars and screens, biomass plugging in injection wells and the formation, and hydrogen sulfide production deep in the formation. If left untreated, it is possible that bacterial contamination may cause a breakdown of wellbore integrity.
• oxidants generated in situ in a wellbore from an electrolyte solution may be used to kill bacteria downhole.
• oxidants may attack components of the bacterial cell wall, such as peptidoglycans and other polysaccharides. Accordingly, methods and systems disclosed herein may generate oxidants in situ for the reduction of bacterial populations downhole.
• Electrolytic tools of use in embodiments disclosed herein may be placed in the wellbore by any means known in the art.
• the various embodiments of the present disclosure may work by placing at least part of or the entire electrolytic tool in the wellbore. Placement may occur at any stage of wellbore operations.
• the electrolytic tool may be placed in the wellbore during completion and before production.
• electrolytic tools disclosed herein may be used to trigger breaking of the gel in the inappropriate location so that it may be placed in the desired location. Additionally, if the tool is being used to control bacterial growth, it is envisioned that it may be desirable to form oxidants at any stage, including drilling.
• the electrolytic tool when generation of oxidants is desired, the electrolytic tool, or portions thereof, may be placed in the desired section of the well.
• This provides advantageous control over axial placement.
• problems may arise with respect to the proper placement of the breaker fluid, that is, ensuring that it is delivered to the entire desired zone (that is, the zone that needs filtercake removal). It is foreseeable in some cases that the portions of the filtercake that encounter the breaker fluid first may react and break apart more quickly than other portions of the filtercake do, with the potential that some fluid loss may be experienced in the region in which the filter cake has quickly broken up.
• an electrolytic tool with adequate dimensions may advantageously allow generation of oxidants over all of the filtercake, so that most of the filtercake may be broken at about the same time.
• several electrolytic cells may be emplaced in proximity to the f ⁇ ltercake to advantageously allow for generation of oxidants over all of the f ⁇ ltercake.
• the desired depth and/or lateral positioning of the electrolytic tool in the wellbore may be advantageously controlled by the use of any equipment known in the art such as winches etc. Further, the depth and lateral positioning of the electrolytic tool in the wellbore may be measured by any instrumentation known in the art, such as depth gauges, sensors, cameras etc. Once optimal placement of the electrolytic tool has been achieved, the oxidants may then be generated in situ at the desired section of the wellbore, thereby achieving paramount axial distribution of the oxidant breaker.
• the electrolytic tool includes an oxidant generation system 80.
• the oxidant generation system 80 includes the oxidant generator 50, a control unit 85, the winch unit 70, a power supply unit 81, and a valve actuator 82.
• the oxidant generator 50 includes an electrolytic cell 51, an oxidant sensor 52, and optionally a hydraulic power generator 53.
• the oxidant generator 50 may comprise multiple electrolytic cells 51, which may be electrically connected to each other in series or in parallel, to allow for the breaking of filtercakes over larger intervals.
• multiple oxidant generators 50 may be used in a single operation depending on the length of interval to be broken and/or dimensions of the tool.
• the oxidant generator 50 is suspended in the wellbore 101 by a cable 71.
• a winch unit 70 lifts and/or lowers the cable 71 to adjust depth position of the oxidant generator 50 in the wellbore 101.
• the control unit 85 includes, for example, a CPU, a ROM, a RAM, an input and an output port, a memory apparatus and the like (not shown).
• the control unit 85 is electrically connected to at least the oxidant generator 50, the winch unit 70, and power supply unit 81.
• the control unit 85 operates the oxidant generator 50, the winch unit 70 and valve actuator 82 by transmitting command signals (solid arrowed lines).
• the command signals may be based on detection signals of the oxidant sensor 51 connected to the oxidant generator 50 and/or the depth gauge 72 connected to the winch unit 70.
• a feedback command signal may be sent to the winch unit 70 through the control unit 85 to adjust the depth of the oxidant generator 50 accordingly.
• a feedback command signal may be sent to the winch unit 70 through the control unit 85 to adjust the output of the oxidant generator accordingly.
• the feedback command signal may be automated or input manually. Accordingly, the power supply unit 81 supplies electrical power (broken arrowed lines) to control unit 60, the oxidant generator 50, the winch unit 70 and the valve actuator 82, based on command signals transmitted by the control unit 85.
• a method of treating a wellbore is shown in a flow chart.
• a wellbore fluid which is an electrolytic brine solution may be emplaced within a wellbore.
• electrolytic brine solutions may have been the fluid used to drill the wellbore or may have been a subsequent fluid placed in the wellbore for completion operations, for example.
• the electrolytic tool may be placed in the section of the wellbore where removal of the filtercake is desired.
• applying voltage to the electrodes generates oxidants in the brine solution in the electrolytic cell.
• the wellbore is evaluated to assess the efficiency of the breaking of the filtercake.
• the electrolytic tool is deactivated in 5000, and removed from the wellbore, as in 6000. If the filtercake has not been sufficiently removed, the electrolytic tool may be activated once again by applying a voltage across the electrodes, as in 3000. This iteration may repeat until the filtercake has been sufficiently removed, and then the electrolytic tool may then be deactivated and removed from the wellbore as in 5000 and 6000, respectively.
• embodiments of the present disclosure provides for the degradation of filtercakes by oxidants generated downhole, in situ, by use of an electrolytic tool.
• the in situ generation of oxidants may provide advantageous control over timing of breaking of the oxidative breaker in the wellbore.
• generating oxidants in situ from relatively benign precursors such as brines may result in less corrosion in the drill string assembly and is more environmentally friendly.
• generating oxidants in situ at the desired site may allow use of smaller volumes of chemicals such as oxidative breaker and other additives, and may be more cost-efficient, using species already present in a wellbore instead of requiring a subsequent pumping of a breaker fluid downhole.
• generating oxidants downhole may allow for control of bacterial populations downhole.
• Control of bacterial populations downhole may result in decreased microbial corrosion of tubular and screens, biomass plugging, and hydrogen sulfide production.
• appreciable cost savings, environmental, and safety benefits may be actualized by use of embodiments of the methods and systems of the present disclosure. While the invention has been described with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments can be devised which do not depart from the scope of the invention as disclosed herein. Accordingly, the scope of the invention should be limited only by the attached claims.

Landscapes

• Life Sciences & Earth Sciences (AREA)
• Engineering & Computer Science (AREA)
• Geology (AREA)
• Mining & Mineral Resources (AREA)
• Physics & Mathematics (AREA)
• Environmental & Geological Engineering (AREA)
• Fluid Mechanics (AREA)
• General Life Sciences & Earth Sciences (AREA)
• Geochemistry & Mineralogy (AREA)
• Water Treatment By Electricity Or Magnetism (AREA)
• Electrolytic Production Of Non-Metals, Compounds, Apparatuses Therefor (AREA)

Applications Claiming Priority (2)

Publications (1)

Family

ID=40943750

Family Applications (1)

Country Status (8)

Families Citing this family (9)

Family Cites Families (27)

• 2009
  • 2009-03-06 CA CA2718072A patent/CA2718072A1/en not_active Abandoned
  • 2009-03-06 EA EA201071065A patent/EA018242B1/ru not_active IP Right Cessation
  • 2009-03-06 MX MX2010009936A patent/MX2010009936A/es not_active Application Discontinuation
  • 2009-03-06 EP EP09720550A patent/EP2268891A2/en not_active Withdrawn
  • 2009-03-06 AU AU2009223855A patent/AU2009223855B2/en not_active Ceased
  • 2009-03-06 CN CN200980108529.2A patent/CN101970793B/zh not_active Expired - Fee Related
  • 2009-03-06 US US12/921,607 patent/US20110024122A1/en not_active Abandoned
  • 2009-03-06 CA CA2853269A patent/CA2853269A1/en not_active Abandoned
  • 2009-03-06 WO PCT/IB2009/005119 patent/WO2009112948A2/en active Application Filing

Non-Patent Citations (1)

Also Published As

Similar Documents

Legal Events