WO2023279148A1 - A method for performing chemical treatments in wellbores - Google Patents
A method for performing chemical treatments in wellbores Download PDFInfo
- Publication number
- WO2023279148A1 WO2023279148A1 PCT/AU2022/050695 AU2022050695W WO2023279148A1 WO 2023279148 A1 WO2023279148 A1 WO 2023279148A1 AU 2022050695 W AU2022050695 W AU 2022050695W WO 2023279148 A1 WO2023279148 A1 WO 2023279148A1
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- wellbore
- mixture
- injection tool
- perforated casing
- casing
- Prior art date
Links
- 238000000034 method Methods 0.000 title claims abstract description 52
- 239000000126 substance Substances 0.000 title claims abstract description 41
- 238000011282 treatment Methods 0.000 title claims abstract description 37
- 239000000203 mixture Substances 0.000 claims abstract description 113
- 239000012530 fluid Substances 0.000 claims abstract description 89
- 238000002347 injection Methods 0.000 claims abstract description 68
- 239000007924 injection Substances 0.000 claims abstract description 68
- 239000011435 rock Substances 0.000 claims abstract description 58
- 239000000654 additive Substances 0.000 claims abstract description 42
- 230000000996 additive effect Effects 0.000 claims abstract description 42
- 239000003245 coal Substances 0.000 claims description 27
- 239000007787 solid Substances 0.000 claims description 24
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 16
- 238000004891 communication Methods 0.000 claims description 6
- 230000005484 gravity Effects 0.000 claims description 5
- 230000004888 barrier function Effects 0.000 claims description 4
- 230000003068 static effect Effects 0.000 claims description 4
- 230000009545 invasion Effects 0.000 claims description 3
- 230000035515 penetration Effects 0.000 claims description 2
- 238000004519 manufacturing process Methods 0.000 description 21
- 239000007789 gas Substances 0.000 description 14
- 230000005012 migration Effects 0.000 description 12
- 238000013508 migration Methods 0.000 description 12
- 239000011343 solid material Substances 0.000 description 12
- 239000002245 particle Substances 0.000 description 8
- 239000000463 material Substances 0.000 description 7
- 230000002829 reductive effect Effects 0.000 description 7
- 239000000243 solution Substances 0.000 description 7
- 230000008901 benefit Effects 0.000 description 5
- 239000006260 foam Substances 0.000 description 5
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 4
- 238000011109 contamination Methods 0.000 description 4
- 239000002585 base Substances 0.000 description 3
- 239000004927 clay Substances 0.000 description 3
- 238000004140 cleaning Methods 0.000 description 3
- 239000008240 homogeneous mixture Substances 0.000 description 3
- 239000007788 liquid Substances 0.000 description 3
- 239000004094 surface-active agent Substances 0.000 description 3
- 239000004604 Blowing Agent Substances 0.000 description 2
- 239000004215 Carbon black (E152) Substances 0.000 description 2
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 description 2
- 244000007835 Cyamopsis tetragonoloba Species 0.000 description 2
- NQRYJNQNLNOLGT-UHFFFAOYSA-N Piperidine Chemical compound C1CCNCC1 NQRYJNQNLNOLGT-UHFFFAOYSA-N 0.000 description 2
- DBMJMQXJHONAFJ-UHFFFAOYSA-M Sodium laurylsulphate Chemical compound [Na+].CCCCCCCCCCCCOS([O-])(=O)=O DBMJMQXJHONAFJ-UHFFFAOYSA-M 0.000 description 2
- 239000003570 air Substances 0.000 description 2
- BTBJBAZGXNKLQC-UHFFFAOYSA-N ammonium lauryl sulfate Chemical compound [NH4+].CCCCCCCCCCCCOS([O-])(=O)=O BTBJBAZGXNKLQC-UHFFFAOYSA-N 0.000 description 2
- 229940063953 ammonium lauryl sulfate Drugs 0.000 description 2
- 239000012267 brine Substances 0.000 description 2
- 239000003795 chemical substances by application Substances 0.000 description 2
- SMVRDGHCVNAOIN-UHFFFAOYSA-L disodium;1-dodecoxydodecane;sulfate Chemical compound [Na+].[Na+].[O-]S([O-])(=O)=O.CCCCCCCCCCCCOCCCCCCCCCCCC SMVRDGHCVNAOIN-UHFFFAOYSA-L 0.000 description 2
- 239000004088 foaming agent Substances 0.000 description 2
- 229930195733 hydrocarbon Natural products 0.000 description 2
- 150000002430 hydrocarbons Chemical class 0.000 description 2
- 230000003993 interaction Effects 0.000 description 2
- 238000003801 milling Methods 0.000 description 2
- 229910052757 nitrogen Inorganic materials 0.000 description 2
- 238000002360 preparation method Methods 0.000 description 2
- 238000005086 pumping Methods 0.000 description 2
- 230000000717 retained effect Effects 0.000 description 2
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 description 2
- IMNIMPAHZVJRPE-UHFFFAOYSA-N triethylenediamine Chemical compound C1CN2CCN1CC2 IMNIMPAHZVJRPE-UHFFFAOYSA-N 0.000 description 2
- 239000004160 Ammonium persulphate Substances 0.000 description 1
- BTBUEUYNUDRHOZ-UHFFFAOYSA-N Borate Chemical compound [O-]B([O-])[O-] BTBUEUYNUDRHOZ-UHFFFAOYSA-N 0.000 description 1
- UXVMQQNJUSDDNG-UHFFFAOYSA-L Calcium chloride Chemical compound [Cl-].[Cl-].[Ca+2] UXVMQQNJUSDDNG-UHFFFAOYSA-L 0.000 description 1
- 239000004971 Cross linker Substances 0.000 description 1
- 239000004698 Polyethylene Substances 0.000 description 1
- KWYUFKZDYYNOTN-UHFFFAOYSA-M Potassium hydroxide Chemical compound [OH-].[K+] KWYUFKZDYYNOTN-UHFFFAOYSA-M 0.000 description 1
- 239000004115 Sodium Silicate Substances 0.000 description 1
- 206010066901 Treatment failure Diseases 0.000 description 1
- GSEJCLTVZPLZKY-UHFFFAOYSA-N Triethanolamine Chemical compound OCCN(CCO)CCO GSEJCLTVZPLZKY-UHFFFAOYSA-N 0.000 description 1
- 239000003082 abrasive agent Substances 0.000 description 1
- 238000009825 accumulation Methods 0.000 description 1
- 230000009471 action Effects 0.000 description 1
- 239000012190 activator Substances 0.000 description 1
- ROOXNKNUYICQNP-UHFFFAOYSA-N ammonium persulfate Chemical compound [NH4+].[NH4+].[O-]S(=O)(=O)OOS([O-])(=O)=O ROOXNKNUYICQNP-UHFFFAOYSA-N 0.000 description 1
- 235000019395 ammonium persulphate Nutrition 0.000 description 1
- 239000001569 carbon dioxide Substances 0.000 description 1
- 229910002092 carbon dioxide Inorganic materials 0.000 description 1
- 239000003054 catalyst Substances 0.000 description 1
- 229920002678 cellulose Polymers 0.000 description 1
- 239000001913 cellulose Substances 0.000 description 1
- 239000004568 cement Substances 0.000 description 1
- 239000011248 coating agent Substances 0.000 description 1
- 238000000576 coating method Methods 0.000 description 1
- 238000005260 corrosion Methods 0.000 description 1
- 230000007797 corrosion Effects 0.000 description 1
- 238000005536 corrosion prevention Methods 0.000 description 1
- 230000007812 deficiency Effects 0.000 description 1
- 230000006735 deficit Effects 0.000 description 1
- ZBCBWPMODOFKDW-UHFFFAOYSA-N diethanolamine Chemical compound OCCNCCO ZBCBWPMODOFKDW-UHFFFAOYSA-N 0.000 description 1
- 238000005553 drilling Methods 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 229920001971 elastomer Polymers 0.000 description 1
- 239000003822 epoxy resin Substances 0.000 description 1
- 230000003628 erosive effect Effects 0.000 description 1
- 239000003349 gelling agent Substances 0.000 description 1
- 230000001771 impaired effect Effects 0.000 description 1
- 238000011065 in-situ storage Methods 0.000 description 1
- 230000000670 limiting effect Effects 0.000 description 1
- 239000011159 matrix material Substances 0.000 description 1
- 230000000116 mitigating effect Effects 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 230000035699 permeability Effects 0.000 description 1
- 229920000647 polyepoxide Polymers 0.000 description 1
- 229920000728 polyester Polymers 0.000 description 1
- -1 polyethylene Polymers 0.000 description 1
- 229920000573 polyethylene Polymers 0.000 description 1
- 229920002635 polyurethane Polymers 0.000 description 1
- 239000004814 polyurethane Substances 0.000 description 1
- 229920000915 polyvinyl chloride Polymers 0.000 description 1
- 239000004800 polyvinyl chloride Substances 0.000 description 1
- 230000003014 reinforcing effect Effects 0.000 description 1
- NTHWMYGWWRZVTN-UHFFFAOYSA-N sodium silicate Chemical compound [Na+].[Na+].[O-][Si]([O-])=O NTHWMYGWWRZVTN-UHFFFAOYSA-N 0.000 description 1
- 229910052911 sodium silicate Inorganic materials 0.000 description 1
- 239000002904 solvent Substances 0.000 description 1
- 238000005728 strengthening Methods 0.000 description 1
- 230000008961 swelling Effects 0.000 description 1
- 229920001059 synthetic polymer Polymers 0.000 description 1
- VOITXYVAKOUIBA-UHFFFAOYSA-N triethylaluminium Chemical compound CC[Al](CC)CC VOITXYVAKOUIBA-UHFFFAOYSA-N 0.000 description 1
- 238000005406 washing Methods 0.000 description 1
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
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
- E21B33/138—Plastering the borehole wall; Injecting into the formation
-
- 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
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
- E21B33/14—Methods or devices for cementing, for plugging holes, crevices or the like for cementing casings into boreholes
-
- 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
-
- 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
- E21B43/02—Subsoil filtering
- E21B43/025—Consolidation of loose sand or the like round the wells without excessively decreasing the permeability thereof
Definitions
- the present invention relates to a method for performing chemical treatments in wellbores.
- the present invention relates to a method for performing chemical treatments in wellbores (and particularly oil and gas wellbores including vertical, deviated and horizontal wellbores) with perforated or slotted production casing or liner sections that increases chemical treatment placement efficiency behind the casing and reduces or eliminates the invasion of chemicals into the rock structure.
- Chemical treatments are performed in oil and gas wells for many different reasons. For instance, chemical treatments may be used to stimulate hydrocarbon production, to shut-off undesired water or gas production, reinforce the wellbore or to reduce solids migration into the wellbore from the surrounding rock structure,
- Embodiments of the present invention provide a method for performing chemical treatments in wellbores, which may at least partially address one or more of the problems or deficiencies mentioned above or which may provide the public with a useful or commercial choice.
- the present invention in one form, resides broadly in a method for performing chemical treatments in wellbores, the method comprising the steps of: introducing a settable fluid into a mixing apparatus located within a wellbore; separately introducing a setting additive into the mixing apparatus; forming a mixture of the settable fluid and the setting additive in the mixing apparatus; introducing the mixture into the wellbore through an injection tool located, initially, at or adjacent a lower end of a perforated casing positioned in the wellbore such that at least a portion of the mixture is located between the perforated casing and a surrounding rock structure; substantially continuously raising the injection tool towards an upper end of the perforated casing while substantially continuously injecting the mixture into the wellbore; and allowing the mixture to at least partially set.
- the settable fluid may be introduced into the wellbore using any suitable technique.
- the settable fluid may be pumped into the wellbore, preferably from above ground level. Any suitable pump may be used to pump the settable fluid into the wellbore.
- the settable fluid may be introduced to the wellbore through a tubing (a jointed tubing or, more preferably, a coiled tubing) within the well.
- production tubing in the wellbore may be withdrawn or removed from the wellbore to allow the coiled tubing to be inserted into the wellbore and the settable fluid to be introduced.
- the preparation of the wellbore may involve removing as many solid particles as possible from the wellbore and/or the annular space between the pre-perforated casing and the surrounding rock structure. However, it will be understood that it may not be possible to remove bridges of solid material formed between the perforated casing and the surrounding rock structure.
- the wellbore may be prepared using any suitable technique. For instance, solid particles may be removed from the wellbore using a fluid (such as water, brine, air or nitrogen, foam, or any suitable combination thereof) and then the solid particles may be circulated to the surface. Also, specialised downhole cleaning tools such as the one described in Australian innovation patent no. 2016101412 may be used to enhance the cleaning behind the casing .
- a fluid such as water, brine, air or nitrogen, foam, or any suitable combination thereof
- specialised downhole cleaning tools such as the one described in Australian innovation patent no. 2016101412 may be used to enhance the cleaning behind the casing .
- the settable fluid may be provided as a substantially homogenous mixture.
- the settable fluid may comprise two or more components that must be mixed together to form the settable fluid.
- the two or more components may be mixed at any suitable location.
- the two or more components may be mixed at the surface prior to the introduction of the settable fluid into the wellbore.
- the mixing of the two or more components may occur during the pumping of the two or more components into the wellbore.
- the settable fluid is introduced into the wellbore in a substantially liquid pumpable form. Once in location between the perforated production casing and the surrounding rock structure, the settable fluid may set to form an at least partially solid material.
- the settable fluid may be of any suitable form.
- the settable fluid may at least partially comprise a cementitious material.
- the settable fluid may comprise a natural polymeric material, a synthetic polymeric material, or a combination of the two (for instance, rubber, polyurethane, polyester, polyvinylchloride, polyethylene or the like, or a combination or cross linked thereof).
- the settable fluid may be provided in the form of a foam, and particularly a pumpable foam which is preferably mixed and pumped from the surface.
- the settable fluid may be introduced to the wellbore as a liquid and then, optionally, converted to a foam in situ.
- the settable fluid may further comprise a foaming agent.
- Any suitable foaming agent may be used, such as a surfactant and/or a blowing agent.
- Any suitable surfactant may be used, such as sodium lauryl ether sulfate (SLES), sodium dodecyl sulfate (SDS), ammonium lauryl sulfate (ALS) or the like, or any suitable combination thereof.
- any suitable blowing agent may be used, such as, but not limited to, nitrogen, air, carbon dioxide, or the like, or any suitable combination thereof.
- the settable fluid may further comprise one or more of the following components: a curing agent, a gellant (such as guar or guar derivatives, synthetic polymers, cellulose or viscoelastic surfactant), a catalyst, an activator, a crosslinker (such as metallic or borate types), a strengthening agent, or the like.
- a curing agent such as guar or guar derivatives, synthetic polymers, cellulose or viscoelastic surfactant
- a catalyst such as guar or guar derivatives, synthetic polymers, cellulose or viscoelastic surfactant
- an activator such as metallic or borate types
- a crosslinker such as metallic or borate types
- the specific gravity of the settable fluid may not exceed 2.0. More preferably, the specific gravity of the settable fluid may be between approximately 0.1 and 1 .7. Still more preferably, the specific gravity of the settable fluid may be between approximately 0.3 and 1 .5. Most preferably, the specific gravity of the settable fluid may be between about 0.5 and 1 .2.
- the settable fluid may have a relatively high viscosity.
- the settable fluid may have any suitable viscosity, although in a preferred embodiment of the invention, the settable fluid may have a viscosity greater than the viscosity of water (i.e. greater than 0.894 cP). More preferably, the settable fluid may have a viscosity of greater than 100.0 cP. Still more preferably, the settable fluid may have a viscosity of greater than 200.0 cP. Even more preferably, the settable fluid may have a viscosity of greater than 250.0 cP. It will be understood that the viscosity of the settable fluid refers to the viscosity of the liquid form of the settable fluid. Once set, the viscosity of the settable fluid may be much higher than these values.
- a setting additive is added to the settable fluid.
- the setting additive may be added to the settable fluid in the wellbore downhole, so as to accelerate the setting reaction of the settable fluid. Therefore, it is preferred that the injection tool may be provided with a mixing apparatus in which the settable fluid and the setting additive may be mixed prior to the mixture being introduced into the wellbore through the injection tool.
- the mixing apparatus may be of any suitable form and may comprise, for instance, an agitated chamber (including an impeller, stirrer or the like) or a Venturi device. More preferably, however, the mixing apparatus may comprise a static mixer.
- the injection tool may be provided with the mixing apparatus.
- the mixing apparatus may be in fluid communication with the injection tool.
- the mixing apparatus may be located adjacent, or in close proximity, to the injection tool.
- the mixing apparatus may be located vertically above the injection tool in the wellbore. In this way, the mixture exiting the mixing apparatus may flow into the injection tool.
- a source of the setting additive may be carried in the injection tool (for instance, in a tank, canister or similar container) and may be added to the settable fluid pumped from the surface.
- the setting additive may be pumped from the surface to the injection tool and, more accurately, the mixing apparatus.
- the setting additive is pumped from the surface in a separate conduit to the settable fluid.
- the setting additive may be pumped from the surface to the mixing apparatus in the coiled tubing. More preferably, the setting additive may be pumped from the surface to the mixing apparatus in a conduit within the coiled tubing.
- the setting additive may be pumped from the surface to the mixing apparatus in a capillary line located within the coiled tubing.
- the setting additive may be introduced to the mixing apparatus with the settable fluid.
- the mixing apparatus forms a substantially homogenous mixture of the setting additive and the settable fluid for introduction to the wellbore.
- the setting additive may be of any suitable form, although in a preferred embodiment of the invention, the setting additive may comprise sodium silicate solution, calcium chloride solution, triethyl aluminum solution, ammonium persulphate solution, triethylenediamine solution, triethanolamine solution, potassium hydroxide solution, piperidine solution, diethanolamine solution, epoxy resin, or any suitable combination thereof.
- the setting additive may be added in any suitable quantity to the settable fluid, and it will be understood that the quantity of setting additive added to the settable fluid may depend on a number of factors, such as the chemical composition of the settable fluid, the chemical composition of the setting additive, the volume of settable fluid, the desired rate of setting of the settable fluid and so on.
- the mixture of the settable fluid and the setting additive may set in a shorter time than the settable fluid without the setting additive.
- the addition of the setting additive to the settable fluid may reduce the setting time of the settable fluid from hours to minutes, or even seconds. Once set, it is envisaged that the mixture may form a physical barrier between the rock structure and the perforated casing.
- the mixture is introduced into the wellbore such that at least a portion of the mixture is located between a perforated production casing and a surrounding rock structure. More preferably, a substantial portion of the mixture may be located between the perforated production casing and a surrounding rock structure.
- the injection tool is, in use, substantially continuously raised towards an upper end of the perforated casing while the mixture is substantially continuously injected into the wellbore.
- the rate at which the injection tool is raised may depend on a number of factors, such as, but not limited to, the exact chemistry of the mixture, the rate at which the mixture sets, the volume of the annular space between the perforated casing and the rock structure and so on. It is envisaged, however, that the injection tool may be raised at a rate of between 1 m/min and 35 m/min. More preferably, the injection tool may be raised at a rate of between 5 m/min and 25 m/min, although it will be understood that the rate may vary depending on the specific circumstances encountered.
- the introduction of the mixture into the wellbore has been described as being substantially continuous, it is envisaged that there may be occasions when the introduction of the mixture is momentarily paused.
- the introduction of the mixture may be momentarily paused as the injection tool passes the location of the bridges of solid material. This may be done to reduce the amount of mixture that is unable to pass through the perforated casing into the annular cavity due to the presence of the bridges of solid material.
- the introduction of mixture into the wellbore may recommence.
- the injection tool introduces the mixture of the settable fluid and the setting additive into the wellbore at an angle to the orientation of the wellbore.
- the mixture of the settable fluid and the setting additive may be introduced into the wellbore at any suitable angle to the orientation of the wellbore.
- the injection tool may introduce the mixture of the settable fluid and the setting additive into the wellbore at an angle of between 30° and 150° to the orientation of the wellbore. More preferably, the injection tool may introduce the mixture of the settable fluid and the setting additive into the wellbore at an angle of between 70° and 110° to the orientation of the wellbore. Most preferably, the injection tool may introduce the mixture of the settable fluid and the setting additive into the wellbore at an angle of approximately 90° to the orientation of the wellbore.
- the injection tool may include a base member in a lower region thereof.
- Any suitable base member may be provided, although it will be understood that the purpose of the base member may be to reduce or preclude the ability of the mixture from being introduced into the wellbore at a point below the injecting tool.
- the injecting tool may comprise a nozzle, hose, conduit or the like, or any suitable combination thereof.
- the mixture may be introduced into the wellbore between an upper member and a lower member.
- the upper member and the lower member may be of any suitable form, and may be the same as one another, or may be different to one another.
- the upper member and the lower member may comprise packers, drag blocks or the like.
- the upper member and the lower member may both comprise packers.
- the upper member may comprise a packer, while the lower member may comprise a drag block.
- the packers are deactivated in the run in hole position.
- the upper member and the lower member are associated with an outer surface of the coiled tubing.
- the upper member and the lower member may be associated with the outer surface of the coiled tubing using any suitable technique.
- the upper member and the lower member may be configured for connection to the outer surface of the coiled tubing.
- the upper member and/or the lower member may be substantially annular members.
- the substantially annular members may be substantially ring-shaped with a central aperture.
- the coiled tubing may pass through the central aperture and the upper member and/or lower member may be retained on the coiled tubing.
- the upper member and the lower member may be associated with the outer surface of the coiled tubing by being located adjacent thereto.
- the upper member and the lower member extend at least partway between the coiled tubing and an inner surface of the wellbore, or an inner surface of a casing (such as, but not limited to, a perforated casing, solid casing (i.e., a casing with no perforations in at least a portion thereof) or the like) located within the wellbore.
- the upper member and the lower member may define a passageway along which the mixture flows at least partway between the coiled tubing and the perforated casing.
- the upper member and the lower member may provide at least partially isolate the portion of the wellbore between the upper member and the lower member from the wellbore.
- the upper member and the lower member may create a barrier to reduce or eliminate the ability of the mixture to enter any part of the wellbore other than the part of the wellbore isolated between the upper member and the lower member.
- the upper member may be expanded so that the outer periphery of the upper member may be located in close proximity to, or abutment with, the inner surface of the casing. In this way, it is envisaged that the flow of the mixture upwardly in the wellbore between the upper member and the casing may be substantially precluded.
- the upper member may substantially isolate the region of the wellbore into which the mixture is introduced through the injection tool. In this embodiment, it is envisaged that the mixture may exit the injection tool at or adjacent the inner surface of the casing.
- the upper member may be expanded using any suitable technique.
- the upper member may be inflatable. Any suitable inflating fluid may be used to inflate the upper member.
- the inflating fluid may be water, brine or setting additive
- the inflating fluid may be pumped from the surface to the upper and lower members.
- the inflating fluid may be pumped through any suitable conduit, although in a preferred embodiment of the invention the inflating fluid may be pumped to the upper and lower members using a capillary line.
- the capillary line may be the same capillary line through which the setting additive is introduced to the mixing apparatus.
- the upper member may be expanded so that the outer periphery of the upper member may be located in close proximity to, or abutment with, the inner surface of the casing.
- the lower member may be provided in such a manner that a gap is provided between the outer periphery of the lower member and the inner surface of the casing. In this way, a portion of the mixture of the settable fluid and the setting additive may flow between the lower member and the casing and enter the wellbore inside the casing at a point below the injection tool.
- the injection tool may be ran initially to or adjacent the bottom of the well. Specifically, the injection tool may be ran in the run in hole (RIH) position to or adjacent the bottom of the well.
- the upper and/or lower members may be retracted and there exists a flow path between the injection tool and casing, which enables the injection tool to be easily pushed down into the wellbore with low or no risk of hanging on casing collars or other casing obstructions and with minimum snubbing force.
- an injection tool designed to retract the members when running in hole smaller size coiled tubing pipe may be used with minimum risk of pipe buckling failure.
- Another advantage may be that the chemical treatments can be performed more cost-efficiently as there is a reduced snubbing force requirement.
- a small to medium size coiled tubing unit set up to run smaller size pipe for example, 2 in or 5.08 cm
- a medium capacity injector for instance 60,000 lb or 27.22t snubbing capacity
- 7 in (17.78 cm) casing may become an effective option.
- the mixture is introduced into the wellbore such that at least a portion of the mixture is located between a perforated production casing and a surrounding rock structure. More preferably, a substantial portion of the settable fluid may be located between the perforated production casing and a surrounding rock structure.
- the mixture may, when set, adhere or bond to the perforated casing and/or the surrounding rock structure.
- the mixture may, when set, simply abut the perforated casing and/or the surrounding rock structure. It is envisaged that, due to the combination of the relatively low density/relatively high viscosity of the mixture and a rapid setting time, invasion or penetration of the mixture into the rock structure (i.e. coal seams) may be substantially precluded, even in relatively depleted wells.
- the mixture is of sufficient mechanical strength and durability so as to remain in use for extended periods of time. Further, it is preferred that the mixture may reduce or mitigate the migration of solid particles from the surrounding rock structure into the wellbore. The mixture may do this by providing a physical barrier between the rock structure and the perforated casing and/or by reinforcing the rock structure such that solid particles do not become detached or separated from the rock structure and/or by having relatively low permeability such that solid particles from the rock structure are physically unable to pass through the settable fluid and enter the wellbore through the perforated casing.
- Another advantage may be that the presence of the mixture may prevent or reduce the instance of erosion of the rock structure (and therefore migration of solid particles into the wellbore) through exposure of the rock structure to water flowing from the coal seams. Furthermore, the presence of the mixture may reduce or minimise interaction between clay-rich rock in the rock structure and water from coal seams. This interaction can result in swelling of clay in the rock structure and migration of clay particles into the wellbore.
- a portion of the mixture introduced to the wellbore may not pass through the perforated casing and may instead remain in the wellbore inside the perforated casing.
- at least a portion of the mixture within the perforated casing may be removed.
- the mixture within the perforated casing may be removed using any suitable technique, such as drilling, milling, jetting or the like.
- one or more passages may be formed in the mixture in order to reconnect at least a portion of the producing rock (i.e. coal seams) to the wellbore. In this way, well production may be resumed.
- the one or more passages may be formed using any suitable technique. For instance, the one or more passages may be drilled or bored, or may be formed using an abrasive material, solvent, jetting water or the like. In other embodiments, the one or more passages may be formed naturally in the mixture by the flow of water, gas and/or solids out of the producing rock (i.e. coal seams).
- the invention resides broadly in an apparatus for introducing a mixture of a settable fluid and a setting additive into a wellbore, the apparatus comprising a mixing apparatus in fluid communication with a coiled tubing and a capillary line located within the coiled tubing, the mixing apparatus configured to be in fluid communication with an injection tool located substantially below the mixing apparatus in use, and wherein the injection tool further comprises an upper member and a lower member, the upper member and the lower member being configured to extend at least partway between the coiled tubing and an inner surface of the wellbore or an inner surface of a casing located within the wellbore, and the injection tool is configured to introduce the mixture into the wellbore along a passageway formed between the upper member and the lower member.
- the apparatus may be used to introduce the mixture to a single location within a wellbore.
- the apparatus may be raised within the wellbore during use so that the mixture may be introduced to multiple locations within the wellbore.
- the invention resides broadly in a method for introducing a chemical treatment into a wellbore
- the injection tool comprising an upper member and a lower member
- a portion of the chemical treatment may pass between the lower member and the inner surface of the perforated casing. In this way, a portion of the chemical treatment may be retained in the wellbore within the perforated casing.
- the present invention has been described largely in terms of its use to reduce the migration of solids from a surrounding rock structure into a wellbore, a skilled addressee would understand that the present invention may be used for a number of other purposes.
- the present invention could be used to reduce or eliminate unwanted water production in a well, or to reduce or eliminate unwanted gas production in a well.
- the present invention could be used to stimulate hydrocarbon production within a well.
- the present invention may be used to treat a “loss zone” or “loss circulation section” of a wellbore by pumping fluid or the mixture into one or more specific sections of a wellbore to reduce or eliminate the loss of fluids from these sections.
- the present invention may also be used to performing cleaning, scale removal and/or washing of the inner wall of a perforated casing in a manner that provides more control (and is therefore more effective) than existing methods.
- the present invention may be used for performing applying corrosion prevention, treating corrosion, or coating the inner surface of the perforated casing.
- Figures 1 to 5 illustrates steps in a method for reducing solids migration into wellbores according to an embodiment of the present invention.
- Figure 1 illustrates a first step in a method for reducing solids migration into a wellbore 10 according to an embodiment of the present invention.
- the wellbore 10 of Figure 1 is a coal seam gas wellbore with a plurality of coal seams 11 surrounded by matrix rock 12 in the rock structure 13 surrounding the wellbore 10.
- bridges 16 of solid material have formed between the rock structure 13 and the perforated casing 15. These bridges 16 act to prevent the free flow of fluid vertically within the annular cavity 17 formed between the casing 15 and the rock structure 13.
- coiled tubing 18 is introduced into the wellbore 10 and located in the RIH position adjacent the bottom of the wellbore 10. At least the upper member 19 (and optionally the lower member 20) are deactivated to improve the ease with which the coiled tubing 18 is run into the wellbore 10.
- a capillary line 21 is located within the coiled tubing 18, and the setting additive is pumped from the surface therethrough, while the settable fluid is pumped from the surface through the coiled tubing 18.
- Figure 2 illustrates a second step in a method for reducing solids migration into a wellbore 10 according to an embodiment of the present invention.
- an upper member 19 in the form of a packer is inflated (for instance using the setting additive pumped through the capillary line 21) so that the outer periphery of the upper member 19 extends to a point at or adjacent an inner surface of the perforated casing 15.
- the mixture introduced into the wellbore 10 through the injection tool 25 may exit the injection tool 25 between the upper member 19 and the lower member 20 at or adjacent to the perforated casing 15.
- the lower member 20 (which may be a packer, drag block or the like) may also be inflated or expanded.
- Figure 3 illustrates a third step in a method for reducing solids migration into a wellbore 10 according to an embodiment of the present invention.
- the settable fluid 22 is pumped through the coiled tubing and into a static mixer 23 located at the lower end of the coiled tubing 18.
- the setting additive is pumped through the capillary line 21 and is mixed with the settable fluid 22 in the static mixer 23 to produce a substantially homogenous mixture.
- Figure 4 illustrates a fourth step in a method for reducing solids migration into a wellbore 10 according to an embodiment of the present invention.
- the coiled tubing 18 has been retracted from the RIH position shown in Figure 1 , and the injection tool 25 has moved upwardly within the wellbore 10 in the direction of the upper end of the perforated casing 15.
- Figure 5 illustrates a final step in a method for reducing solids migration into a wellbore 10 according to an embodiment of the present invention.
- the coiled tubing 18 has been retracted to a point where the injection tool 25 is now above the upper end of the perforated casing 15.
- the introduction of the mixture 24 into the wellbore 10 is ceased.
- the presence of the setting additive in the mixture 24 significantly reduces the setting time of the mixture 24 in comparison to the setting time of the settable fluid alone. In this way, particularly in relatively depleted wells, the flow of the settable fluid into the coal seams 11 may be reduced or eliminated.
- the mixture 24 may substantially fill the annular cavity 17. However, it is possible, and may be desired, that some of the mixture 24 may remain inside the perforated casing 15. Mixture 24 that remains within the perforated casing 15 may be removed by milling or the like.
- coal seams 11 may be reconnected to the wellbore through the natural action of water, coal seam gas and/or solid material flowing out of the coal seams 11 and forming passageways through the mixture 24 so that water and coal seam gas may once again flow into the wellbore 10.
- passageways may be formed through the mixture 24 by perforating, hydraulically jetting, or abrading (and the like) the mixture 24 in order to reconnect the coal seams 11 with the wellbore 10.
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- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
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AU2022307366A AU2022307366A1 (en) | 2021-07-06 | 2022-07-05 | A method for performing chemical treatments in wellbores |
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AU2021902047A AU2021902047A0 (en) | 2021-07-06 | A method for performing chemical treatments in wellbores | |
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Citations (4)
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US20050016727A1 (en) * | 2003-07-25 | 2005-01-27 | Schlumberger Technology Corporation | [downhole sampling apparatus and method] |
US20120085539A1 (en) * | 2009-06-16 | 2012-04-12 | Agr | Well tool and method for in situ introduction of a treatment fluid into an annulus in a well |
US20130277047A1 (en) * | 2010-09-17 | 2013-10-24 | Schlumberger Technology Corporation | Downhole Delivery Of Chemicals With A Micro-Tubing System |
RU2498047C1 (en) * | 2012-06-01 | 2013-11-10 | Открытое акционерное общество "Татнефть" имени В.Д. Шашина | Method for making-up grouting compound in well |
-
2022
- 2022-07-05 AU AU2022307366A patent/AU2022307366A1/en active Pending
- 2022-07-05 WO PCT/AU2022/050695 patent/WO2023279148A1/en active Application Filing
Patent Citations (4)
Publication number | Priority date | Publication date | Assignee | Title |
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US20050016727A1 (en) * | 2003-07-25 | 2005-01-27 | Schlumberger Technology Corporation | [downhole sampling apparatus and method] |
US20120085539A1 (en) * | 2009-06-16 | 2012-04-12 | Agr | Well tool and method for in situ introduction of a treatment fluid into an annulus in a well |
US20130277047A1 (en) * | 2010-09-17 | 2013-10-24 | Schlumberger Technology Corporation | Downhole Delivery Of Chemicals With A Micro-Tubing System |
RU2498047C1 (en) * | 2012-06-01 | 2013-11-10 | Открытое акционерное общество "Татнефть" имени В.Д. Шашина | Method for making-up grouting compound in well |
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