EA040920B1 - PROTECT PACKER ELEMENT CONSUMABLE MATERIAL FOR IMPROVED RUNNING TIME - Google Patents

Description

Technical field

The present disclosure relates generally to oil well equipment, and more particularly to elastomeric packers used in completions, well cementing, and other well operations.

State of the art

Downhole packers are commonly used in many oilfield applications to seal against fluid flow to isolate one or more sections of a wellbore for testing, processing, or production purposes. Non-limiting examples of fluids include liquids such as oil and water, gases such as natural gas, and three-phase flow. Packers can be classified as retrievable or permanent.

When the packer is deployed, the packer may hang in a radially compressed state in an open or cased wellbore from a tubing string, workstring, cable, or the like. When set in position, the packer may be set, for example, by applying tension, compression, or hydraulic force such that one or more wedges or other anchor mechanism engage the inside surface of the wellbore or casing, thereby locking the packer within the wellbore. wells. Installing the packer in the radial direction expands the elastomeric sealing element or packer element, bringing it into engagement with the inner surface of the wellbore or casing, thereby preventing the flow of fluid through the annulus.

Packer elements can be formed using a limited number of different rubber compounds, as most elastomers, capable of handling a wide variety of oilfield fluids, also have low tensile strength and extrusion resistance, making them unsuitable for use. Therefore, most packer sealing elements are made from a durable nitrile material such as nitrile butadiene rubber (NBR) or hydrogenated nitrile butadiene rubber (HNBR).

However, when exposed to an incompatible fluid, which may be introduced during a run downhole operation, the sealing packer element may begin to rapidly fail. For this reason, furthermore, in addition to minimizing the high hourly cost of well work, it may be desirable to limit the time that packers are exposed to such an incompatible fluid by increasing the speed of runs. High speed runs can cause the rubber packer element to pack or swab prematurely. This phenomenon occurs because the viscous well fluid flowing past the rubber packer element during a run tends to pull the packer element outward towards the wellbore wall. Fluid flow past the packer may also damage other elements of the packer, including wedges, deflector wedges, and the like.

Brief description of graphic materials

Embodiments of the invention are described in detail below with reference to the accompanying figures, with FIG. 1 is a partial cross-sectional elevational view of an exemplary well system showing a well packer according to an embodiment of the principles of the present disclosure that is inserted into the wellbore by means of a cable or coiled tubing conveyance;

in fig. 2 is a partial cross-sectional elevation view of at least an exemplary well system showing a well packer according to an embodiment of the principles of the present disclosure that is inserted into the wellbore by a drill string, work string, or production tubing string;

in fig. 3 is a partial cross-sectional elevational view of an exemplary downhole packer that may be used in conjunction with the downhole system illustrated in FIG. 2 showing an elastomeric packer element covered with a temporary protective jacket, in accordance with an embodiment of the invention;

in fig. 4 is a partial cross-sectional elevational view of an exemplary downhole packer that may be used in conjunction with the downhole system illustrated in FIG. 2 showing an elastomeric packer element, a drive mechanism and an anchor mechanism covered with a temporary protective casing, in accordance with an embodiment of the invention;

in fig. 5 is a partial cross-sectional elevational view of an exemplary downhole packer that may be used in conjunction with the downhole system illustrated in FIG. 2 showing an elastomeric packer element covered with a temporary protective jacket, in accordance with an embodiment of the invention;

in fig. 6 is a flow diagram of a method for performing operations in a wellbore in accordance with an embodiment of the invention that reduces run times when deploying downhole packers.

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Detailed Description of the Invention

The present disclosure may repeat the reference numerals and/or letters in various examples. This repetition is intended for simplicity and clarity and does not, by itself, necessarily establish a relationship between the various embodiments and/or configurations discussed. In addition, spatial relationship terms such as downstream, downstream, downstream, upstream, upstream, uphole, downhole, upstream, downstream, and the like, may be used in this document to simplify the presentation for describing the relationship of one element or feature to another element(s) or feature(s), as illustrated in the figures. The spatial relationship terms are intended to cover various orientations of the device in use or operation in addition to the orientation depicted in the figures.

In FIG. 1 illustrates an exemplary downhole system 100 that includes a packer 200 in accordance with an embodiment of the invention deployed in a cable environment. In some examples of wireline operations in the well, a platform above the surface 106 that is equipped with a drilling rig 132 or a drawworks 133 that supports a vehicle 134 extending deep into the wellbore 102, which may include a casing 104. Cable operations in the well may be performed, for example , after the drill string is removed from the wellbore 102 to allow the packer 200 to be run by wireline into the wellbore 102, for example, in conjunction with one or more well logging operations. The conveyance 134 may be coiled tubing, wireline, or other structure on which the packer 200 is lowered.

In FIG. 2 illustrates an exemplary downhole system 100' that includes a packer 200 in accordance with an embodiment of the invention deployed in a typical tubing run environment, such as that used during drilling of a wellbore 102. The transport means 134' may be made of drill pipe stands or individual lengths of pipe connected together to form a pipe string 140 that extends deep into the wellbore 102. The tubular string 140 includes a packer 200. The drilling rig 142 at the surface 106 can support the tubular string 140. The tubular string 140 may be a drill string that, in addition to the drill pipe, may include, for example, a working pipe, a drill collar, a bottom hole assembly with a mud motor, a drill bit, and other components (not illustrated). The tubing string 140 may also be a production tubing string for a production well completion, or a production tubing string for cementing, perforating, or other operations.

As described herein, exemplary embodiments of the present invention relate to a packer 200 having a sacrificial temporary protective element disposed thereon that protects the packer element and optionally other components of the packer from the adverse effects of the environment and the flow of fluids in the wellbore 102. until the packer 200 is ready to be installed. The security element may take various forms, as described below.

In FIG. 3 illustrates a partial cross-sectional elevation view of a packer 200 in accordance with one or more embodiments of the invention. In the illustrated embodiment, packer 200 is a retrievable packer set by string tension. However, the present disclosure is not limited to a specific type of packer. Retrievable or permanent seal packers, pressure-set packers, cable-actuated mechanical packers, tension-set packers/pressure-set packers, hydraulically-set packers, hydrostatic pressure-set packers, swellable packers, packers for two or more parallel lifting strings and packers with or without a fluid bypass can be used equally in accordance with the principles of the present disclosure.

Packer 200 may include a body or mandrel 210. Mandrel 210 may be tubular to provide a flow path 212 through packer 200. Mandrel 210 may be placed along tubing string 140 (FIG. 2) by means of lock collar 214 and male connector 216. However, as other types of connectors may be used if necessary. The mandrel 210 may also be placed along other types of transportation means 134, such as cable or coiled tubing (see FIG. 1).

The packer 200 includes a radially expandable sealing or packer element 220 running on a mandrel 210. In the non-deployed state, the packer element 220 has an outside diameter that is smaller than the inside diameter of the open wall of the hole or casing 104 of the wellbore 102 (FIGS. 1, 2), to allow packer 200 to be run deep into wellbore 102. When deployed, packer element 220 expands radially to have an outer diameter sufficient for packer element 220 to fully engage the wall of the wellbore to form a watertight seal.

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Although in one or more embodiments of the invention, the packer element 200 is not limited to a particular type of material, the packer element 220 may be made of an elastic material, such as rubber or an elastomer. In one or more embodiments of the invention, the packer element 220 may be made of a nitrile material, such as nitrile butadiene rubber (NBR) or hydrogenated nitrile butadiene rubber (HNBR), which may have suitable mechanical and waterproofing properties for use downhole. In a swellable packer, the packer element 220 may be made of a water or oil swellable elastomer or thermoplastic, such as water absorbent resins, crosslinked polyacrylate products, crosslinked starch-acrylate graft products, crosslinked acrylonitrile starch hydrolyzate products, and crosslinked carboxymethyl cellulose products. In addition, the packer element 220 may be made of ethylene propylene rubber (EPM) because, as discussed below, a sacrificial or temporary containment jacket initially encapsulates the packer element 220 and can protect the packer element 220 from the adverse effects of incompatible fluids during a run in the hole. wells.

The packer 200 may include an actuator 240 for a radially expandable packer element 220. The packer element 220 may be radially expanded by axial compression between the upper and lower shoulders 222, 224 of the actuator 240 as illustrated in FIG. 3. The packer element 220 can also expand radially by inflating a hollow balloon (not illustrated) within the packer element 220 or by physically swelling the material containing the packer element 220.

The packer 200 may include an anchor mechanism 230 for selectively fixing the packer 200 at a predetermined location within the wellbore 102 (FIG. 2). In the pull string retrievable packer illustrated in FIG. 3, the anchor mechanism 230 includes a set of serrated wedges 232, or combinations thereof, and a conical bit 234. The wedges 232 are configured to engage the borehole wall upon initial upward movement of the packer 200. While the upward movement of the packer 200 continues, the mandrel 210 slides within the anchor mechanism 230, thereby bringing the cone nozzle 234 into engagement with the internal wedges 236 of the wedges 232 to force the wedges 232 into tight engagement with the borehole wall.

However, depending on the particular type of packer 200, other devices for the anchor mechanism 230 may be used, or no anchor mechanism may be used at all. For example, the anchor mechanism 230 may include a lower wedge assembly and a conical nozzle that operates under compressive loads. The anchor mechanism 230 may also include retaining wedges, joint links, and the like. For example, at least the anchor mechanism may not be needed, for example in the case of swellable packers.

According to the exemplary principles of the present disclosure, the packer 200 includes a temporary containment 250 located around the packer element 220. The containment 250 extends the life of the packer element 220 when the packer 200 is immersed in an incompatible fluid because the packer element 220 is not exposed to downhole fluids. until the containment 250 is used up or depleted. For the same reasons, the containment 250 prevents the packer element 220 from swabbing when fluid flows past the packer 220 during descent into the wellbore 102 (FIG. 1), thereby leading to minimizing the chance of premature packing or pre-setting. Thus, the shroud 250 allows the speed of the run to be increased, saving time and associated costs. In one or more embodiments, the shroud 250 may also encapsulate one or more components of the drive mechanism 240 and/or anchor mechanism 230, thereby protecting such mechanisms from the hostile environment within the wellbore 102. Such an arrangement may have advantages such as during cementing operations.

In FIG. 3 illustrates a protective housing 250 in accordance with one or more embodiments of the invention. The protective cover 250 may be in the form of a sleeve 252, which is placed around the packer element 220.

Sleeve 252 may also extend over one or more components of drive assembly 240, such as upper and lower shoulders 222, 224, as illustrated in the figure. Although in FIG. 3, the containment case 250 is illustrated as completely enclosing the packer element 220, in other embodiments, the containment case 250 may only partially encapsulate the packer element 220, or enclose the packer element within the casing. In either case, the containment 250 may be in the form of a sleeve 252 that is placed around the packer element 220. The sleeve 252 minimizes or prevents contact of the packer element 220 with the downhole fluid and prevents the packer element 220 from swabbing due to fluid flowing past said element. Sleeve 252 may be made of a material that readily dissolves in the well fluid. Non-limiting examples of suitable soluble material for sleeve 252 may include metallic and non-metallic materials (such as plastic), examples of which are aluminum-gallium alloys such as 80% aluminium-20% gallium; 80%Al-10%Ga-10%In;

75%Al-5%Ga-5%Zn-5%Bi-5%Sn-5%Mg; 90%Al-2.5%Ga-2.5%Zn-2.5%Bi-2.5%Sn; 99.8%Al-0.1%In0.1%Ga; as well as a plastic material such as polyglycolic acid (PGA); poly(lactic coglycolic acid) (PLGA); polylactic acid (PLA); polycaprolactone (PCL); as well as polyhydroxyalconate. The wall thickness of the sleeve 252 may be determined based on the dissolution rate of the sleeve material, the running speed, and the depth at which the packer 200 is to be deployed.

Sleeve 252 can also be made from a material that will melt under the influence of temperature and/or pressure downhole, such as a suitable thermoplastic or fusible metal alloy. Fusible metal alloys can easily be made to melt within about ten degrees of their characteristic temperature. Thus, a particular alloy can be chosen to not melt until the packer 200 approaches the target zone, and the run rate is not limited to swabbing the elastomeric components until the target zone is reached.

In FIG. 4 illustrates a partial cross-sectional elevation view of a packer 200' which is substantially the same as packer 200 in FIG. 3. In one or more embodiments, the containment 250 may be a sleeve 254 that encases the packer element 220 and one or more components of the drive mechanism 240 and anchor mechanism 230. As illustrated in FIG. 4, the sleeve 254 wraps the space packer 200 from the anchor mechanism 232, the lower shoulder 224 of the anchor mechanism 240. Like the sleeve 252 of FIG. 3, sleeve 254 may be made of a soluble or fusible material that protects the encapsulated components from the wellbore environment during the initial run of packer 200. Sleeve 254 is consumed prior to activation or setting of packer 200.

In FIG. 5 illustrates a partial cross-sectional elevational view of a packer 200 in accordance with one or more embodiments of the invention. Like the packer 200 of FIG. 3, the packer 200 may include a mandrel 210, an elastomeric packer element 220, an optional anchor mechanism 230, and an optional drive mechanism 240. The protective casing 250 encapsulates the packer element 220 to prevent swabbing and interaction with incompatible well fluids. The containment 250 may include a coating 256 of a temporary material that is deposited or otherwise placed around the packer element 220. The temporary coating material 256 may have a melting point at a given temperature or by being dissolved in a particular wellbore fluid. The coating 256 may be applied around the packer element 220 by any suitable method, including pouring, dipping, spraying, taping, painting, casting, and other known methods. The use of a coating 256 can advantageously be used on any current elastomer based packer without modification to the existing design.

In FIG. 6 illustrates a flowchart of a wellbore method 300 according to an embodiment of the invention that reduces run times when deploying downhole packers. First, in accordance with FIG. 3 and 6, in step 304, the packer element 220 of the well packer 200 is wrapped by a sacrificial, temporary containment 250. Additionally, as illustrated in FIG. 4, the drive mechanism 240 and/or the anchor mechanism 230, if provided, may be encased by the temporary containment 250 in whole or in part, thereby providing protection to such components or element.

As discussed above, the containment 250 may be in the form of a thin wall sleeve 252, 254 (FIGS. 3, 4, respectively) located around the packer 200, or in the form of an applied coating 256 applied to the packer 200 (FIG. 5). However, the protective cover 250 may take any suitable shape.

Temporary containment 250 may comprise a material with a predetermined low melting temperature such that containment 250 will melt when packer 200 is positioned in the target zone of the wellbore. Examples of suitable melting materials include fusible metal alloys and thermoplastics. Alternatively or additionally, the temporary containment 250 may contain a material that is soluble in a given well fluid, such as water or hydrocarbons. Examples of suitable soluble materials can be metallic and non-metallic materials (such as plastic), examples of which are: aluminum-gallium alloys such as 80% aluminium-20% gallium; 80%Al-10%Ga-10%In; 75%Al-5%Ga-5%Zn5%Bi-5%Sn-5%Mg; 90%Al-2.5%Ga-2.5%Zn-2.5%Bi-2.5%Sn; 99.8%Al-0.1%In-0.1%Ga; as well as a plastic material such as polyglycolic acid (PGA); poly(lactic coglycolic acid) (PLGA); polylactic acid (PLA); polycaprolactone (PCL); and polyhydroxyalconate.

With reference to FIG. 1, 2, and 6, in step 308, the packer 200 with temporary containment 250 is lowered into the wellbore 102. The packer 200 may be run into the wellbore 102 using a cable or coiled tubing transport 134 (FIG. 1) or, for example, a drill string, workstring, or production string 140 transport 134 (FIG. 2). . Because the packer element 220 is sheathed by the guard 250, the running speed is not limited by swabbing factors, thereby reducing potential time and cost savings.

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At 312, when the packer 200 is run to the target depth, the guard 250 may begin to deplete depending on conditions in the wellbore. Ideally, the containment case 250 is configured to be used in a particular situation such that the containment case 250 is not fully depleted until the packer 200 is at or near the target location, and such that the containment case 250 is depleted only shortly thereafter. how the packer 200 is at or near the target location. Thus, the time that the packer 200 can be set is minimized.

Once the containment 250 is sufficiently depleted, at 316, the packer can be set within the wellbore 102, for example, by applying stress, compression, torsion, hydraulic force, electric current, or swelling. The step member 220 expands in the radial direction to enter into sealing engagement with the wall of the wellbore 102 or its casing 104.

Thus, a downhole packer has been described. The downhole packer may typically include a mandrel; expandable in the radial direction of the packer element descending on the specified mandrel; and a temporary protective casing located around the specified packer element. Similarly, a downhole system for deployment in a wellbore is described. The well system may include a well formed in the earth and opening to the surface of the earth; a means of transportation extending from the earth's surface into said wellbore; and a packer transported by said means of transportation and located within said wellbore, said packer comprising a mandrel, a radially expandable packer element running down the mandrel, and a temporary protective casing located around said packer element. Similarly, the downhole system may include a conveyance mechanism extending into the wellbore; and a packer deployed by said transport mechanism and positioned within said wellbore, said packer comprising a mandrel, a radially expandable packer element running down said mandrel, and a temporary protective casing located around said packer element.

Any of the above may contain any of the elements below, alone or in combination with each other.

The expandable packer element is formed from an elastomer.

The expandable packer element is formed from a material selected from the group consisting of nitrile butadiene rubber; hydrogenated nitrile butadiene rubber; water-absorbing resins; cross-linked polyacrylate products; cross-linked starch acrylate graft copolymer products; cross-linked starch-acrylonitrile graft copolymer hydrolyzate products; cross-linked carboxymethyl cellulose products; as well as ethylene propylene rubber.

The temporary protective casing is a coupling.

The temporary protective cover is a cover.

The protective casing, at least partially, closes the packer element.

The protective casing completely covers the packer element.

The protective casing, at least partially, closes the packer element.

The protective casing completely covers the packer element.

At least one element from the group consisting of an anchor mechanism lowered using said mandrel, configured to selectively fix said packer inside the wellbore, and a drive mechanism operatively associated with said packer element so that said packer element can selectively expand, at least in the radial direction.

At least one element from the group, consisting of an anchor mechanism, which is lowered by means of the specified mandrel, acting in such a way as to selectively fix the specified packer, at least within the wellbore, and a drive mechanism, functionally connected to the specified packer element, for selective expansion in the radial direction of the specified packer element, while the specified temporary protective casing takes in the shell, at least, the specified one element.

The temporary protective casing is made of a material that melts under the thermodynamic conditions of the wellbore.

The material of the protective casing is a fusible metal alloy.

The protective cover material is a thermoplastic material.

The temporary protective casing is made of a material that dissolves in the well fluid.

The temporary protective casing is made of aluminum-gallium alloy.

The temporary protective casing is made of a metallic material selected from the group consisting of 80% aluminium-20% gallium; 80%Al-10%Ga-10%In; 75%Al-5%Ga-5%Zn-5%Bi-5%Sn5%Mg; 90%Al-2.5%Ga-2.5%Zn-2.5%Bi-2.5%Sn; as well as 99.8% Al-0.1% In-0.1% Ga.

The temporary protective cover is made of a plastic material selected from the group consisting of polyglycolic acid (PGA); poly(lactic coglycolic acid) (PLGA); polylactic acid (PLA); polycaprolactone (PCL); as well as polyhydroxyalconate.

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Claims (12)

Thus, a method of performing work in a wellbore is described. The method of performing work in the wellbore, as a rule, may include the creation of a shell for the packer element using a temporary protective casing; lowering said packer into a wellbore formed in the ground; providing the specified protective casing of the opportunity to be used up in the conditions of the wellbore; and then setting said packer within said wellbore. The above method may include any of the steps below, alone or in combination with each other. Creation of a shell for at least one element from the group consisting of an anchor mechanism lowered by said mandrel, acting in such a way as to selectively fix the specified packer within the wellbore, and a drive mechanism operatively connected to the specified packer element for selective radial expansion of the specified packer element with the specified temporary protective casing. Creating a shell for the specified packer element using the specified temporary protective casing, made of a material that dissolves in the well fluid. Creating a shell for the specified packer element using the specified temporary protective casing made of a material that melts under the thermodynamic conditions of the wellbore. The formation of a temporary protective casing from a material selected from the group consisting of a fusible metal alloy and a thermoplastic material. The creation of the shell includes the deployment of a temporary protective casing in order to at least partially enclose the specified packer element. The creation of the shell includes the creation of a shell for the packer element with the help of a protective material, which, at least partially, covers the specified packer element. The abstract of the invention is intended solely to provide a method by which the nature and essence of the technical disclosure of the invention can be quickly determined from a cursory examination and is only one or more embodiments of the invention. Although various embodiments of the invention have been illustrated in detail, the present invention is not limited to the illustrated embodiments. Specialists in the art can modify and adapt the above embodiments of the invention. Such modifications and adaptations are within the spirit and scope of the invention. CLAIM 1. A wellbore packer (200) containing a mandrel (210); a radially expandable packer element (220) running down said mandrel (210); a temporary protective casing (250) located around the specified packer element (220); a drive mechanism (240) operatively connected to said packer element (220) for selectively expanding said packer element (220) in the radial direction, and an anchor mechanism (230) being lowered by said mandrel (210) and acting so as to selectively fix the specified packer (200) inside the wellbore; moreover, the temporary protective casing (250) is configured to cover at least the first and second parts associated with the axially spaced first and second shoulders, respectively, of the specified drive mechanism (240), moreover, the packer element (220) is configured to engagement with the first and second shoulders, compression in the axial direction between them for selective expansion in the radial direction of the specified packer element (220); and moreover, the anchor mechanism (230) is located next to the specified first part and opposite the specified second part of the drive mechanism (240). 2. Packer according to claim 1, characterized in that said temporary protective cover is a sleeve or cover. 3. The packer of claim 1, wherein the anchor mechanism (230) is configured to transition to a deployed configuration from a non-deployed configuration to selectively lock said packer within the wellbore, wherein, in the non-deployed configuration, said temporary protective sheath is configured to cover at least least part of the specified anchor mechanism; and the anchor mechanism is located at a distance from the specified first part of the drive mechanism (240). 4. The packer according to claim 1, characterized in that said temporary protective casing is made of a material that melts under thermodynamic conditions of the wellbore; said material is a fusible metal alloy; and said material is a thermoplastic material. 5. Packer according to claim 1, characterized in that said temporary protective casing is made of a material that dissolves in the well fluid. 6. Downhole system (100), containing the wellbore (102), formed in the ground and opening towards the surface of the earth; means (134) of transportation, passing from the surface of the earth into the wellbore; and a packer (200) according to any one of claims 1 to 5, run by said means of transportation and installed inside said wellbore. 7. Downhole system according to claim 6, characterized in that said means of transportation comprises one element from the group consisting of a drill string, a work string, a production tubing string, coiled tubing, and a cable. 8. The method of operating the packer in the wellbore, including the creation of a shell around the packer element (220), which is part of the packer (200) according to any one of claims 1 to 5, using a temporary protective casing (250); creation with the help of the specified temporary protective casing (250) of the shell around at least the first and second parts associated with the first and second shoulders spaced apart in the axial direction, respectively, of the drive mechanism (240) functionally connected to the specified packer element (220) , for selective radial expansion of the specified packer element (220), and the packer element (220) is configured to engage with the first and second shoulders, compression in the axial direction between them for selective expansion in the radial direction of the specified packer element (220); lowering the specified packer (200) and the specified drive mechanism (240) together with the anchor mechanism (230) inside the borehole (102) formed in the ground, and the anchor mechanism (230) is located next to the specified first part and opposite the specified second part of the drive mechanism (240); providing the specified casing (250) the ability to collapse in the conditions of the wellbore; and then setting said packer (200) inside said wellbore (102). 9. The method of claim 8, wherein the anchor mechanism (230) is configured to transition to a deployed configuration from a non-deployed configuration to selectively lock said packer within the wellbore; wherein the method further comprises providing, in a non-deployed configuration, a shell for at least a portion of the anchor mechanism (230) by means of a temporary protective casing; and moreover, in a non-deployed configuration, the anchor mechanism (230) is located at a distance from the specified first part of the drive mechanism (240). 10. The method of claim 8, further comprising providing a sheath to said packer element with said temporary containment made of a material that dissolves in the well fluid. 11. The method according to claim 8, additionally including the creation of a shell for the specified packer element using the specified temporary protective casing made of a material that melts under thermodynamic conditions of the wellbore; and forming a temporary protective casing of a material selected from the group consisting of a fusible metal alloy and a thermoplastic material. 12. The method according to claim 8, characterized in that the creation of the shell includes the deployment of a temporary protective casing in order to at least partially enclose the specified packer element; or the creation of the shell includes the creation of a shell for the packer element with a protective material, which, at least partially, covers the specified packer element. -