Classifications

• • C—CHEMISTRY; METALLURGY
  • C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
  • C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
  • C04B28/00—Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements
  • C04B28/02—Compositions of mortars, concrete or artificial stone, containing inorganic binders or the reaction product of an inorganic and an organic binder, e.g. polycarboxylate cements containing hydraulic cements other than calcium sulfates
• • C—CHEMISTRY; METALLURGY
  • C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
  • C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
  • C04B26/00—Compositions of mortars, concrete or artificial stone, containing only organic binders, e.g. polymer or resin concrete
  • C04B26/02—Macromolecular compounds
  • C04B26/04—Macromolecular compounds obtained by reactions only involving carbon-to-carbon unsaturated bonds
  • C04B26/045—Polyalkenes
• • C—CHEMISTRY; METALLURGY
  • C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
  • C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
  • C04B26/00—Compositions of mortars, concrete or artificial stone, containing only organic binders, e.g. polymer or resin concrete
  • C04B26/30—Compounds having one or more carbon-to-metal or carbon-to-silicon linkages ; Other silicon-containing organic compounds; Boron-organic compounds
  • C04B26/32—Compounds having one or more carbon-to-metal or carbon-to-silicon linkages ; Other silicon-containing organic compounds; Boron-organic compounds containing silicon
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
  • C09K8/426—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells for plugging
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
  • C09K8/428—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells for squeeze cementing, e.g. for repairing
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
  • C09K8/44—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing organic binders only
• • C—CHEMISTRY; METALLURGY
  • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
  • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
  • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
  • C09K8/42—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells
  • C09K8/46—Compositions for cementing, e.g. for cementing casings into boreholes; Compositions for plugging, e.g. for killing wells containing inorganic binders, e.g. Portland cement
• • C—CHEMISTRY; METALLURGY
  • C04—CEMENTS; CONCRETE; ARTIFICIAL STONE; CERAMICS; REFRACTORIES
  • C04B—LIME, MAGNESIA; SLAG; CEMENTS; COMPOSITIONS THEREOF, e.g. MORTARS, CONCRETE OR LIKE BUILDING MATERIALS; ARTIFICIAL STONE; CERAMICS; REFRACTORIES; TREATMENT OF NATURAL STONE
  • C04B2103/00—Function or property of ingredients for mortars, concrete or artificial stone
  • C04B2103/0045—Polymers chosen for their physico-chemical characteristics
  • C04B2103/0062—Cross-linked polymers

Definitions

• the present disclosure is directed generally to apparatus, systems, and methods for well control, and plug such as may be useful in relation to a hydrocarbon well blowout event and more particularly to systems and methods pertaining to an interim intervention operation for an out of control well.
• Well control intervention systems and methods are generally classified as either conventional or unconventional.
• Conventional intervention systems are generally used when the well can be shut-in or otherwise contained and controlled by the wellbore hydrostatic head and/or surface pressure control equipment.
• unconventional well control intervention systems are generally used to attempt to regain control of flowing wells that cannot be controlled by the wellbore fluid and/or surface pressure control equipment.
• Such“blowout” situation may result from failure of downhole equipment, loss of wellbore hydrostatic control, and/or failure of surface pressure-control equipment.
• the object of regaining well control is to halt the flow of fluids (liquid and gas) from the wellbore, generally referred to as“killing” or“isolating” the well.
• Unconventional methods are more complex and challenging than conventional methods and frequently require use of multiple attempts and/or methods, often requiring substantial time investment, including sometimes drilling relief wells. Improved methods and systems for unconventional well control intervention are needed.
• Unconventional well control intervention methods include“direct” intervention, referring to intervention actions occurring within the wellbore and indirect intervention refers to actions occurring at least partially outside of the flowing wellbore, such as via a relief well.
• Two known unconventional direct intervention methods include a momentum weighted fluid methods and dynamic weighted fluid methods.
• Momentum weighted fluid methods rely upon introducing a relatively high density fluid at sufficient rate and velocity, directionally oriented in opposition to the adversely flowing well stream, so as to effect a fluid collision having sufficient momentum that the kill fluid overcomes the adverse momentum of the out of control fluid stream within the wellbore. Such process is commonly referred to as“out running the well.” This is often a very difficult process, especially when performed at or near the surface of the wellbore (e.g.,“top-weighted fluid”).
• Dynamic weighted fluid methods are similar to momentum weighted fluid methods except dynamic weighted fluid methods rely upon introduction of the weighted fluid stream into the wellbore at a depth such that hydrostatic and hydrodynamic pressure are combined within the wellbore at the point of introduction of the weighted fluids into the wellbore, thereby exceeding the flowing pressure of the blowout fluid in the wellbore and killing the well.
• Dynamic weighted fluid interventions are commonly used in relief well and underground blowout operations, but are also implemented directly in wellbores that contain or are provided with a conduit for introducing the weighted fluid into the wellbore relatively deep so as to utilize both hydrostatic and hydrodynamic forces against the flowing fluid.
• An efficient response system of equipment, material, and procedures is desired to provide interim well control intervention that at least temporarily impedes and perhaps even temporarily halts the uncontrolled flow of fluids from an out of control wellbore and provides a time cushion until a more permanent solution can be developed and implemented.
• Systems, equipment, and methods are disclosed herein that may be useful for intervention in a wellbore operation that has experienced a loss of hydrostatic formation pressure control, such as a blowout.
• the disclosed information may enable regaining some control of the well or at least mitigating the flow rate of the blowout, perhaps even temporarily halt the uncontrolled fluid flow.
• the disclosed control system may be relatively quickly implemented as an interim intervention mechanism to restrict or reduce effluent from the wellbore so as to provide a time-cushion until a permanent well control solution can be implemented.
• Systems, methods, and apparatus are also disclosed herein that may be useful for plugging and abandoning a portion or entirety of a wellbore.
• the disclosed technology may be useful to provide functional and/or operational improvements over prior plug forming technology such as cement-based plug-forming technology.
• Performance enhancements and material properties may provide more desirable options than was available in other technologies such as cement.
• the disclosed intervention system provides interim (non-permanent) well control systems and methods that may be relatively rapidly deployable and readily implemented relative to the time required to implement a more complex, permanent well control solution.
• conventional and/or other unconventional well control operations may subsequently or concurrently proceed in due course, even while the presently disclosed interim system functions concurrently to halt or at least constrict the well effluent flow rate in advance of or concurrently with preparation of the permanent or final solution.
• Plug and abandonment operations either in conjunction with a blowout event or as part of a traditional plug and abandonment operation.
• a primary aspect of the disclosed technology is introduction into the wellbore and/or wellbore supporting formation by a polymer (including resins) or polymer-forming compositions into the wellbore to create a polymer-containing plug (fluid-flow restriction) in the wellbore.
• the term“wellbore” broadly includes the borehole and any tubulars and compositions positioned therein.
• the methods disclosed herein may include systems, apparatus, and methods for controlling a well blowout comprising; a flow control device such as a blowout preventer on a wellbore; a control fluid aperture fluidly connected with the wellbore for introducing a control fluid comprising a monomer, polymer, or combination thereof, as a plug forming agent, (henceforth“plug-forming agent”) through a control fluid aperture and into the wellbore while wellbore fluid flows from the subterranean formation through the wellbore; a weighted fluid aperture positioned in the wellbore conduit below the control fluid aperture for introducing a weighted fluid into the wellbore while control fluid is also being introduced into the wellbore through the control fluid aperture.
• a flow control device such as a blowout preventer on a wellbore
• a control fluid aperture fluidly connected with the wellbore for introducing a control fluid comprising a monomer, polymer, or combination thereof, as a plug forming agent, (henceforth“plug
• the primary throughbore of the flow control devices comprising metal internal surfaces that may serve a polymerization sites or anchoring surfaces for a build-up of the plug-forming agent.
• the processes disclosed herein may include a method of performing a wellbore intervention operation to reduce an uncontrolled flow of wellbore blowout fluid from a subterranean wellbore, the method comprising: providing a flow control device, the flow control device engaged proximate a top end of a wellbore conduit that includes a wellbore throughbore, the flow control device including a primary throughbore coaxially aligned with and including a portion of the wellbore throughbore; providing a control fluid aperture proximate the top end of the wellbore conduit, the control fluid aperture being fluidly connected with the primary throughbore; providing a weighted fluid aperture in the wellbore throughbore at an upstream location in the wellbore throughbore with respect to the control fluid aperture and with respect to the direction of wellbore blowout fluid flow through the wellbore throughbore; introducing a control fluid through the control fluid aperture and into the wellbore throughbore while the wellbore blowout fluid flows from the subterran
• the method includes a method and system for creating polymer plugs within wellbores, the method comprising: providing a plug-forming agent at a selected location within a wellbore; providing a Grubbs-(Ru) (Ruthenium based) catalyst at the selected location within the wellbore; combining the plug-forming agent and Grubbs catalyst at the selected location within the wellbore for a polymerization reaction between the plug-forming agent and the Grubbs catalyst, to create a polymerized, cross-linked polymer plug at the selected location; and allowing the polymerization and cross-linking to cure into the polymer plug at the selected location within the wellbore.
• a plug-forming agent at a selected location within a wellbore
• a Grubbs-(Ru) Ruthenium based
• initial combining of the plug forming agent and the Grubbs catalyst may be conducted at surface, prior to being pumped into the wellbore, while in other methods the plug-forming agent and catalyst will be combined inside the wellbore. Either way, the combined materials are at some point combined within the wellbore, including the perforations and/or formation surrounding the wellbore.
• the method further comprising introducing a weighted fluid through the weighted fluid aperture and into the wellbore throughbore while pumping the control fluid through the control fluid aperture.
• the method further comprises introducing a weighted fluid through the weighted fluid aperture and into the wellbore throughbore after the wellbore blowout fluid has stopped flowing through the wellbore throughbore.
• the advantages disclosed herein may include an apparatus and system for performing a wellbore intervention operation to reduce an uncontrolled flow rate of wellbore blowout fluids from a subterranean wellbore, the apparatus comprising: at least one of a monomer and a polymer capable of at least one of polymerizing and crosslinking within the wellbore throughbore while within the wellbore throughbore; a flow control device, the flow control device engaged proximate a top end of a wellbore conduit that includes a wellbore throughbore at a surface location of the wellbore conduit, the flow control device including a primary throughbore that includes the wellbore throughbore, the primary throughbore coaxially aligned with the wellbore throughbore; a control fluid aperture proximate the top end of the wellbore conduit, the control fluid aperture being fluidly connected with the wellbore throughbore, the control fluid aperture positioned to introduce a control fluid into the primary throughbore concurrent with wellbore blowout
• control fluid aperture and/or the plug-forming agent aperture may be located in at least one of (i) the top end of the wellbore conduit, (ii) the flow control device, and (iii) a location intermediate (i) and (ii), the control fluid aperture being fluidly connected with the wellbore throughbore, the control fluid aperture for introducing a control fluid and the plugging agent into the wellbore throughbore.
• control fluid comprising the plug-forming agent may be introduced into the wellbore throughbore while a wellbore blowout fluid flows from the subterranean formation through the wellbore throughbore at a wellbore blowout fluid flow rate, whereby the control fluid is introduced at a control fluid introduction rate of at least 25% (by volume) of the wellbore blowout fluid flow rate from the wellbore throughbore prior to introducing the control fluid into the wellbore throughbore.
• control fluid comprising the plug-forming agent may be introduced into the wellbore throughbore while the wellbore blowout fluid has no flow rate due to the well flow being killed by prior and contemporaneous introduction of a preliminary control fluid into the wellbore throughbore.
• control fluid aperture and the plug-forming agent aperture are substantially the same aperture or set of apertures.
• the plug-forming agent aperture is separate from the control fluid aperture.
• the plug-forming aperture is preferably upstream of or below the control fluid aperture, with respect to the direction of blowout fluid flow from the subterranean formation and through the wellbore throughbore.
• a weighted fluid aperture may be provided in the wellbore throughbore positioned at an upstream location in the wellbore throughbore with respect to the control fluid aperture and with respect to direction of flow of wellbore blowout fluid flowing through the wellbore throughbore, the weighted fluid aperture capable to introduce a weighted fluid and/or the plugging agent into the wellbore throughbore while either a control fluid or a preliminary control fluid is introduced into the wellbore throughbore through the control fluid aperture.
• One objective of the presently disclosed technology is creating a pressure drop in the flowing blowout fluid within the primary throughbore by creating hydrodynamic conditions therein that approach the maximum fluid conducting capacity of the primary throughbore, by introducing control fluid and/or a plug-forming agent therein.
• a corresponding objective of the presently disclosed technology is to introduce a plug-forming agent into the wellbore throughbore to polymerize and/or crosslink therein and form a polymer and/or crosslinked plug or restriction within the wellbore throughbore to increase the pressure drop in the flowing blowout fluid within the primary throughbore, resulting in reduced or halted blowout fluid flow rate through the wellbore throughbore.
• the disclosed technology includes an apparatus for performing a wellbore intervention operation to reduce an uncontrolled flow rate of wellbore fluids from a subterranean wellbore, the apparatus comprising: a flow control device, the flow control device engaged proximate a top end of a wellbore conduit that includes a wellbore throughbore, the flow control device including a primary throughbore coaxially aligned with and comprising a portion of the wellbore throughbore; a control fluid aperture proximate the top end of the wellbore conduit, the control fluid aperture being fluidly connected with the primary throughbore; a plug-forming agent aperture in the wellbore throughbore at an upstream location in the wellbore throughbore with respect to the control fluid aperture and with respect to the direction of wellbore blowout fluid flow through the wellbore throughbore; a weighted fluid aperture for introducing a weighted fluid into the wellbore throughbore at an upstream location in the wellbore throughbore with respect to
• Successful implementation of the presently disclosed technology affords an additional method (in addition to the previously known prior art methods) to achieve some measure of control over the blowout fluid in reasonably accessible points of the wellbore conduit, commonly within the wellhead, marine riser, blowout preventer, or in proximity thereto.
• This additional measure of control may be achieved using readily portable equipment and without requiring introduction of a separate conduit or work string deep into the wellbore or requiring removal of an obstruction or string from therein.
• Successful implementation of the presently disclosed technology may thus supplement the well control or blowout intervention process, providing readily responsive action plan options and equipment that may afford at least a temporary plugging or constriction on the such as momentum or dynamic kills, cementing, or addition of a capping stack can be subsequently implemented.
• the improvements disclosed herewith may include polymerization-based and polymer-based wellbore-related plugging (fluid flow sealing, restricting, or isolating) methods, processes, applications, uses, systems, compositions, and/or apparatus developed in conjunction with the blowout control methods and systems disclosed herein.
• the improvements disclosed herewith include a method for creating polymer plugs within wellbores, the method comprising; combining a polymerizable plug forming agent and a Grubbs catalyst; locating the combined plug-forming agent and the Grubbs catalyst at a selected location within the wellbore for a polymerization reaction between the plug-forming agent and the Grubbs catalyst, to create a cross-linked polymer composition within the wellbore; and allowing the plug-forming agent and the Grubbs catalyst to polymerize into the polymer plug at the selected location within the wellbore.
• the improvements may further comprise providing the polymerizable plug-forming agent; providing the Grubbs catalyst; and combining the plug forming agent and the Grubbs catalyst within the wellbore.
• the disclosure further comprises: providing the polymerizable plug-forming agent; providing the Grubbs catalyst; combining the plug-forming agent and the Grubbs catalyst outside of the wellbore; and locating the combined plug-forming agent and Grubbs catalyst to the selected location within the wellbore.
• the plug forming agent comprises at least one of dicyclopentadiene, norborene, and combinations thereof.
• the method further comprises using at least one of (i) a Grubbs’ Ru- based ring opening metathesis (ROM) catalyst to create the polymer plug, and (ii) a Grubbs’ Ru-based ring opening metathesis polymerization (ROMP) catalyst to polymerize the at least one of the dicyclopentadiene, norborene, and combinations thereof.
• ROM Grubbs’ Ru-based ring opening metathesis
• REP Grubbs’ Ru-based ring opening metathesis polymerization
• the disclosed improvements may include wherein the plug forming agent comprises a siloxane.
• the improvements may include wherein the siloxane comprises alkoxy groups.
• the alkoxy groups may comprise at least one of methoxy groups and ethoxy groups.
• the siloxane crosslinks in the presence of water may include a polymerization reaction and/or chemical bonding of polymer chains.
• Some embodiments may include creating the polymer plug within a wellbore tubular positioned within the wellbore, such as within casing, tubing, drill-pipe, coil tubing, or a liner.
• the improvements may further comprise creating the polymer plug at least partially in an annular area external to a wellbore tubular positioned within the wellbore.
• Such operations may be affiliated, for example, with what is conventionally known in the art as a plug and abandonment operation, a primary cementing-type operations, a remedial cementing-type of job, and a completion cementing type of operation.
• plug is used broadly herein to include any type of creating a barrier to fluid flow or fluid communication
• the improvements may include but are not limited to not only conventionally setting a plug within a wellbore throughbore, but the term plug or plugging also includes using the disclosed polymer compositions in conjunction with cement (either mixed into or pumped distinct from the cement) or merely used in lieu of cement in an operation that would have otherwise been conventionally completed using merely cement.
• the disclosed polymer compositions may be used to enhance a cement plug by blending the polymer with the cement, or may be used wholly in the absence of cement thereby essentially acting as a substitute for cement.
• the disclosed improvements may further comprise creating the polymer plug in an openhole portion of the wellbore.
• the disclosed improvements may comprise creating the plug in area of the wellbore comprising at least one of a perforation and a cut in a wellbore tubular positioned within the wellbore.
• the polymer plug may be used in the wellbore during at least one of a drilling operation, a casing operation, a liner operation, completion operation, a recompletion operation, a primary cementing operation, and a staged cementing operation.
• Other implementations may further comprise hydraulically squeezing at least one of the plug-forming agent and the Grubbs catalyst into at least a portion of a subterranean formation containing the wellbore, while flowable, prior to fully polymerizing, crosslinking, or curing the polymer.
• Some improvements may comprise pumping the combined plug-forming agent and the Grubbs catalyst into a selected location within the wellbore as a spotted plug-forming polymer-based fluid using a wellbore tubular positioned within the wellbore; pulling the positioned wellbore tubular out of the selected positioning location within the wellbore such that the wellbore tubular is no longer positioned within the spotted polymer fluid; hydraulically pressurizing the wellbore to displace at least a portion of the spotted liquid polymer plug into at least one of the subterranean formation and an annular area within the wellbore, prior to fully curing the spotted polymer fluid as the cured cross-linked polymer.
• the providing of a Grubbs catalyst at the selected location within the wellbore comprises pumping the Grubbs catalyst to the desired location for combining the plug-forming agent and Grubbs catalyst at the selected location within the wellbore.
• the selected location within the wellbore comprises providing the plug in an annular region within the wellbore.
• cement has been the most common material used for plugging or sealing portions of a wellbore (internal and/or annular), such as during primary, secondary, or remedial cementing operations.
• the technical improvements disclosed herewith include using the polymers disclosed herein for plugging and such other cementing-type of sealing operations associated with cement, instead of cement or in combination with cement.
• embodiments of the technology disclosed herein may further comprise blending (mixing or otherwise combining) the plug-creating agent and the Grubbs catalyst with fluid cement (cement that is still flowable and pumpable).
• the blending may occur at surface or downhole.
• the plug-creating agent and the catalyst may be blended into the cement at the same time or separately, again, either at surface or downhole, with the reaction rate adjusted accordingly to enable time for plug locating and placement.
• Some aspects may comprise blending the plug-creating agent and the Grubbs catalyst with the fluid cement prior to pumping the combination downhole or may be combined at one location downhole and then pumped as a combination to the selected location or another selected location downhole.
• the selected location may include a location within the wellbore that at least partially comprises an annular region within the wellbore.
• the step of locating may comprise pumping the combination during at least one of a primary cementing operation, a staged cementing operation, and a liner cementing operation, an abandonment operation, a remedial cementing operation, a liner top squeezing cementing operation, and a plug-back cementing operation.
• Cement has been the most common plugging material used for many years. Cement’s capabilities and limitations are well understood. Some of its challenges are that it is brittle and can potentially fracture when exposed to stress that might occur over time. Other issues related to the use of cement include: cement requires time to cure and excessive retardation of hardening can delay operations; liquid cement can become contaminated by influx of gas or liquids that alter the desired properties; excessive density of the cement can result in losses to the formation and a plug not being of the required length; contact of the cement with water may cause shrinkage; and cement contamination with drilling mud can lead to seal failures.
• the presently disclosed plugging materials may provide more attractive options in some instances, for a plug that is long lasting, easily pumped and can move and fill small potential leak paths, performs at different temperatures and pressures, extremely low permeability once in place, non shrinking, ductile and non-brittle, resistant to downhole contaminants, has a controllable cure rate, and able to bond to the casing or formation where it is placed.
• Use of the presently disclosed polymer compositions may include, for example, plugging and abandoning a blow out well subsequent to regaining control over the blowout well.
• Other areas of technical improvement may include, for example plugging portions or all of a wellbore as part of a routine plugging operation, such as a plug and abandonment or during a drilling operation.
• the plugs created according to the technology disclosed herein may include a permanent plug such as for plugging and abandonment operations, or a temporary plug, such as for formation or fluid control, sand control, seal loss circulation zones, or seal off a water flow zone, or for structural wellbore stabilization, such as during drilling or completion operations.
• the plugging compositions may also be used to seal or squeeze off existing perforations or to hydraulically isolate one section of a wellbore, including an interior throughbore and/or an annular portion of the wellbore, from another section of the wellbore.
• the presently disclosed technology may include methods and systems for plugging portions or sections of a wellbore using systems including suitable liquid monomers, such as dicyclopentadiene (DCPD) or such as a functionalized norborene, and a Grubbs Catalyst (Ru) to create a polymer plug at a desired or controlled cure rate, resulting in a solid or rigid plug.
• suitable liquid monomers such as dicyclopentadiene (DCPD) or such as a functionalized norborene
• a Grubbs Catalyst a Grubbs Catalyst
• Fig. 1 is an exemplary schematic representation of a well control operation according to the present disclosure.
• Fig. 2 is also an exemplary schematic representation of a well control operation according to the present disclosure.
• Fig. 3 provides an exemplary representation of an exemplary polymerization reaction according to the present disclosure.
• Fig. 4 to Fig. 6 illustrate an exemplary sequential representation of a well stabilizing and/or a well plugging operation according to the present disclosure.
• Relatively rapid access to processes and apparatus for controlling and killing a well blowout may further benefit the oil and gas energy industry.
• the presently disclosed technology is believed to provide functional improvements and/or improved range of methodology options over previously available technology.
• Methods and equipment are disclosed that may provide effective interim control of blowout fluid flow from a wellbore such that a more permanent well killing operation may be performed subsequently or concurrently therewith.
• the presently disclosed well control operation methods may be applied in conjunction with performance of the long-term or “highly dependable” (permanent) kill operation.
• the presently disclosed interim technology may morph seamlessly from a“control” intervention operation into a permanent well killing operation.
• Figs. 1 and 2 are merely a general technical illustration of some aspects of application of the disclosed technology. Not all of the elements illustrated may be present in all embodiments or aspects of the disclosed technology and other embodiments may include varying component arrangements, omitted components, and/or additional equipment, without departing from the scope of the present disclosure.
• Figs. 1 and 2 are merely provides a simplified illustration of some of the basic components used in drilling or servicing subterranean wells, particularly offshore wells, in accordance with the presently disclosed well control technology.
• the presently disclosed technology involves creating a blockage or impedance of the wellbore blowout fluid flow rate through the wellbore, in proximity to the surface or seafloor, such as near the wellhead, by introducing a plug-forming agent and/or additional fluid (both the plug-forming agent and/or the optional additional fluid are referred to herein as a“control fluid”) into the flow stream at such rate and pressure as to create an increased backpressure in the wellhead throughbore that creates sufficient additional pressure drop in the flow control device throughbore that overcomes (all or at least 25% of) the flowing wellbore pressure of the blowout fluid flow rate through the wellhead.
• a plug-forming agent and/or additional fluid both the plug-forming agent and/or the optional additional fluid are referred to herein as a“control fluid”
• the control fluid may only comprise the plug-forming agent(s), the plug-forming agent and an additional fluid such as water, or both the plug-forming agent and the additional fluid.
• the plug-forming agent and the additional fluid may be introduced either together in the same introduction aperture(s), in separate apertures, and/or a combination of both so as to accommodate avoiding premature mixing of reactive components.
• control fluid is introduced in proximity of an upper or top end of the wellbore, such as into the wellhead, drilling spool, or in a lower portion of the blowout preventer, or in adjacent equipment such as well control devices (e.g., blowout preventers, marine risers, riser disconnects, master valves, etc.) that have an internal arrangement of components exposed to the wellbore that creates a relatively restrictive turbulence of control fluid and formation fluid therein.
• well control devices e.g., blowout preventers, marine risers, riser disconnects, master valves, etc.
• a plug-forming agent such as a polymer or monomer that can be polymerized and/or crosslinked may be introduced into the wellbore throughbore, either while the well is flowing blowout fluid, or after blowout fluid flow rate has been suspended or arrested, so as to create a polymer plug within the wellbore throughbore and/or related equipment.
• the control fluid comprises water, such as seawater, brine, or other relatively conveniently and abundantly available water.
• the plug-forming agent may be introduced in conjunction with introduction of another control fluid, either in the same introduction apertures or in separate apertures. Portions of the plug-forming agent may be mixed with the control fluid, such as portions that are non reactive with and compatible with the control fluid, such as the polymer, while other reactive portions are introduced separately from the control fluid or separately from the reactive portions of the plug-forming agent, such that polymerization reaction and/or crosslinking may occur within the wellbore throughbore, before the plug-forming agent is discharged by the blowout formation fluid from within the wellbore throughbore.
• the reaction kinetics therefore has to occur relatively quickly upon mixing in the wellbore.
• control fluid introduced into the wellbore prior to introduction of the plug-forming agent may be introduced into the wellbore throughbore (via either the same apertures as the previously or concurrently introduced control fluid or via separate apertures) to create or begin creating the polymer plug in the wellbore throughbore.
• Control fluid introduced into the wellbore throughbore for purposes of securing rate control on the wellbore blowout fluid flow rate, in advance of introducing the plug-forming agent or control fluid mixed with the plug-forming agent may for clarity purposes be referred to herein as the“preliminary” control fluid.
• the control fluid and the preliminary control fluid may substantially be the same fluid composition (e.g., comprised primarily of water, such as seawater) except for absence of the plug-forming agent in the preliminary control fluid.
• the control fluid introduction rate may be sufficiently high so as to hydrodynamically create a flowing wellhead pressure drop within the wellhead primary throughbore and/or related equipment due to the fluid mixing and turbulent flow patterns therein, that exceeds the formation fluid flowing pressure at that point of control fluid introduction into the wellbore.
• Addition of the plug-forming agent serves to additionally create a mechanical impediment to formation blowout fluid flow rate through the wellbore throughbore, by accumulating or building up on the wellbore throughbore surfaces.
• the objective may be to permit the plug-forming agent to act substantially without other rate reduction methods, such that the plug-forming agent builds up and gradually plugs off or constricts the blowout fluid flow rate without benefit of other blowout fluid rate restriction means.
• the well After plugging off the blowout fluid flow rate, the well may be permanently equipped and killed with cement or other permanent solutions.
• the common objective may be to create a desired constriction or back pressure in the wellbore throughbore so as to substantially impede, vastly reduce, or even halt flow of the wellbore blowout fluid from the wellbore.
• These well control operations may be subsequently continued after killing or controlling the well, while other operations to finally and permanently control the well are performed, such as pumping a weighted mud, cement, or another control fluid into the well to permanently kill the well.
• the weighted fluid also may comprise at least one of seawater, saturated brine, drilling mud, other polymer plugs, and cement.
• An advantage offered by the present technology is use of readily available and environmentally compatible water or seawater as the introduced well control fluid. For offshore wells or wells positioned on lakes or inland waterways, this creates essentially a limitless source of control fluid, as the control fluid is merely circulated through the system.
• a water source such as a bank of large tanks may be provided to facilitate circulating water from the tanks, into the primary throughbore, and back to the tanks or to another contained facility where the water may could be processed and reused.
• introducing seawater as the control fluid brings the added benefit of fire suppression and thermal reduction in event the effluent is on fire or has possibility of ignition.
• a heavier weighted fluid can then be introduced into the wellbore through a weighted fluid aperture.
• the weighted fluid aperture may preferably be positioned below the control fluid aperture.
• the weighted fluid can then fall by gravity through the wellbore blowout fluid in the wellbore and/or displace the blowout fluid as the weighted fluid moves down the wellbore and begins permanently killing the well blowout.
• Introducing the plug-forming agent into the wellbore throughbore may continue while the additional well killing operation of introducing the weighted fluid into the wellbore progresses.
• Introducing the weighted fluid in parallel with introducing the control fluid and/or plug-forming agent may continue until the wellbore is fully hydraulically stabilized and no longer has the ability to flow uncontrolled.
• the presently disclosed methods and systems have the advantage of being remotely operable from the rig, vessel or platform experiencing the blowout, as all operations may be performed from a workboat or other vessel that is safely distant from the blowout.
• the well-control system or operation will not be impacted by failure of the drilling rig.
• pumping seawater into the well control device as the control fluid not only provides an infinite source of control fluid, but also brings the advantage of adding firefighting water into the fuel in the event that the hydrocarbons are ignited after escaping onto the drilling rig.
• This system could save the rig, control the well, and if desired also provide means for introducing environmental-cleanup-aiding chemicals directly into the blowout effluent stream.
• Fig. 1 illustrates an exemplary equipment arrangement for a well control operation according to the present disclosure, whereby wellbore 50 is experiencing a well control event and an operation according to the present disclosure is employed to intervene and kill the flow of effluent from wellbore 50.
• a service vessel 72 is positioned safely apart from or remote offset from the rig 62 or well centerline 11.
• Exemplary vessel 72 may be loaded with equipment, pumps, tanks, lines, drilling mud, cement, and/or other additives as may be useful in the well control operation.
• Exemplary vessel 72 also provides pumps 32, 42 for introducing fluids into the wellbore 50 via pump lines 34 and 44.
• a wellbore 50 is located within a subterranean formation 60, whereby the wellbore is in fluid communication with a reservoir or formation containing sufficient formation fluid pressure to create a well control situation such as a blowout.
• Top side well control or operation-related equipment is positioned at several points along the wellbore 50 above the surface location (such as mudline 48 or water surface 74) including at water surface 74.
• Wellbore 50 is discharging the wellbore fluid 16 in an uncontrolled flow, from substantially any location downstream (above) of the wellhead pressure control devices 20.
• Wellbore fluid 16 may be escaping or discharged at substantially any location downstream from at least a portion of the well control surface equipment 20 or from the wellbore throughbore 12, such as near the mudline 48, on a rig or surface vessel 62 or therebetween.
• Fig. 1 illustrates the presence of a plurality of well control devices 20, such as a blowout preventer 26 (BOP), a lower marine riser package 52 (LMRP), and a marine riser 24.
• Well control device(s) 20 is (are) engaged with the top end 18 of wellbore 50.
• Wellbore 50 includes a wellbore conduit 10 defining a wellbore throughbore 12 therein, such as a well casing string(s).
• the collective components comprising the well control device 20 each include a primary throughbore 70 substantially coaxially aligned along a wellbore centerline 11 with the wellbore throughbore 12, but not necessarily having the same primary throughbore internal radial dimensions 28 as the wellbore conduit 10.
• the primary throughbore 70 may be irregular with respect to internal radial dimensions 28 between various components therein, such as pipe rams 88, wipers, master valves on a Christmas tree, plug profiles, and will possess varying internal surface roughness and dimensional variations so as to contribute to creation of turbulent fluid flow therein that under conditions of sufficiently high flow rate may create a substantial pressure drop therein that may impede the combined flow rate of formation blowout fluid and control fluid through the primary throughbore 70, thus aiding in creating enhance backpressure on wellbore 50, and reducing or halting effluent 16 flow.
• the disclosed technology includes a method of performing a well control intervention operation to reduce an uncontrolled flow of wellbore blowout fluids 16 such as a blowout from a subterranean wellbore 50.
• blowout is used broadly herein to include substantially any loss of well control ability from the surface, including catastrophic events as well as less-notorious occurrences, related to the inability of using surface pressure control equipment 20 to contain and control the flow of effluent fluid 16 from within a wellbore conduit 10 into the environment outside the well 50.
• the disclosed methods may comprise providing (either by addition to the wellbore or as a preexisting component of the wellbore assembly) at least one flow control device 20, such as a BOP 26, LMRP 52, Christmas tree valve arrangement, and snubbing equipment.
• BOP is used broadly herein to generally refer to the totality of surface or subsea well pressure or fluid controlling equipment present on the wellbore that comprises at least a portion of the wellbore throughbore 12 and which is typically appended to the top end 18 of the wellbore conduit 10 during an operation of, on, or within the well 50.
• the main internal well control device 20 throughbore 70 within the flow control devices may be referred to broadly herein as the primary throughbore 70.
• the wellbore throughbore 12 includes the primary throughbore 70.
• the well control device 20 is typically engaged with a top end 18 of the wellbore conduit 10 at a surface location of the wellbore conduit, such as at the seafloor mudline 48 (or land surface or platform or vessel surface).
• the primary throughbore 70 is coaxially aligned with the wellbore throughbore 12 and the primary throughbore 70 comprises internal dimensional irregularities such as constrictions and discontinuities, along the primary throughbore conduit 70 inner wall surfaces. These irregularities may be due to varying positions and dimensions related to internal components such as pipe rams, plug seats, master valves, or other internal features that may create a substantially discontinuous or irregular conduit path along the axial length of the primary conduit 70.
• a control fluid aperture(s) 30 is provided in proximity to the fluid control device 20, preferably located either in a lower half of the fluid control device 20 or at a point in the wellbore conduit 10 below (upstream with respect to the direction of blowout fluid flow) the fluid control device 20, such as in a drilling spool, a drilling choke-kill cross.
• the control fluid aperture 30 may include multiple numbers or variations of type and location of such apertures.
• the control fluid aperture 30 facilitates an entry location to introduce the control fluid and/or the plug-forming agent into the wellbore throughbore.
• control fluid apertures are sized such that the control fluid and/or plug-forming agent may be introduced at a desired or sufficient rate, volume, and/or pressure to impede or halt flow of formation fluid 16 through at least the portion of the wellbore throughbore or conduit below the control fluid aperture 30.
• the control fluid aperture 30 facilitates introducing a plug-forming agent alone or control fluid that includes the plug-forming agent, and including other control fluid components such as seawater, freshwater, drilling fluid, etc., into the wellbore throughbore 12 for increasing hydrodynamic fluid pressure and inertial energy within the primary throughbore 70 section of the wellbore throughbore 12 so as to arrest flow of blowout fluid.
• the control fluid aperture 30 may be provided in the top end 18 of the wellbore conduit 10, meaning substantially anywhere along the wellbore throughbore 12 above (uphole from) the bradenhead flange or mudline, wherein the control fluid aperture is also fluidly connected with the wellbore throughbore, or combinations thereof.
• the ports may be generally provided substantially perpendicular to the axis of the throughbore.
• the control fluid aperture 30 may be provided in at least one of (i) the top end of the wellbore conduit, (ii) the flow control device, and (iii) a location intermediate (i) and (ii), the control fluid aperture being fluidly connected with the wellbore throughbore, or combinations thereof.
• the disclosed technology provides a weighted fluid aperture 40 for introducing a weighted fluid into the wellbore below the control fluid aperture 30 to provide the hydrostatic control and containment of well effluent 16 from the wellbore 50.
• the term“below” means an upstream location in the wellbore throughbore with respect to direction of flow of wellbore blowout fluid 16 flowing through the throughbore 12.
• control fluid aperture may be located within a BOP body, between BOP rams, or in a drilling spool (choke-kill spool), or combinations thereof.
• Introducing a control fluid through the control fluid aperture 30 into the wellbore throughbore 12 while wellbore blowout fluid 16 flows from the subterranean formation 60 through the wellbore throughbore 12 may in some instances provide sufficient backpressure to both temporarily control and permanently control the well.
• the control fluid alone may perform to both temporarily control the well and with continued pumping also serve as the weighted fluid to fill the wellbore with control fluid and permanently kill the well.
• control fluid and/or plug-forming agent may be advantageous to introduce at least a portion or as much as possible of the control fluid and/or plug-forming agent into the primary through bore 20 as far upstream (low) as possible, such as in the lower half of the BOP 26, such as below BOP mid-line 15, without hydraulically interfering with introduction of the weighted fluid into the weighted fluid aperture 40.
• the presently disclosed technology also includes an apparatus and system for performing a wellbore intervention operation to reduce an uncontrolled flow rate of wellbore blowout fluids from a subterranean wellbore.
• a wellbore intervention operation to reduce an uncontrolled flow rate of wellbore blowout fluids from a subterranean wellbore.
• the apparatus or system may comprise a flow control device 20 mechanically and fluidly engaged (directly or including other components engaged therewith) with a top end of a wellbore conduit (generally the wellhead at the surface or mudline, but in proximity thereto such as in a conductor casing or other conduit in proximity to the mudline or surface) that includes a wellbore throughbore 12 at a surface location 48 of the wellbore conduit, the flow control device 20 including a primary throughbore 70 that is included within the wellbore throughbore 12, the primary throughbore 70 coaxially aligned with the wellbore throughbore 12 and the primary throughbore 70 comprising internal dimensional irregularities.
• a wellbore conduit generally the wellhead at the surface or mudline, but in proximity thereto such as in a conductor casing or other conduit in proximity to the mudline or surface
• the flow control device 20 including a primary throughbore 70 that is included within the wellbore throughbore 12, the primary throughbore 70 coaxially aligned with the
• Internal dimensional irregularities and like terms refers to the primary throughbore 70 having a non- uniform effective internal conduit-forming surfaces or internal cross-sectional area or internal diameter dimensions, along the axial length of the primary throughbore 70 as compared with the substantially uniform internal diameter of the wellbore conduit 10.
• the internal dimensions of the primary throughbore may be less than, greater than, or in some instances substantially the same as the internal diameter of the wellbore conduit 10.
• “Internal dimensional irregularities” variations include the internal component positional and size variations within the various apparatus, valves, BOP’s, etc., that comprise the primary throughbore 70 downstream from (above) the weighted fluid introduction aperture. Such diameter variations provide internal fluid flow-disrupting edges and shape inconsistencies along the axial length of the primary throughbore 70 that collectively may facilitate substantial turbulent flow and enhanced rate restriction, resulting in increased hydraulic pressure drop along the primary throughbore 70.
• the plug-forming agents may be monomers or polymers that attach to a metal site for polymerization or reaction, or otherwise mechanically or chemically bond (e.g., ionic or covalent) with the metal surface of the wellbore throughbore. It may be desirable in some applications to treat or prewash the metal surfaces before introducing the plug-forming agent, such as with a solvent, detergent, surfactant, acid, and/or steam to remove deposits such as paraffin, scale, gel, wax, paint, hydrocarbons, or other material that may block interaction or bonding between internal metal surfaces and the plug-forming agent.
• a solvent, detergent, surfactant, acid, and/or steam to remove deposits such as paraffin, scale, gel, wax, paint, hydrocarbons, or other material that may block interaction or bonding between internal metal surfaces and the plug-forming agent.
• Preliminary control fluid, control fluid, and/or plug-forming material may introduced into the wellbore throughbore in sufficient rate to create a substantial hydrodynamic pressure drop within the primary throughbore 70, such as a pressure drop of at least 10%, or at least 25%, or at least 50%, or at least 75%, or at least 100% from the previously estimated or determined flowing hydraulic pressure of the wellbore blowout fluid within the primary throughbore 70 before introduction of the control fluid therein.
• control fluid may commonly need to be introduced into the primary throughbore 12 at a control fluid introduction rate that is at least 25%, or at least 50%, or at least 100%, or at least 200% of the previously estimated or determined wellbore blowout fluid 16 flow rate from the wellbore throughbore 12 prior to introducing the control fluid into the wellbore throughbore 12.
• a weighted fluid such as weighted mud, cement, weighted kill fluid, or heavy brine may be introduced preferably through the weighted fluid aperture 40 and into the wellbore throughbore 12 while pumping the control fluid through the control fluid aperture 30.
• weighted fluid may be substantially the same fluid as the control fluid, or another weighted fluid, and the weighted fluid may comprise the plug forming agent.
• control fluid may include tailoring the control fluid.
• the control fluid may comprise at least one of carbon dioxide, nitrogen, air, methanol, another alcohol, NaCl, KC1, MgCl, another salt, and combinations thereof.
• plug-forming formulations e.g., mass-growing or accumulating
• Such plug-forming formulations may be comprise a combination of components that polymerize, deposit, react, mix, crosslink, or active when combined within the wellbore throughbore, either with each other and/or with the wellbore blowout fluid.
• the components comprising the plug-formulations formulations may be separately introduced into the wellbore throughbore for mixing therein and (relatively quickly) reacting therein while still located within the wellbore throughbore.
• Such plug-forming agent may also include chemical or true polymer formulations that are water or hydrocarbon activated compositions.
• the activated plug-forming agent(s) may accumulate or otherwise structurally build up within the primary throughbore, creating a flow path restriction, constriction, or full blockage of the fluid flow rate through the wellbore throughbore.
• Fibrous and/or granular solids such as nylons, Kevlar, durable materials, and/or fiberglass materials may also be concurrently introduced for enhancing the toughness or shear strength of the polymer accumulation within the primary throughbore 70.
• an apparatus, system, and/or method of performing a subterranean wellbore intervention operation to reduce an uncontrolled flow of wellbore blowout fluid from a subterranean wellbore comprising: providing a flow control device, the flow control device engaged proximate a top end of a wellbore conduit that includes a wellbore throughbore, the flow control device including a primary throughbore coaxially aligned with and comprising a portion of the wellbore throughbore; providing a control fluid aperture proximate the top end of the wellbore conduit, the control fluid aperture being fluidly connected with the primary throughbore; providing a weighted fluid aperture in the wellbore throughbore at an upstream location in the wellbore throughbore with respect to the control fluid aperture and with respect to the direction of wellbore blowout fluid flow through the wellbore throughbore; introducing a control fluid through the control fluid aperture and into the wellbore throughbore while the wellbore
• the plug-forming agent may, in some aspects be introduced into the wellbore in the form of a monomer, a polymer, and/or a polymer that can further polymerize and/or is crosslinkable, preferably within the time span with which the plug-forming agent is positioned within the wellbore throughbore and/or in components related thereto.
• a polymerization catalyst may be utilized with or provided with some plug-forming agents. The polymerization catalyst may mix with the monomer or polymer within the wellbore throughbore.
• the plug forming agent may comprise two components that are introduced separately into the wellbore to react within each other within the wellbore. In other embodiments, the plug-forming agent may comprise a component(s) that are reactive with the formation blow-out fluid.
• the plug-forming agent may comprise two or more components that are introduced separately into the wellbore to react with each other within the wellbore.
• plug forming is defined broadly herein to include polymerization and crosslinking, so as to form a substantially solid, plastic, or resinous plug within the wellbore throughbore.
• Other suitable states for the plug-forming agent may include stiff gels, scales, and elastomers.
• Crosslinking may be affected with or without a chemical cross-linking agent, such as by physical mixing.
• An exemplary plug-forming agent according to the present disclosure comprises a dicyclopentadiene (DCPD).
• DCDP may be crosslinked using a Grubbs’ Ru-based ring opening metathesis catalyst to crosslink the dicyclopentadiene (DCPD).
• the polymerization reaction may be effected relatively rapidly so as to occur within the short time-period within which the plug-forming agent is axially positioned within the wellbore throughbore. With proper choice of catalyst, the reaction may be tailored to occur at a specific temperature, such as at or above 50 degrees C.
• this solution can be pumped at relatively high rates into a flowing wellbore throughbore, such as through a control fluid port below a BOP to form a barrier to formation blowout fluid flow.
• the integrity of the formed plug may be enhanced, such as by including strengthening agents such as a cellulose bridging agent, a solid material, and/or fibrous materials that are mixed in the DCDP solution prior to injection.
• Another exemplary plug-forming agent includes a siloxane that may be polymerized and/or crosslinked.
• Siloxanes may be comprised of appropriate alkoxy groups, such as but not limited to MethOxy (MeO) groups and/or EthOxy (EtO) groups that may crosslink in the presence of water, such as in seawater, and eliminate the use of methanols or ethanols for crosslinking.
• MethOxy (MeO) groups and/or EthOxy (EtO) groups that may crosslink in the presence of water, such as in seawater, and eliminate the use of methanols or ethanols for crosslinking.
• the siloxane and water may require injection through separate lines if crosslinking conditions cause the crosslinking reaction to occur too quickly, or alternatively the siloxane may cross-link on contact with seawater during pumping for introduction in relatively shallow conditions where wellbore introduction timing is quicker.
• siloxane and water mix polymerization and/or crosslinking may occur, including both physical and chemical crosslinking.
• Thermal energy from the wellbore fluid may be utilized to catalyze or assist with the polymerization and crosslinking, such as at or above a desired temperature.
• the plug-forming agent may be heated or the water may be heated, or steam or another heated fluid, such as the control fluid, may be introduced into the wellbore throughbore to assist with polymerization and crosslinking.
• Bridging agents such as solids or fibers also may be utilized with the siloxanes to enhance plug strength.
• the resulting siloxane and water polymer product may react with or in contact with metal surfaces within the wellbore throughbore and create a buildup of a relatively hard, wellbore plug-forming agent.
• reaction product is built up until the buildup creates a blockage within the wellbore throughbore (particularly in proximity to the point of introduction of the plug-forming agent) sufficient to choke off or kill the flow of wellbore blowout fluid from the wellbore.
• control fluid including either the preliminary control fluid or the control fluid comprising the plug-forming agent
• a control fluid introduction rate sufficient to reduce the wellbore blowout fluid flow rate by determined amount, such as achieving a reduction of at least 10%, or 25%, or 50%, 75%, or 90%, or at least 100%, (by volume) with respect to the wellbore blowout fluid 16 flow rate through the wellbore throughbore 12 or primary throughbore 70, prior to introduction of the control fluid into the primary throughbore 70.
• One option for controlling the well while introducing the plug-forming agent is to hydrodynamically control the well through one group of control fluid ports, while introducing the plug-forming agent through a separate set of control fluid apertures, typically below or upstream of the former set of control fluid ports.
• the plug-forming agent may be introduced into a lower energy environment within the wellbore throughbore, than if the agent were introduced into the high-energy control fluid ports.
• Another option however, is to introduce the plug-forming agent into the higher energy control fluid ports to benefit from the mixing energy or as a consequence of limited number of control fluid introduction apertures.
• control fluid aperture 30 in at least one of (i) the top end of the wellbore conduit, (ii) the flow control device, and (iii) a location intermediate (i) and (ii), the control fluid aperture being fluidly connected with the wellbore throughbore.
• the control fluid aperture 30 facilitates introducing (such as by pumping or by gravitational flow) a control fluid into the wellbore throughbore 12 while a wellbore blowout fluid flows from the subterranean formation 60 through the wellbore throughbore 12 at a wellbore blowout fluid flow rate, whereby the control fluid is introduced at a control fluid introduction rate of at least 25% (by volume) of the estimated or determined wellbore blowout fluid flow rate was from the wellbore throughbore prior to introducing the control fluid into the wellbore throughbore.
• these and other rates referred to herein apply to the control fluid introduction process, either as a preliminary control fluid or a control fluid introduced in conjunction with introduction of the plug-forming fluid.
• a weighted fluid aperture 40 is also provided for introducing weighted fluid into the wellbore throughbore 12.
• the aperture 40 is positioned at an upstream location in the wellbore throughbore with respect to the control fluid aperture and with respect to direction of flow of wellbore blowout fluid flowing through the wellbore throughbore (e.g., the weighted fluid aperture 40 is generally positioned below the control fluid aperture 30 and in some embodiments the weighted fluid aperture 40 may be positioned below the fluid control device 20 or near a lower end of the fluid control device 20.
• the weighted fluid aperture 40 is sized and/or provided by sufficient number of apertures 40 to be capable to introduce a weighted fluid into the wellbore throughbore 12 while the control fluid is introduced into the wellbore primary throughbore 70 through the control fluid aperture 30, from a control fluid conduit line 34 and a control fluid pump 32.
• Flow control device 20 is a broad term intended to refer generally to the any of the pressure and/or flow control regulating devices associated with the top end 18 of the wellbore 50 that are positioned upon (above) the well 50, including equipment near a mudline 48, an earthen surface casing bradenhead flange, or other water surface, that may be used in conjunction with controlling wellbore pressure and/or fluid flow during a well operation.
• the collection and various arrangements of the flow control devices associated with the top end 18 generally defines the“primary throughbore” 20 portion of the wellbore throughbore 12.
• the top end 18 of the primary throughbore 70 comprises that portion of the well assembly above and mechanically connected with the wellbore bradenhead flange.
• Exemplary well operations using a flow control device include substantially any operation that may encounter wellbore pressure or flow, such as drilling, workover, well servicing, production, abandonment operation, and/or a well capping operation, and exemplary equipment includes at least one of a BOP 28, LMRP 52, at least a portion of a riser assembly, a production tree, choke/kill spool, and combinations thereof.
• the plugs formed according to the present disclosure will typically be formed within the flow control devices and related equipment, positioned substantially at or above ground level or above the sea floor in an offshore application. The interior portion of such equipment is considered as comprising a portion of the wellbore throughbore.
• the present apparatus or system also includes a control fluid conduit 34 and a control fluid pump 32 in fluid communication with the control fluid aperture 30.
• the control fluid conduits may comprise one or multiple lines as necessary, and may be utilized for conveyance and introduction of the plug-forming agent from a pump source and into a control fluid aperture.
• source fluid for the pump may be drawn from a fluid reservoir or water body, such as by using suction line 82 in fluid connection with the adjacent water source 80, such as the ocean, a freshwater source, large water tanks, etc.
• seawater or other readily available fluid as the control fluid whereby the blowout effluent is discharging into the ocean provides a substantially limitless source of environmentally compatible control fluid.
• control fluid introduction rate and duration are merely mechanical limitations that may be addressed or enhanced separately such as during planning stages for the well and equipment (e.g., control fluid aperture size and number of apertures available, pressure ratings, pump capacity, etc.).
• Multiple apertures fluidly connected with the wellbore throughbore 12 may be utilized as the control fluid apertures 30, at least some of which may be provided for other uses as well.
• the control fluid apertures 30 may be located substantially anywhere within and/or upstream of (below) the primary throughbore 70.
• a weighted fluid aperture 40 should be provided upstream of (below) the lower-most (closest) control fluid aperture 30.
• the most downstream (highest) weighted fluid aperture 40 is upstream of (below) the lower-most (closest) control fluid apertures 30, by at least 3 but more preferably at least 5 and even more preferably at least 7 wellbore conduit effective internal diameters of the wellbore blowout fluid 16 flow stream.
• the most upstream (lowest) control fluid aperture 30 is downstream of (with respect to the direction of flow of the wellbore blowout fluid) the highest (most upstream) weighted fluid aperture 40.
• the weighted fluid aperture 40 is upstream of (below) the nearest control fluid aperture 30, by at least 3, 5, or 7 internal diameters of the wellbore conduit throughbore 12.
• the introduced weighted fluid does not encounter the majority of the mixing and most turbulent hydraulic energy area imposed within the primary throughbore 70 portion of the wellbore throughbore 12. It may also be preferred in some aspects that the weighted fluid aperture 40 is positioned upstream (below) of the primary throughbore 70 portion of the wellbore throughbore 12, such as in proximity to the casing bradenhead flange or a spool positioned thereon.
• the weighted fluid aperture may in some instances be utilized for introduction of the plug-forming agent and/or a portion of the control fluid until such time as the well becomes plugged off, controlled, and killed, whereby it may become appropriate to then introduce a weighted fluid through the weighted fluid aperture.
• control fluid pump 32 and control fluid conduit 34 are capable of pumping control fluid through the control fluid aperture(s) 30 and into the wellbore throughbore 12 at a control fluid introduction rate of at least 25%, or at least 50%, or at least 100%, or at least 200% (by volume) of the wellbore blowout fluid flow rate through the wellbore throughbore 12 that was estimated or determined prior to introduction of the control fluid into the wellbore throughbore 12.
• the volumetric fraction of control fluid introduced therein at near maximum primary throughbore flow capacity that comprises the total fluid stream the lower the volumetric fraction of wellbore effluent 16 escaping into the environment from the wellbore 50.
• control fluid may be introduced through the weighted fluid aperture and into the wellbore throughbore while concurrently introducing (e.g., pumping) the control fluid through the control fluid aperture.
• the weighted fluid aperture 40 is positioned preferably below the control fluid aperture 30 and the weighted fluid aperture(s) is dimensioned to provide flow rate capacity to introduce weighted fluid into the wellbore throughbore at a rate whereby the weighted fluid falls through the stagnant or reduced velocity wellbore blowout fluid effluent flow rate through the wellbore throughbore 12.
• another fluid conduit 92 may be inserted into the primary throughbore 70, serving to (1) reduce the effective cross-sectional flow area of the primary throughbore due to the presence of the additional conduit therein, and (2) to introduce selectively, either additional control fluid into the primary throughbore 70 or to introduce weighted fluid into the wellbore throughbore 12.
• the additional conduit may facilitate an additional means for also directly taking measurements within the primary throughbore or wellbore conduit, such as the flowing fluid pressure at various points or depths along the primary throughbore 70 or in the wellbore throughbore 12.
• Introducing control fluid and/or the plug-forming agent into the primary throughbore 70 through the additional conduit 44a may supplement introduction of control fluid into the primary throughbore, through the control fluid aperture 30 in order to gain control or cessation of flow of formation fluids 19 from wellbore 50.
• control fluid is introduced into the primary throughbore from as many introduction points as available, including both the additional conduit 44a and through multiple control fluid apertures 30, in order to create sufficient pressure drop in the primary throughbore 70.
• introducing control fluid into the primary throughbore 70 through the additional conduit 44A may be performed in the absence of introducing control fluid into the primary throughbore using the control fluid aperture 40.
• Weighted fluid and/or plug-forming agent may be introduced into the wellbore conduit 10 using the weighted fluid aperture 40, the additional conduit 44a, or using both fluid aperture 40 and additional conduit 44a.
• Weighted fluid and/or the plug-forming agent may be introduced into the wellbore conduit 10 using the weighted fluid aperture 40, the additional conduit 44a, or using both fluid aperture 40 and additional conduit 44a.
• weighted fluid and/or plug-forming agent may be introduced (or further introduced) into the wellbore throughbore 50.
• the weighted fluid (and optionally including the plug-forming agent) may be introduced into the wellbore through bore 12 from the weighted fluid aperture 40 and/or into the wellbore throughbore 12 from the additional conduit 44a.
• At least a portion of the weighted fluid may be introduced into the wellbore throughbore 12 by a separate conduit 44a inserted through the wellbore throughbore 50 and into the wellbore conduit 10.
• at least a portion of the weighted fluid may be introduced into the wellbore conduit 10 from the top (downstream side) of the wellbore 50 or fluid control device 20
• the fluid discharge outlet of the additional conduit is positioned within or inserted into the wellbore throughbore 12 to a position at least 3, but more preferably, at least 5, and even more preferably, at least 7 wellbore conduit, and yet even more preferably, at least 10 effective internal diameters of the wellbore throughbore 12, below the control fluid aperture 30 that is closest to the top end of the wellbore conduit 10 (below the lowest control fluid aperture 30), such as below the control fluid aperture 30 closest to the casing bradenhead.
• the discharge outlet of the weighted fluid conduit 40 is upstream of (below) the nearest (lowermost) control fluid aperture 30, by at least 3, 5, or 7 internal diameters of the wellbore conduit throughbore 12.
• the weighted fluid is introduced into the wellbore throughbore 12 at a discharge or introduction point upstream of (below) the turbulent high pressure region created within the primary throughbore 70 that is being maintained by ongoing introduction of the control fluid therein.
• the weighted fluid may be introduced through separate conduit 44a alone, or concurrently in conjunction with the previously discussed introduction of wellbore blowout fluid through wellbore fluid aperture 40, such as through weighted fluid conduit 44b. In many instances, weighted fluid may be simultaneously introduced through both conduits 44a and 44b.
• One embodiment for forcing the separate conduit 44a into and through the primary throughbore 70 is use of a hydrajet or other type of fluid propulsion system, such as the exemplary illustrated hydrajet tool 92.
• Seawater may be pumped through well tubing 90, such as through coil tubing 93 or through jointed tubular pipe 91 such as drill pipe (either from rig 62 or other vessel 72), wherein the seawater provides propulsion force 31 to the hydra-jet tool 92.
• the hydrajet tool 92 may be provided with a rotating or steerable head 94 to help manipulate the tool 92 through the intricacies of the flow control devices 20.
• the hydraulic propulsion force 31 may be provided by substantially any convenient fluid, such as seawater or the control fluid.
• the hydra jet tool 92, well tubing 90 and separate conduit 44a may be moved by hydraulic propulsion force 31 from a position outside of the primary throughbore, such as illustrated at position A, into a proper position for introducing the weighted fluid 46 into the wellbore conduit 10, such as illustrated at position B.
• the weighted fluid 46 (for example) may be pumped such as from vessel 72, using pump 46, through line 44a, through tool 92 and into the wellbore throughbore 12 where the weighted fluid may fall through the wellbore blowout fluid within wellbore conduit 10, until the weighted fluid fills the wellbore 50 and the wellbore 50 becomes substantially depressurized (permanently controlled) at the top of the well 18.
• jointed tubing 91 such as drill pipe may be used in lieu of the hydrajet tool 92.
• the drill pipe may be weighted sufficiently to self- displace itself through the high-pressure primary throughbore 70 and into the wellbore.
• jointed tubing may be preferred over coil tubing for insertion into the wellbore throughbore 12 in order that the relatively stiff and relatively heavy jointed tubing 91 can be run through the primary throughbore 70 to a selected depth in the wellbore throughbore 12, such as to a depth in proximity to the point of loss of wellbore pressure integrity (either bottomhole or point experiencing an underground blowout).
• weighted fluid and/or plug-forming agent may be introduced using the additional conduit 44a to create a hydrostatic head above the point of casing or wellbore failure or rupture.
• Weighted fluid may be supplemented with flow-impeding materials, such as with weighting agents, crosslinkers, additional polymers, cement, and/or viscosifiers.
• fluid streams comprising or consisting of a plug-forming agent, either in conjunction with the control fluid or as the control fluid, including polymer formulations that activate within the primary throughbore to polymerize or otherwise react to create a plug-forming agent accumulation within the primary throughbore 70.
• Polymer formulations may be introduced into the primary throughbore either through the control fluid ports, and/or through the additional conduit 44a.
• weighted fluid may be introduced such as via either the additional conduit and/or the weighted fluid aperture to permanently kill the well.
• the presently disclosed technology may include methods and systems for plugging portions or sections of a wellbore.
• Exemplary operations may include plug and abandonments, recompletions, prevention of lost circulation during drilling operations, stabilizing bore hole walls during drilling, sealing off water or gas flow zones during drilling operations, and to squeeze off existing perforations, such as during completion or recompletion operations.
• Suitable polymer plugging systems include those using liquid monomers such as dicyclopentadiene (DCPD) and/or functionalized norborene, and a Grubbs Catalyst (Ru) to create a polymer plug at a desired or controlled cure rate, resulting in a solid or rigid plug.
• DCPD dicyclopentadiene
• Ru Grubbs Catalyst
• Grubbs’ Ru-based ring opening metathesis (ROM) and Grubbs Ru-based Ring opening metathesis polymerization (ROMP) processes are exemplary polymerization processes according to the presently disclosed technology.
• plug is used herein to broadly refer to a polymer barrier to hydraulic communication or flow within or adjacent to a wellbore, the polymer barrier being created according to the present disclosure, and positioned at a selected location(s) along the length of the wellbore, including within tubulars positioned within the borehole, open hole sections, annular areas, perforations connected therewith, and/or within combinations thereof.
• the created polymer plugs may be utilized for permanent plugging operations, such as for plugging and abandonment operations.
• the created polymer plugs also may be utilized for remedial or temporary plugging operations, such as for formation stabilization or fluid control, sand control, sealing off lost circulation zones, sealing off a water flow zones, and for structural wellbore stabilization, such as during drilling or completion operations.
• the polymer plugs also may be used to seal or squeeze off existing perforations or to hydraulically isolate one section of a wellbore from another, including an interior throughbore and/or an annular portion of the wellbore, from another section of the wellbore.
• the disclosed polymer compositions may be desirable to combine or mix with other functional materials, such as fluid-loss control particulates to mitigate premature or excessive loss of the liquid polymer into the formation or annulus prior to the polymer setting up or crosslinking in the desired locations.
• the improved methods disclosed herein also may include using the disclosed polymers combined with cement such as to enhance certain properties of the cement. Combinations with materials such as cement may provide enhanced material properties for operations such as forming an improved seal for plug and abandonment, or to squeeze a casing leak in a collar, or to squeeze off perforations.
• the disclosed polymers Prior to the polymer crosslinking or otherwise reacting, the disclosed polymers may exhibit flow properties that are more Newtonian and less viscous than liquid cement, thereby flowing into tighter flowpaths than cement alone otherwise might.
• the activated and crosslinked polymer is formed in situ by combining suitable polymerizable liquid monomers (such as dicyclopentadiene (DCPD) or norborene) with a liquid Grubbs catalyst (Nguyen et al. 2000; Grubbs 2006)) at or near the location of use.
• suitable polymerizable liquid monomers such as dicyclopentadiene (DCPD) or norborene
• a liquid Grubbs catalyst Non-opentadiene
• the ring opening metathesis polymerization (ROMP) or ring opening metathesis reactions of the DCPD and/or functionalized norborene, with the Grubbs catalyst are illustrated in exemplary Figure 3.
• Plug forming agent monomers or polymers, such as DCPD 302 and/or norborene 304 are activated into a polymerization reaction with the Grubbs Catalyst 306 to form the polymer plug 300.
• the reaction time may be adjusted such that the combined plugging agent polymer and catalyst may be squeezed into the perforations, fractures, leaks, annulus, removal of pipe from within the spotted column of polymer and catalyst, etc., intended for plugging, prior to the reaction progressing polymerization to the state where the material becomes too viscous or immobile.
• the reaction initiation rate also may be altered by replacing certain ligands with more labile or reactive ligands, such as replacing the phosphine ligand with pyridine ligands.
• the reacting or cross-linking of the polymer results in a solid material that bonds well to metal and exhibits toughness properties and resistance to shear properties that may be desirable in many plugging or sealing applications related to use in wellbores and/or subsurface formations.
• the presently disclosed technology includes a method for creating plugs within subterranean wellbores and related equipment, in an exemplary embodiment the method comprising: providing a plug-forming agent at a selected location within a wellbore; providing a Grubbs catalyst at the selected location within the wellbore; combining the plug-forming agent and Grubbs catalyst at the selected location within the wellbore for a polymerization reaction between the plug-forming agent and the Grubbs catalyst, to create a cross-linked polymer at the selected location; and allowing the cross-linked polymer to cure into the plug at the selected location within the wellbore.
• Grubbs’ catalysts may be utilized for the initiators for the plug-forming operations as disclosed herewith, but the ring-opening metathesis (ROM) and especially ring-opening metathesis polymerization (ROMP) are of particular interest.
• the plug-forming agent may comprise a liquid monomer, such as dicyclopentadiene or norborene, utilizing a polymerization reaction initiating catalyst, such as but not limited to Grubbs’ Ru-based (Ruthenium-based) ring opening metathesis polymerization (ROMP) catalyst to crosslink the liquid monomer.
• a polymerization reaction initiating catalyst such as but not limited to Grubbs’ Ru-based (Ruthenium-based) ring opening metathesis polymerization (ROMP) catalyst to crosslink the liquid monomer.
• the Grubbs Ru catalysts may include any of the first, second, and third generation catalysts, depending upon the desire reaction rate and conditions.
• the plug-forming agent may comprise a siloxane, and the siloxane may comprise, for example, alkoxy groups, which may include, for example at least one of methoxy groups and ethoxy groups.
• the siloxane may crosslink in the presence of water for some applications or may be designed to crosslink in the presence of a catalyst such as the Grubb’s Ru-base catalyst.
• a catalyst such as the Grubb’s Ru-base catalyst.
• crosslinking as used herein may include polymerization, chemical bonding, and traditional polymer strand physical intermeshing.
• Polymer plugs as disclosed herein may be formed within the throughbore of a wellbore tubular, such as within a casing, liner, tubing or drill pipe, in an annular space between tubular strings, in the annular space between a tubular string and the bore hole wall, and combinations thereof.
• the presently disclosed plugs also may be formed within a subterranean formation, such as in natural or created fractures, within a formation matrix, within perforations, and/or within an area of loss circulation.
• the plugs also may be created as required during well abandonment processes, at top and bottom of certain zones, at locations of jet cut or perforated tubulars, or in conjunction with primary cementing jobs.
• the disclosed methods may also comprise hydraulically squeezing the plug-forming agent and the Grubbs catalyst and the cross-linking monomer or polymer into at least a portion of a subterranean formation supporting the wellbore, either subsequent to combining or prior to combining the polymer and catalyst, prior to fully curing the cross-linked polymer.
• an exemplary plug-setting process may include steps comprising: pumping the plug-forming agent and the Grubbs catalyst into a selected location in the wellbore as a spotted polymer fluid using a wellbore tubular positioned within the wellbore; moving the wellbore tubular out of the selected location within the wellbore such that the wellbore tubular is not positioned within the spotted polymer fluid; hydraulically pressurizing the spotted polymer fluid within the wellbore to displace at least a portion of the spotted polymer fluid into at least one of the subterranean formation and an annular area within the wellbore, prior to fully curing the spotted polymer fluid as the cured cross-linked polymer.
• Figures 4 through 6 illustrate an exemplary workflow for spotting a plug for formation stabilization and lost circulation during a drilling operation.
• Figure 4 illustrates a drill bit 302 drilling wellbore 50 and encountering a network of lost circulation zones 312, 314, 316.
• Figure 5 illustrates that a polymer plug according to the present disclosure is spotted in the wellbore and displaced at least partially into subterranean formation 80 and into the high porosity lost circulation zones 312, 314, and 316. Note that the drill bit 302 has been pulled up above and out of the spotted plug, subsequent to pumping the plug forming agent and catalyst into the troubled part 312, 314, and 316 of the formation 80.
• FIG. 6 illustrates the drill bit 302 drilling through the portion of the plug 300 that remained within wellbore 50. The lost circulation zones have been plugged off and the formation 80 stabilized by polymer plug 300 such that drilling to deeper depths may continue.
• FIG. 4 Although exemplary Figures 4 through 6 are illustrated at or near bohom hole in the wellbore 50, for other wellbore operations such as well completion, workover, plug- and-abandonment, or drilling, a similar procedure of (i) spohing the plug-forming agent and catalyst at a desired location, (ii) pulling the spohing tubing out of the spohed but not yet polymerized mixture, (iii) displacing the mixture into the formation, perforations, or annulus if necessary, (iv) allowing polymerization of the plug to from in situ, and (v) then moving to the next step in the wellbore operation procedure may be executed at substantially any depth or location along the length of the wellbore where a plugging operation is required.
• the term“and/or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity.
• Multiple entities listed with“and/or” should be construed in the same manner, i.e.,“one or more” of the entities so conjoined.
• Other entities may optionally be present other than the entities specifically identified by the“and/or” clause, whether related or unrelated to those entities specifically identified.
• a reference to“A and/or B,” when used in conjunction with open-ended language such as“comprising” may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, to both A and B (optionally including other entities).
• These entities may refer to elements, actions, structures, steps, operations, values, and the like.
• the phrase“at least one,” in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities.
• This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase“at least one” refers, whether related or unrelated to those entities specifically identified.
• “at least one of A and B” may refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities).
• each of the expressions“at least one of A, B and C,”“at least one of A, B, or C,”“one or more of A, B, and C,”“one or more of A, B, or C” and“A, B, and/or C” may mean A alone, B alone, C alone, A and B together, A and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity.
• phrase“etc.” is not limiting and is used herein merely for convenience to illustrate to the reader that the listed examples are not exhaustive and other members not listed may be included. However, absence of the phrase“etc.” in a list of items or components does not mean that the provided list is exhaustive, such that the provided list still may include other members therein.
• the terms“adapted” and“configured” mean that the element, component, or other subject matter is designed and/or intended to perform a given function.
• the use of the terms“adapted” and“configured” should not be construed to mean that a given element, component, or other subject matter is simply“capable of’ performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function.
• elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa.
• the phrase,“for example,” the phrase,“as an example,” and/or simply the term“example,” when used with reference to one or more components, features, details, structures, embodiments, and/or methods according to the present disclosure, are intended to convey that the described component, feature, detail, structure, embodiment, and/or method is an illustrative, non-exclusive example of components, features, details, structures, embodiments, and/or methods according to the present disclosure.

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