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US20180238133A1 - Sharp and erosion resistance degradable material for slip buttons and sliding sleeve baffles - Google Patents

Sharp and erosion resistance degradable material for slip buttons and sliding sleeve baffles Download PDF

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Publication number
US20180238133A1
US20180238133A1 US15/754,449 US201515754449A US2018238133A1 US 20180238133 A1 US20180238133 A1 US 20180238133A1 US 201515754449 A US201515754449 A US 201515754449A US 2018238133 A1 US2018238133 A1 US 2018238133A1
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United States
Prior art keywords
wellbore
metal
dissolvable metal
dissolvable
isolation device
Prior art date
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US15/754,449
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English (en)
Inventor
Michael L. Fripp
Zach Walton
Thomas FROSELL
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Halliburton Energy Services Inc
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Individual
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Assigned to HALLIBURTON ENERGY SERVICES, INC. reassignment HALLIBURTON ENERGY SERVICES, INC. ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: FRIPP, MICHAEL LINLEY, FROSELL, Thomas, WALTON, Zach
Publication of US20180238133A1 publication Critical patent/US20180238133A1/en
Abandoned legal-status Critical Current

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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B29/00—Cutting or destroying pipes, packers, plugs or wire lines, located in boreholes or wells, e.g. cutting of damaged pipes, of windows; Deforming of pipes in boreholes or wells; Reconditioning of well casings while in the ground
    • E21B29/02—Cutting or destroying pipes, packers, plugs or wire lines, located in boreholes or wells, e.g. cutting of damaged pipes, of windows; Deforming of pipes in boreholes or wells; Reconditioning of well casings while in the ground by explosives or by thermal or chemical means
    • C—CHEMISTRY; METALLURGY
    • C22—METALLURGY; FERROUS OR NON-FERROUS ALLOYS; TREATMENT OF ALLOYS OR NON-FERROUS METALS
    • C22C—ALLOYS
    • C22C21/00—Alloys based on aluminium
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
    • E21B23/01—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for anchoring the tools or the like
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • E21B33/129—Packers; Plugs with mechanical slips for hooking into the casing
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • E21B33/129—Packers; Plugs with mechanical slips for hooking into the casing
    • E21B33/1293—Packers; Plugs with mechanical slips for hooking into the casing with means for anchoring against downward and upward movement
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/063—Valve or closure with destructible element, e.g. frangible disc
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/10—Valve arrangements for boreholes or wells in wells operated by control fluid supplied from outside the borehole
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
    • E21B2200/06—Sleeve valves
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
    • E21B2200/08—Down-hole devices using materials which decompose under well-bore conditions
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B34/00—Valve arrangements for boreholes or wells
    • E21B34/06—Valve arrangements for boreholes or wells in wells
    • E21B34/14—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools
    • E21B34/142—Valve arrangements for boreholes or wells in wells operated by movement of tools, e.g. sleeve valves operated by pistons or wire line tools unsupported or free-falling elements, e.g. balls, plugs, darts or pistons
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures

Definitions

  • the present disclosure generally relates to a sharp and erosion-resistant degradable material used in a component in a downhole tool, and a method of using said degradable material. More particularly, the sharp and erosion-resistant degradable material includes a dissolvable metal matrix composite wherein the dissolvable metal matrix composite includes a dissolvable metal and a dispersed reinforcement material wherein the dissolvable metal is capable of dissolving via galvanic corrosion.
  • fracturing plugs are designed for these general purposes and are well known in the art of producing hydrocarbons, such as oil and gas.
  • Such wellbore isolation devices may be used in direct contact with the formation face of the wellbore, with a casing string extended and secured within the wellbore, or with a screen or wire mesh.
  • Removing the wellbore isolation device may allow hydrocarbon production operations to commence without being hindered by the presence of the downhole tool.
  • Removing wellbore isolation devices is traditionally accomplished by a complex retrieval operation that involves milling or drilling out a portion of the wellbore isolation device, and subsequently mechanically retrieving its remaining portions.
  • a tool string having a mill or drill bit attached to its distal end is introduced into the wellbore and conveyed to the wellbore isolation device to mill or drill out the wellbore isolation device.
  • the remaining portions of the wellbore isolation device may be grasped onto and retrieved back to the surface with the tool string for disposal.
  • this retrieval operation can be a costly and time-consuming process.
  • FIG. 1 is a well system that employs the metal matrix composite in accordance with the principles of the present disclosure.
  • FIG. 2 is a cross-sectional side view of an exemplary frac plug that can employ the metal matrix composite in accordance with the principles of the present disclosure
  • FIG. 3 is an example of a sliding sleeve that employs the metal matrix composite in accordance with the principles of the present disclosure
  • FIG. 4 is an example of a metal matrix composite in accordance with the principles of the present disclosure.
  • FIG. 5 is a micrograph of an example of a metal matrix composite in accordance with the principles of the present disclosure.
  • any use of any form of the terms “connect,” “engage,” “couple,” “attach,” or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described.
  • the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to”. Unless otherwise indicated, as used throughout this document, “or” does not require mutual exclusivity.
  • a hydraulic coupling, connection, or communication between two components describes components that are associated in such a way that fluid pressure may be transmitted between or among the components.
  • Reference to a fluid coupling, connection, or communication between two components describes components that are associated in such a way that a fluid may flow between or among the components.
  • Hydraulically coupled, connected, or communicating components may include certain arrangements where fluid does not flow between the components, but fluid pressure may nonetheless be transmitted such as via a diaphragm or piston.
  • the present disclosure generally relates to a sharp and erosion resistant degradable material used in a component in a downhole tool and a method of using said degradable material, and more particularly, to a dissolvable metal matrix composite.
  • a “fluid” may include a substance having a continuous phase that tends to flow and to conform to the outline of its container when the substance is tested at a temperature of 71° F. (22° C.) and a pressure of one atmosphere “atm” (0.1 megapascals “MPa”).
  • a fluid may be a liquid or gas.
  • a homogenous fluid has only one phase, whereas, a heterogeneous fluid has more than one distinct phase.
  • a heterogeneous fluid may be: a slurry, which includes a continuous liquid phase and undissolved solid particles as the dispersed phase; an emulsion, which includes a continuous liquid phase and at least one dispersed phase of immiscible liquid droplets; a foam, which includes a continuous liquid phase and a gas as the dispersed phase; or a mist, which includes a continuous gas phase and a liquid as the dispersed phase.
  • a heterogeneous fluid will have only one continuous phase, but may have more than one dispersed phase. It is to be understood that any of the phases of a heterogeneous fluid (e.g., a continuous or dispersed phase) may contain dissolved or undissolved substances or compounds.
  • base fluid is the liquid that is in the greatest concentration in the wellbore fluid and is the solvent of a solution or the continuous phase of a heterogeneous fluid.
  • a well can include, without limitation, an oil, gas, or water production well, or an injection well.
  • a “well” includes at least one wellbore.
  • a wellbore can include vertical, inclined, and horizontal portions, and it can be straight, curved, or branched.
  • the term “wellbore” includes any cased, and any uncased, open-hole portion of the wellbore.
  • a near-wellbore region is the subterranean material and rock of the subterranean formation surrounding the wellbore.
  • a “well” also includes the near-wellbore region. The near-wellbore region is generally considered to be the region within approximately 100 feet radially of the wellbore.
  • “into a well” means and includes into any portion of the well, including into the wellbore or into the near-wellbore region via the wellbore.
  • a portion of a wellbore may be an open hole or cased hole.
  • a tubing string may be placed into the wellbore.
  • the tubing string allows fluids to be introduced into or flowed from a remote portion of the wellbore.
  • a casing is placed into the wellbore that can also contain a tubing string.
  • a wellbore can contain an annulus.
  • annulus examples include, but are not limited to: the space between the wellbore and the outside of a tubing string in an open-hole wellbore; the space between the wellbore and the outside of a casing in a cased-hole wellbore; and the space between the inside of a casing and the outside of a tubing string in a cased-hole wellbore.
  • a zone is an interval of rock differentiated from surrounding rocks on the basis of its fossil content or other features, such as faults or fractures. For example, one zone can have a higher permeability compared to another zone. It is often desirable to treat one or more locations within multiples zones of a formation.
  • One or more zones of the formation can be isolated within the wellbore via the use of an isolation device to create multiple wellbore intervals. At least one wellbore interval corresponds to a formation zone.
  • the isolation device can be used for zonal isolation and functions to block fluid flow within a tubular, such as a tubing string, or within an annulus.
  • the blockage of fluid flow prevents the fluid from flowing across the isolation device in any direction and isolates the zone of interest. In this manner, treatment techniques can be performed within the zone of interest.
  • the term “sealing ball,” and grammatical variants thereof refers to a spherical or spheroidal element designed to seal perforations of a wellbore isolation device that are accepting fluid, thereby diverting reservoir treatments to other portions of a target zone.
  • An example of a sealing ball is a frac ball in a frac plug wellbore isolation device.
  • the term “packer element” refers to an expandable, inflatable, or swellable element that expands against a casing or wellbore to seal the wellbore.
  • wellbore isolation device is a device that is set in a wellbore to isolate a portion of the wellbore thereabove from a portion therebelow so that fluid can be forced into the surrounding subterranean formation above the device.
  • Common wellbore isolation devices include, but are not limited to, a ball and a seat, a bridge plug, a packer, and a plug. It is to be understood that reference to a “ball” is not meant to limit the geometric shape of the ball to spherical, but rather is meant to include any device that is capable of engaging with a seat.
  • a “ball” can be spherical in shape, but can also be a dart, a bar, or any other shape. Zonal isolation can be accomplished via a ball and seat by dropping or flowing the ball from the wellhead onto the seat that is located within the wellbore. The ball engages with the seat, and the seal created by this engagement prevents fluid communication into other wellbore intervals downstream of the ball and seat.
  • the relative term “downstream” means at a location further away from a wellhead.
  • the wellbore can contain more than one ball seat.
  • a seat can be located within each wellbore interval.
  • the inner diameter (I.D.) of the ball seats is different for each zone.
  • the I.D. of the ball seats sequentially decreases at each zone, moving from the wellhead to the bottom of the well.
  • a smaller ball is first dropped into a first wellbore interval that is the farthest downstream; the corresponding zone is treated; a slightly larger ball is then dropped into another wellbore interval that is located upstream of the first wellbore interval; that corresponding zone is then treated; and the process continues in this fashion—moving upstream along the wellbore—until all the desired zones have been treated.
  • the relative term “upstream” means at a location closer to the wellhead.
  • a bridge plug is composed primarily of slips, a plug mandrel, and a rubber sealing element.
  • a bridge plug can be introduced into a wellbore and the sealing element can be caused to block fluid flow into downstream intervals.
  • a packer generally consists of a sealing device, a holding or setting device, and an inside passage for fluids. A packer can be used to block fluid flow through the annulus located between the outside of a tubular and the wall of the wellbore or inside of a casing
  • dissolvable and all of its grammatical variants (e.g., “degrade,” “degradation,” “degrading,” “dissolve,” dissolving,” and the like), refers to the dissolution or chemical conversion of solid materials such that reduced-mass solid end products by at least one of solubilization, hydrolytic degradation, chemical reactions (including electrochemical and galvanic reactions), thermal reactions, reactions induced by radiation, or combinations thereof.
  • a “degradable or dissolvable metal” may refer to a metal that has a certain rate of dissolution, and the rate of dissolution may correspond to a rate of material loss at a particular temperature and within particular wellbore conditions.
  • an “electrolyte” is any substance containing free ions (i.e., a positively or negatively charged atom or group of atoms) that make the substance electrically conductive.
  • the electrolyte can be selected from the group consisting of, solutions of an acid, a base, a salt, and combinations thereof.
  • a salt can be dissolved in water, for example, to create a salt solution.
  • Common free ions in an electrolyte include, but are not limited to, sodium (Na+), potassium (K + ), calcium (Ca 2 ⁇ ), magnesium (Mg 2+ ), chloride (Cl ⁇ ), bromide (B ⁇ ) hydrogen phosphate (HPO 4 2 ), hydrogen carbonate (HCO 3 ⁇ ), and any combination thereof.
  • the electrolyte contains chloride ions.
  • Galvanic corrosion occurs when two different metals or metal alloys are in electrical connectivity with each other and both are in contact with an electrolyte.
  • electrical connectivity means that the two different metals or metal alloys are either touching or in close enough proximity to each other such that when the two different metals are in contact with an electrolyte, the electrolyte becomes electrically conductive and ion migration occurs between one of the metals and the other metal, and is not meant to require an actual physical connection between the two different metals, for example, via a metal wire.
  • metal is meant to include pure metals and also metal alloys without the need to continually specify that the metal can also be a metal alloy.
  • metal or metal alloy in one sentence or paragraph does not mean that the mere use of the word “metal” in another sentence or paragraph is meant to exclude a metal alloy.
  • metal alloy means a mixture of two or more elements, wherein at least one of the elements is a metal. The other element(s) can be a non-metal or a different metal.
  • An example of a metal and non-metal alloy is steel, comprising the metal element iron and the non-metal element carbon.
  • An example of a metal and metal alloy is bronze, comprising the metallic elements copper and tin.
  • the degradation of the dissolvable metal matrix composite or dissolvable metal may be sufficient for the mechanical properties of the metal to be reduced to a point that the metal no longer maintains its integrity and, in essence, falls apart or sloughs off into its surroundings.
  • the conditions for degradation are generally wellbore conditions where an external stimulus may be used to initiate or effect the rate of degradation, where the external stimulus is naturally occurring in the wellbore (e.g., pressure, temperature) or introduced into the wellbore (e.g., fluids, chemicals).
  • the pH of the fluid that interacts with the material may be changed by introduction of an acid or a base.
  • wellbore environment includes both naturally occurring wellbore environments and materials or fluids introduced into the wellbore.
  • At least a portion with reference to degradation (e.g., “at least a portion of the mandrel is degradable” or “at least a portion of the degradable packer element is degradable,” and variants thereof) refers to degradation of at least about 80% of the volume of that part.
  • the present disclosure describes embodiments of a component in a downhole tool (e.g., wellbore isolation device) that is made of a dissolvable metal matrix composite.
  • a component in a downhole tool e.g., wellbore isolation device
  • the present disclosure describes having a variety of components including, e.g., a baffle seats, a shear pin, a slip button, a mandrel, a sealing ball, and an expandable or inflatable packer element.
  • the degradable wellbore isolation devices may include e.g., frac plugs. Having a component for wellbore isolation device be made out of a dissolvable metal matrix composite would facilitate an easier disposal of the component without an expensive or labor intensive procedure to remove said component from the wellbore system.
  • the dissolvable metal matrix composite consists essentially of a dissolvable metal and a dispersed reinforcement material wherein the dissolvable metal is capable of dissolving via galvanic corrosion when the dissolvable metal is in presence of an electrolyte.
  • the dispersed reinforcement material may include a ceramic or a hardened metal.
  • the dissolvable metal matrix composite consists essentially of a dissolvable metal and a disperse reinforcement material wherein the dissolvable metal is capable of dissolving via dissolution when the dissolvable metal is in the presence of water.
  • the dissolvable metal forms a galvanic couple with the dispersed reinforcement material.
  • the dissolvable metal that may be used in accordance with the embodiments of the present disclosure includes galvanically-corrodible or degradable metals and metal alloys. Such metals and metal alloys may be configured to degrade via an electrochemical process in which the galvanically-corrodible metal corrodes in the presence of an electrolyte (e.g., brine or other salt-containing fluids present within the wellbore).
  • the electrolyte can be a fluid that is introduced into the wellbore or a fluid emanating from the wellbore, such as from a surrounding subterranean formation.
  • the degradability of the dissolvable metal matrix composite can be accelerated by creating galvanic couples within the dissolvable metal matrix composite. There are two paths for accelerating the corrosion: 1) alloying the dissolvable metal with copper, nickel, carbon, or iron, or 2) replacing part of the ceramic with cathodic nuggets.
  • the dissolvable metal may be alloyed with copper, nickel, or iron as a solid solution.
  • the copper, nickel, or iron creates inclusions that have a galvanic potential that accelerates the corrosion of the metal.
  • a part of the ceramic may be replaced with a cathodic component that creates a galvanic potential with the metal matrix.
  • the galvanic coupling may be generated by embedding or attaching a cathodic substance or piece of material into an anodic component.
  • the cathodic component could be a nugget, a spheroid, a sliver, a fiber, or a weave.
  • the cathodic component could be any material that creates a galvanic potential with the metal matrix.
  • the cathodic components include copper, nickel, steel, or graphite (carbon).
  • Other options may include platinum, silver, zirconium, titanium, iron, bronze, chromium, tin, or their alloys.
  • the galvanic coupling may be generated by dissolving aluminum in gallium.
  • the metal that is less noble, compared to the other metal, will dissolve in the electrolyte.
  • the less noble metal is often referred to as the anode, and the more noble metal is often referred to as the cathode.
  • Galvanic corrosion is an electrochemical process whereby free ions in the electrolyte make the electrolyte electrically conductive, thereby providing a means for ion migration from the anode to the cathode—resulting in deposition formed on the cathode.
  • Metals can be arranged in a galvanic series. The galvanic series lists metals in order of the most noble to the least noble.
  • An anodic index lists the electrochemical voltage (V) that develops between a metal and a standard reference electrode (gold (Au)) in a given electrolyte.
  • the actual electrolyte used can affect where a particular metal or metal alloy appears on the galvanic series and can also affect the electrochemical voltage. For example, the dissolved oxygen content in the electrolyte can dictate where the metal or metal alloy appears on the galvanic series and the metal's electrochemical voltage.
  • the anodic index of gold is ⁇ 0 V; while the anodic index of beryllium is ⁇ 1.85 V.
  • a metal that has an anodic index greater than another metal is more noble than the other metal and will function as the cathode.
  • the metal that has an anodic index less than another metal is less noble and functions as the anode.
  • the anodic index of the lesser noble metal is subtracted from the other metal's anodic index, resulting in a positive value.
  • the rate of galvanic corrosion There are several factors that can affect the rate of galvanic corrosion.
  • One of the factors is the distance separating the metals on the galvanic series chart or the difference between the anodic indices of the metals.
  • beryllium is one of the last metals listed at the least noble end of the galvanic series and platinum is one of the first metals listed at the most noble end of the series.
  • tin is listed directly above lead on the galvanic series.
  • the difference between the anodic index of gold and beryllium is 1.85 V; whereas, the difference between tin and lead is 0.05 V. This means that galvanic corrosion will occur at a much faster rate for magnesium or beryllium and gold compared to lead and tin.
  • the temperature and concentration of the electrolyte Another factor that can affect the rate of galvanic corrosion is the temperature and concentration of the electrolyte. The higher the temperature and concentration of the electrolyte, the faster the rate of corrosion In an embodiment of the present disclosure, the temperature of the wellbore system may be increased or decreased based on volume of the wellbore fluid being pumped into the wellbore system.
  • anodic metal is the total amount of surface area of the least noble (anodic metal).
  • the cross-sectional size of the anodic metal pieces can be decreased in order to increase the total amount of surface area per total volume of the material.
  • the anodic metal or metal alloy can also be a matrix in which pieces of cathode material is embedded in the anode matrix.
  • Yet another factor that can affect the rate of galvanic corrosion is the ambient pressure. Depending on the electrolyte chemistry and the two metals, the corrosion rate can be slower at higher pressures than at lower pressures if gaseous components are generated. Yet another factor that can affect the rate of galvanic corrosion is the physical distance between the two different metal and/or metal alloys of the galvanic system.
  • the dissolvable metal may include gold, gold-platinum alloys, silver, nickel, nickel-copper alloys, nickel-chromium alloys, copper, copper alloys (e.g., brass, bronze, etc.), chromium, tin, aluminum, aluminum alloys, iron, zinc, magnesium, magnesium alloys, beryllium, any alloy of the aforementioned materials, and any combination thereof.
  • the dissolvable metal may include an aluminum alloy that is alloyed with gallium.
  • the gallium acts as a depassivating agent and prevents the formation of a protective passivation layer on the surface of the aluminum.
  • Indium and tin also act as depassivating agents and help to prevent passivation on the aluminum.
  • Examples of aluminum-gallium alloys include 80% aluminum-20% gallium, 80% Al-10% Ga-10% In, 75% Al-5% Ga-5% Zn-5% Bi-5% Sn-5% Mg, and 90% Al-2.5% Ga-2.5% Zn-2.5% Bi-2.5% Sn. Another example is 99.8% Al-0.1% In-0.1% Ga.
  • the dissolvable metal may include an aluminum alloy that is alloyed with copper, with manganese, with silicon, with magnesium, with iron, with lithium, carbon, and/or with zinc.
  • Example of aluminum alloy with copper is a 2024 aluminum which includes 92% Al-.5% Si-0.5% Fe-4.5% Cu-0.5% Mn-1.5% Mg-0.1% Cr-0.25% Zn-0.15% Ti.
  • the dissolvable metal may include a magnesium alloy that is alloyed with zinc, aluminum, yttrium, copper, nickel, cerium, and/or iron.
  • a magnesium alloy that is alloyed with aluminum is AZ 91 magnesium which includes 90.8% Mg-8.25% Al-0.63% Zn-0.035% Si-0.22% Mn.
  • ZK 61 is Another example of a magnesium alloy that is alloyed with zinc which includes 95% Mg-5% Zn-0.3% Zr.
  • Magnesium alloys may include at least one other ingredient besides the magnesium.
  • the other ingredients can be selected from one or more metals, one or more non-metals, or a combination thereof.
  • Suitable metals that may be alloyed with magnesium include, but are not limited to, lithium, sodium, potassium, rubidium, cesium, beryllium, calcium, strontium, barium, aluminum, gallium, indium, tin, thallium, lead, bismuth, scandium, titanium, vanadium, chromium, manganese, iron, cobalt, nickel, copper, zinc, yttrium, zirconium, niobium, molybdenum, ruthenium, rhodium, palladium, praseodymium, silver, lanthanum, hafnium, tantalum, tungsten, terbium, rhenium, osmium, iridium, platinum, gold, neodymium, gadolinium, erb
  • Suitable non-metals that may be alloyed with magnesium include, but are not limited to, graphite, carbon, silicon, boron nitride, and combinations thereof.
  • the carbon can be in the form of carbon particles, fibers, nanotubes, fullerenes, and any combination thereof.
  • the graphite can be in the form of particles, fibers, weaves, graphene, and any combination thereof.
  • the magnesium and its alloyed ingredient(s) may be in a solid solution and not in a partial solution or a compound where inter-granular inclusions may be present.
  • the magnesium and its alloyed ingredient(s) may be uniformly distributed throughout the magnesium alloy but, as will be appreciated, some minor variations in the distribution of particles of the magnesium and its alloyed ingredient(s) can occur.
  • the magnesium alloy is a sintered construction.
  • the magnesium alloy may have a yield stress in the range of from about 10,000 pounds per square inch (psi) to about 50,000 psi, encompassing any value and subset therebetween.
  • the magnesium alloy may have a yield stress of about 20,000 psi to about 30,000 psi, or about 30,000 psi to about 40,000 psi, or about 40,000 psi to about 50,000 psi, encompassing any value and subset therebetween.
  • Suitable aluminum alloys may include alloys having aluminum at a concentration in the range of from about 40% to about 99% by weight of the aluminum alloy, encompassing any value and subset therebetween.
  • suitable aluminum alloys may have aluminum concentrations of about 40% to about 50%, or about 50% to about 60%, or about 60% to about 70%, or about 70% to about 80%, or about 80% to about 90%, or about 90% to about 99% by weight of the aluminum alloy, encompassing any value and subset therebetween.
  • the aluminum alloys may be wrought or cast aluminum alloys and comprise at least one other ingredient besides the aluminum.
  • the other ingredients can be selected from one or more any of the metals, non-metals, and combinations thereof described above with reference to magnesium alloys, with the addition of the aluminum alloys additionally being able to comprise magnesium.
  • the degradable or dissolvable metal for use in the embodiments described herein may also include micro-galvanic metals or materials, such as, for example, solution-structured galvanic materials.
  • a solution-structured galvanic material is a magnesium alloy containing zinc (Zn), where different domains within the alloy contain different percentages of Zn. This leads to a galvanic coupling between these different domains, which cause micro-galvanic corrosion and degradation.
  • Micro-galvanically corrodible magnesium alloys could also be solution structured with other elements such as zinc, aluminum, manganese, nickel, cobalt, calcium, iron, carbon, tin, silver, copper, titanium, rare earth elements, etc.
  • solution-structured micro-galvanically-corrodible magnesium alloys include ZK60, which includes about 4% to about 7% zinc, about 0% to about 1% zirconium, about 0% to about 3% other, and balance magnesium; AZ80, which includes 7% to 10% aluminum, 0% to 1% zinc, 0% to 1% manganese, 3% other, and balance magnesium; and AZ31, which includes 2% to 5% aluminum, 0% to 2% zinc, 0% to 1% manganese, 3% other, and the balance magnesium.
  • ZK60 which includes about 4% to about 7% zinc, about 0% to about 1% zirconium, about 0% to about 3% other, and balance magnesium
  • AZ80 which includes 7% to 10% aluminum, 0% to 1% zinc, 0% to 1% manganese, 3% other, and balance magnesium
  • AZ31 which includes 2% to 5% aluminum, 0% to 2% zinc, 0% to 1% manganese, 3% other, and the balance magnesium.
  • “other” may
  • the dispersed reinforcement material may include ceramic components or particles.
  • the ceramic components may be constructed from zirconia (including zircon), alumina (including fused alumina, chrome-alumina, and emery), carbide (including tungsten carbide, silicon carbide, titanium carbide, and boron carbide), boride (including boron nitride, osmium diboride, rhenium boride, titanium boride, and tungsten boride), nitride (silicon nitride and aluminum nitride), synthetic diamond, and silica.
  • the ceramic may be an oxide (like the alumina and zirconia) or a non-oxide (like the carbide, nitride, and boride).
  • the dispersed reinforcement material may include e.g., a particle, a fiber, a weave, a nugget, and the like.
  • the dissolvable metal matrix composite may be considered to be a cermet.
  • a hardened metal may be used instead of the ceramic.
  • a medium or high carbon steel with a carbon content in excess of 0.25% could be used.
  • a maraging steel, a stainless steel, Inconel, tool steel, titanium, nickel, tungsten, chromium, or alloys of any of these materials may also be used.
  • the dissolvable metal matrix composite includes a dispersed reinforcement material and a dissolvable metal wherein the dispersed reinforcement material may include tungsten carbide ceramic with graphite particles in a mold, and the dissolvable metal may include aluminum.
  • the aluminum alloy will be a degradable alloy that binds together the tungsten carbide and the graphite particles.
  • the graphite Upon exposure to an electrolyte, the graphite will galvanically react with the aluminum, and the aluminum will disappear, leaving behind a ceramic dust and graphite dust.
  • This degradable or dissolvable metal matrix composite is best suited for slip buttons on dissolvable frac plugs as well as for baffle seat on sliding sleeves.
  • the dissolvable metal matrix composite of the present disclosure fulfills the need for the slip buttons to have the sharpness and the baffle seat to have the erosion resistance while facilitating easier and cost efficient degradation of the slip buttons and baffle seat in the wellbore system.
  • the dissolvable metal matrix composite may include about 20 to about 95 weight percent of the dispersed reinforcement material, and may be most typically about 50 to about 70 weight percent of the dispersed reinforcement material.
  • the dissolvable metal matrix composite may include up to about 95 weight percent of the dissolvable metal.
  • the dissolvable metal matrix composite may include a dissolvable metal that exhibits a degradation rate in an amount greater than 10 mg/cm 2 per hour at a temperature of 200° F. (93.3° C.) while exposed to a 15% potassium chloride (KCI) solution.
  • KCI potassium chloride
  • the degradation rate of the dissolvable metal may be somewhat slower, such that the dissolvable metal exhibits a degradation rate in an amount of less than about 10 mg/cm 2 per hour at 200° F. (93.3° C.) in 15% KCI solution. In other embodiments, the dissolvable metal exhibits a degradation rate such that lower than about 10% but greater than 1% of its total mass is lost per day at 200° F. (93.3° C.) in 15% KCI solution.
  • the degradation of the dissolvable metal may be in the range of from about 1 day to about 120 days, encompassing any value or subset therebetween.
  • the degradation may be about 5 days to about 10 days, or about 10 days to about 20 days, or about 20 days to about 30 days, or about 30 days to about 120 days, encompassing any value and subset therebetween.
  • Each of these values representing the degradable metal may depend on a number of factors including, but not limited to, the type of degradable or dissolvable metal, the wellbore environment, and the like.
  • the dissolvable metal matrix composite may include at least one tracer.
  • the tracer(s) can be, without limitation, radioactive, chemical, electronic, physical, or acoustic.
  • a tracer can be useful in determining real-time information on the rate of dissolution dissolvable metal.
  • a dissolvable metal containing a tracer upon dissolution can be flowed through the wellbore and towards the wellhead or into the subterranean formation.
  • workers at the surface can make on-the-fly decisions that can affect the rate of dissolution of the remaining dissolvable metal. Such decisions might include to increase or decrease the concentration of the electrolyte or to increase or decrease the pH of the electrolyte.
  • the dissolution of the dissolvable metal may also be accelerated by hydraulically fracturing with an acid or otherwise augmenting the wellbore fluid with an acid.
  • all or a portion of the outer surface of a given component of the wellbore isolation device may be treated or coated with a substance configured to enhance degradation of the dissolvable metal
  • a treatment or coating may be configured to remove a protective coating or treatment or otherwise accelerate the degradation of the dissolvable metal.
  • An example is a galvanically-corroding metal coated with a layer of polyglycolic acid (PGA).
  • PGA polyglycolic acid
  • the PGA would undergo hydrolysis and cause the surrounding fluid to become more acidic, which would accelerate the degradation of the underlying dissolvable metal.
  • the well system 100 may include a service rig 102 (also referred to as a “derrick”) that is positioned on the earth's surface 104 and extends over and around a wellbore 106 that penetrates a subterranean formation 108 .
  • the service rig 102 may be a drilling rig, a completion rig, a workover rig, or the like.
  • the service rig 102 may be omitted and replaced with a standard surface wellhead completion or installation, without departing from the scope of the disclosure.
  • While the well system 100 is depicted as a land-based operation, it will be appreciated that the principles of the present disclosure could equally be applied in any sea-based or sub-sea application where the service rig 102 may be a floating platform or sub-surface wellhead installation, as generally known in the art.
  • the wellbore 106 may be drilled into the subterranean formation 108 using any suitable drilling technique and may extend in a substantially vertical direction away from the earth's surface 104 over a vertical wellbore portion 110 .
  • the vertical wellbore portion 110 may deviate from vertical relative to the earth's surface 104 and transition into a substantially horizontal wellbore portion 112 , although such deviation is not required. That is, the wellbore 106 may be vertical, horizontal, or deviated, without departing from the scope of the present disclosure.
  • the wellbore 106 may be completed by cementing a string of casing 114 within the wellbore 106 along all or a portion thereof.
  • casing refers not only to casing as generally known in the art, but also to borehole liner, which comprises tubular sections coupled end to end but not extending to a surface location. In other embodiments, however, the string of casing 114 may be omitted from all or a portion of the wellbore 106 and the principles of the present disclosure may equally apply to an “open-hole” environment.
  • the well system 100 may further include a wellbore isolation device 116 that may be conveyed into the wellbore 106 on a conveyance 118 (also referred to as a “tool string”) that extends from the service rig 102 .
  • the wellbore isolation device 116 may include or otherwise comprise any type of casing or borehole isolation device known to those skilled in the art including, but not limited to, a frac plug, a deployable baffle, a wellbore packer, a wiper plug, a cement plug, or any combination thereof.
  • the conveyance 118 that delivers the wellbore isolation device 116 downhole may be, but is not limited to, wireline, slickline, an electric line, coiled tubing, drill pipe, production tubing, or the like.
  • the wellbore isolation device 116 may be conveyed downhole to a target location (not shown) within the wellbore 106 . At the target location, the wellbore isolation device may be actuated or “set” to seal the wellbore 106 and otherwise provide a point of fluid isolation within the wellbore 106 . In some embodiments, the wellbore isolation device 116 is pumped to the target location using hydraulic pressure applied from the service rig 102 at the surface 104 . In such embodiments, the conveyance 118 serves to maintain control of the wellbore isolation device 116 as it traverses the wellbore 106 and provides the necessary power to actuate and set the wellbore isolation device 116 upon reaching the target location. In other embodiments, the wellbore isolation device 116 freely falls to the target location under the force of gravity to traverse all or part of the wellbore 106 .
  • FIG. 1 depicts the wellbore isolation device 116 as being arranged and operating in the horizontal portion 112 of the wellbore 106
  • the embodiments described herein are equally applicable for use in portions of the wellbore 106 that are vertical, deviated, or otherwise slanted.
  • a plurality of wellbore isolation devices 116 may be placed in the wellbore 106 .
  • several wellbore isolation devices 116 may be arranged in the wellbore 106 to divide the wellbore 106 into smaller intervals or “zones” for hydraulic stimulation.
  • FIG. 2 illustrated is a cross-sectional view of an exemplary wellbore isolation device 200 that may employ one or more of the principles of the present disclosure, according to one or more embodiments.
  • the wellbore isolation device 200 may be similar to or the same as the wellbore isolation device 116 of FIG. 1 . Accordingly, the wellbore isolation device 200 may be configured to be extended into and seal the wellbore 106 at a target location, and thereby prevent fluid flow past the wellbore isolation device 200 for wellbore completion or stimulation operations.
  • the wellbore 106 may be lined with the casing 114 or another type of wellbore liner or tubing in which the wellbore isolation device 200 may suitably be set. In other embodiments, however, the casing 114 may be omitted and the wellbore isolation device 200 may instead be set or otherwise deployed in an uncompleted or “open-hole” environment.
  • the wellbore isolation device 200 is generally depicted and described herein as a hydraulic fracturing plug or “frac” plug. It will be appreciated by those skilled in the art, however, that the principles of this disclosure may equally apply to any of the other aforementioned types of casing or borehole isolation devices, without departing from the scope of the disclosure. Indeed, the wellbore isolation device 200 may be any of a frac plug, a bridge plug, a wellbore packer, a deployable baffle, a ball and seat, a cement plug, or any combination thereof in keeping with the principles of the present disclosure.
  • the wellbore isolation device 200 may include a ball cage 204 extending from or otherwise coupled to the upper end of a mandrel 206 .
  • a sealing ball 208 e.g., a frac ball
  • the mandrel 206 defines a longitudinal central flow passage 210 .
  • the mandrel 206 also defines a ball seat 212 at its upper end.
  • One or more spacer rings 214 may be secured to the mandrel 206 and otherwise extend thereabout.
  • the spacer ring 214 provides an abutment, which axially retains a set of upper slips 216 a that are also positioned circumferentially about the mandrel 206 .
  • a set of lower slips 216 b may be arranged distally from the upper slips 216 a.
  • the lower slips 216 b may include a lower slip button 215 b wherein the slip button 215 b may include a sharp edge 217 b which is configured to bite into the casing 114 .
  • the upper slips 216 a may include an upper slip button 215 a wherein the slip button 215 a may include a sharp edge 217 a which is configured to bite into the casing 114 .
  • the sealing ball 208 may be dropped into the conveyance 118 ( FIG. 1 ) to land on top of the wellbore isolation device 200 rather than being carried within the ball cage 204 .
  • the slip buttons 215 a and 215 b may be composed of the dissolvable (or degradable) metal matrix composite in accordance with the principles of the present disclosure, thereby allowing an easier and cost efficient disposal of the slip buttons 215 a and 215 b in the wellbore.
  • One or more slip wedges 218 may also be positioned circumferentially about the mandrel 206 , and a packer assembly consisting of one or more expandable or inflatable packer elements 220 may be disposed between the upper and lower slip wedges 218 a,b and otherwise arranged about the mandrel 206 .
  • a packer assembly consisting of one or more expandable or inflatable packer elements 220 may be disposed between the upper and lower slip wedges 218 a,b and otherwise arranged about the mandrel 206 .
  • the particular packer assembly depicted in FIG. 2 is merely representative as there are several packer arrangements known and used within the art. For instance, while three packer elements 220 are shown in FIG. 2 , the principles of the present disclosure are equally applicable to wellbore isolation devices that employ more or less than three packer elements 220 , without departing from the scope of the disclosure.
  • a mule shoe 222 may be positioned at or otherwise secured to the mandrel 206 at its lower or distal end.
  • the lower most portion of the wellbore isolation device 200 need not be a mule shoe 222 , but could be any type of section that serves to terminate the structure of the wellbore isolation device 200 , or otherwise serves as a connector for connecting the wellbore isolation device 200 to other tools, such as a valve, tubing, or other downhole equipment.
  • At least a portion of the mandrel 206 (such as the interior surface) or at least a portion of the spacer ring 214 or mule shoe 222 (such as the exterior surface) may be composed of the dissolvable (or degradable) metal matrix composite in accordance with the principles of the present disclosure, thereby allowing more erosion resistance or abrasion resistance of the component.
  • a spring 224 may be arranged within a chamber 226 defined in the mandrel 206 and otherwise positioned coaxially with and fluidly coupled to the central flow passage 210 . At one end, the spring 224 biases a shoulder 228 defined by the chamber 226 and at its opposing end the spring 224 engages and otherwise supports the sealing ball 208 .
  • the ball cage 204 may define a plurality of ports 230 (three shown) that allow the flow of fluids therethrough, thereby allowing fluids to flow through the length of the wellbore isolation device 200 via the central flow passage 210 .
  • the spring 224 prevents the sealing ball 208 from engaging the ball seat 212 .
  • fluids may pass through the wellbore isolation device 200 ; i.e., through the ports 230 and the central flow passage 210 .
  • the ball cage 204 retains the sealing ball 208 such that it is not lost during translation into the wellbore 106 to its target location.
  • a setting tool (not shown) of a type known in the art can be used to move the wellbore isolation device 200 from its unset position (shown in FIG. 2 ) to a set position.
  • the setting tool may operate via various mechanisms to anchor the wellbore isolation device 200 in the wellbore 106 including, but not limited to, hydraulic setting, mechanical setting, setting by swelling, setting by inflation, and the like.
  • the slips 216 a,b and the packer elements 220 expand and engage the inner walls of the casing 114 .
  • fluid is injected into the wellbore 106 and conveyed to the wellbore isolation device 200 at a predetermined flow rate that overcomes the spring force of the spring 224 and forces the sealing ball 208 downwardly until it sealingly engages the ball seat 212 .
  • the sealing ball 208 is engaged with the ball seat 212 and the packer elements 220 are in their set position, fluid flow past or through the wellbore isolation device 200 in the downhole direction is effectively prevented.
  • completion or stimulation operations may be undertaken by injecting a treatment or completion fluid into the wellbore 106 and forcing the treatment/completion fluid out of the wellbore 106 and into a subterranean formation above the wellbore isolation device 200 .
  • the wellbore isolation device 200 Following completion and/or stimulation operations, the wellbore isolation device 200 must be removed from the wellbore 106 in order to allow production operations to effectively occur without being excessively hindered by the emplacement of the wellbore isolation device 200 .
  • various components of the wellbore isolation device 200 may be made of one or more degrading or dissolving materials, e.g., dissolvable metal matrix composite.
  • the wellbore isolation device 200 may have a greater flow area or flow capacity through and/or around the wellbore isolation device 200 .
  • the wellbore isolation device 200 may exhibit a large flow area or flow capacity through and/or around the wellbore isolation device 200 so that it does not unreasonably impede, obstruct, or inhibit production operations while the wellbore isolation device 200 degrades. As a result, production operations may be undertaken while the wellbore isolation device 200 proceeds to dissolve and/or degrade, and without creating a significant pressure restriction within the wellbore 106 .
  • At least the mandrel 206 may be made of or otherwise include a dissolvable metal matrix composite which includes a dissolvable metal that is configured to degrade or dissolve within a wellbore environment.
  • other components of the wellbore isolation device 200 may also be made of or otherwise comprise a dissolvable metal including, but not limited to, the upper and lower slips 216 a,b, the upper and lower slip wedges 218 a,b, and the mule shoe 222 .
  • other components of the wellbore isolation device 200 that may be made of or otherwise comprise a dissolvable metal to include extrusion limiters and shear pins associated with the wellbore isolation device 200 .
  • FIG. 3 shows an example of a sliding sleeve 300 that employs metal matrix composite in accordance with the present disclosure.
  • the sliding sleeve 300 may include baffle portion 310 on top and sliding sleeve portion 315 on bottom.
  • the sliding sleeve 300 may further include dissolvable metal matrix composite that degrades in a wellbore fluid.
  • the dissolvable metal matrix composite includes dissolvable metal and a dispersed reinforcement material.
  • the dispersed reinforcement material provides sharpness and the erosion resistance needed in a baffle (or baffle seat) while the metal provides toughness.
  • the erosion resistance also provides resistance to the proppant and flow that passes by the baffles.
  • the dissolvable metal matrix composite enables dissolvable baffle or baffle seats which in turn facilitates easier removal of the baffle from the wellbore system.
  • the degradable material may be configured to be encapsulated in a metallic or polymeric coating.
  • the coating prevents dissolution until the coating is removed. This prevents premature degradation.
  • the coating may be removed by erosion during the hydraulic fracturing operation. There may be different diameter baffles at different locations in the wellbore.
  • the sliding sleeve 300 may be used to block access to a flow port.
  • the sliding sleeve 300 may be held in place at the flow port by a shear pin.
  • a ball 325 lands on the sliding sleeve portion 315 , the hydraulic force breaks the shear pin and the siding sleeve portion 315 shifts towards the right.
  • the flow ports are now open and the frac can commence.
  • the baffle 310 where the ball 325 has landed is the erosion resistant metal matrix composite.
  • the sliding sleeve 300 may include a supporting component 320 that supports the baffle 310 .
  • the supporting component 320 may include a degradable material.
  • the baffle 310 and the supporting component 320 may be configured as a single piece and composed entirely of the degradable metal matrix composite.
  • FIG. 4 shows an example of a metal matrix composite that is constructed in accordance with the principles of the present disclosure.
  • the dissolvable or degradable metal matrix composite of the present disclosure includes dissolvable metal and a dispersed reinforcement material wherein the reinforcement material is a ceramic or a hardened metal.
  • a mold may be filled with reinforcement material and then infiltrated with dissolvable metal (e.g., aluminum alloy or magnesium alloy).
  • the dissolvable metal then glues all the reinforcement material together (as shown in e.g., FIG. 5 ). Any component or part of the downhole component may include such mold.
  • the dissolvable metal may degrade in a wellbore fluid under certain conditions.
  • the dissolvable metal matrix composite includes connecting together an element that is and not degradable (e.g., ceramic or hardened metal) with an element that is degradable (e.g., dissolvable metal) with a degradable metal glue.
  • the rate of degradation of the dissolvable metal may depend on a number of factors including, but not limited to, the type of dissolvable metal selected and the conditions of the wellbore environment.
  • the degradable or dissolvable metal matrix composite for use in forming components of the wellbore isolation device 200 may degrade, at least in part, in the presence of an aqueous fluid (e.g., a treatment fluid, wellbore fluid, acid, chemical, and the like).
  • the aqueous fluid that may degrade the dissolvable metal may include, but is not limited to, fresh water, saltwater (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated salt water), seawater, or combinations thereof.
  • the aqueous fluid may comprise ionic salts that trigger galvanic corrosion.
  • the aqueous fluid may come from the wellbore 106 itself (i.e., the subterranean formation) or may be introduced by a wellbore operator.

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