CA2406259C - Downhole tool apparatus with non-metallic components and methods of drilling thereof - Google Patents
Downhole tool apparatus with non-metallic components and methods of drilling thereof Download PDFInfo
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- CA2406259C CA2406259C CA002406259A CA2406259A CA2406259C CA 2406259 C CA2406259 C CA 2406259C CA 002406259 A CA002406259 A CA 002406259A CA 2406259 A CA2406259 A CA 2406259A CA 2406259 C CA2406259 C CA 2406259C
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Abstract
A downhole tool apparatus and methods of drilling the apparatus. The apparatus may include, but is not limited to, packers and bridge plugs utilizing non-metallic components. The material may include engineering grade plastics.
The nonmetallic components may include but lire not limited to the center mandrel, slips, slip wedges, slip supports and housings, spacer rings, valve housings and valve components. Methods of driliing out the apparatus without significant variations in the drilling speed and weight applied to the drill bit may be employed. Alternative drill bit types, such as polycrystalline diamond compact (PDC) bits may also be used.
The nonmetallic components may include but lire not limited to the center mandrel, slips, slip wedges, slip supports and housings, spacer rings, valve housings and valve components. Methods of driliing out the apparatus without significant variations in the drilling speed and weight applied to the drill bit may be employed. Alternative drill bit types, such as polycrystalline diamond compact (PDC) bits may also be used.
Description
DOWNHOLE TOOL APPARATUS WITH NON-METALLIC
COMPONENTS AND METHODS OF DRILLING THEREOF
Baekc~rc>und Of The :I~wention 1. Field Of "the Invention This invention re:Lates to dc.ownhole tools for use in well bores and metl~.ods of drilling such apparatus out of well bares, anc3. more pt~r~ticularly, to such tools having c~rillable componer~ts therein made of non-metallic materials, such as engineering grade plastics.
COMPONENTS AND METHODS OF DRILLING THEREOF
Baekc~rc>und Of The :I~wention 1. Field Of "the Invention This invention re:Lates to dc.ownhole tools for use in well bores and metl~.ods of drilling such apparatus out of well bares, anc3. more pt~r~ticularly, to such tools having c~rillable componer~ts therein made of non-metallic materials, such as engineering grade plastics.
2. Description of The Prior Art In the drilling o:r xvework:ng of oil wells, a great variety of <iownhole tools are used. For example, but not by way of lim__tation, it is often desirable to seal ti:~bing or~ ot:her pipe in the casing of the well, such as when it is desired to pump cement or other slurry down t~.zbing and force the slurry out into a formation. It then becomes necessary to seal the tubing with respect to the well casing and to prevent the fluid pressure of the slurry from 1=_ftinc~ the tubing out of the well.
Packers and bridge pli.zgs des igm>r~ .for these general purposes are well known iz~ the art.
When it -ws desired to remove many of these downhole tools from a. well bore, it is frequently simpler and less expensive to m.i Ll or drill them out rather than to imp.:Lement a complex retrieving aperation. In mill:inc~, a mill-ir~g cutter is used to grind the packer or plug, for example, or at least the outer component;> thereof, oat of the well bore.
Milling is a :) relatively slow process, but it can be used an packers or bridge plugs having relatively hard components such as erosion-resistant hard steel. One such packer is disclosed in U. S. Patent No. 4,151,875 to Sullaway, assigned to the assignee of the present invention and sold under the trademark EZ Disposal packer. Other downhole tools in addition to packers and bridge plugs may also be drilled out.
In drilling, a drill bit is used to cut and grind up the components of the downhole tool to remove it from the well bore. This is a much faster operation than milling, but requires the tool to be made out of materials which can be accommodated by the drill bit. Typically, soft and medium hardness cast iron are used an the pressure bearing components, along with some brass and aluminum items. Packers of this type include the Halliburton EZ Drill~ and EZ Drill SV~ squeeze packers.
The EZ Drill SV° squeeze packer, far example, includes a lock ring housing, upper slip wedge, dower slip wedge, and lower slip support made of soft cast iron. These components are mounted on a mandrel made of medium hardness cast iron.
The EZ Drill~ squeeze packer is similarly constructed. The Halliburton EZ Drills' bridge plug is also similar, except that it does not provide for fluid flow therethrough.
All of the above-mentioned packers are disclosed in Halliburton Services Sales and Service Catalog No. 43, pages 2561-2562, and the bridge plug is disclosed i.n the same catalog on pages 2556-2557.
Packers and bridge pli.zgs des igm>r~ .for these general purposes are well known iz~ the art.
When it -ws desired to remove many of these downhole tools from a. well bore, it is frequently simpler and less expensive to m.i Ll or drill them out rather than to imp.:Lement a complex retrieving aperation. In mill:inc~, a mill-ir~g cutter is used to grind the packer or plug, for example, or at least the outer component;> thereof, oat of the well bore.
Milling is a :) relatively slow process, but it can be used an packers or bridge plugs having relatively hard components such as erosion-resistant hard steel. One such packer is disclosed in U. S. Patent No. 4,151,875 to Sullaway, assigned to the assignee of the present invention and sold under the trademark EZ Disposal packer. Other downhole tools in addition to packers and bridge plugs may also be drilled out.
In drilling, a drill bit is used to cut and grind up the components of the downhole tool to remove it from the well bore. This is a much faster operation than milling, but requires the tool to be made out of materials which can be accommodated by the drill bit. Typically, soft and medium hardness cast iron are used an the pressure bearing components, along with some brass and aluminum items. Packers of this type include the Halliburton EZ Drill~ and EZ Drill SV~ squeeze packers.
The EZ Drill SV° squeeze packer, far example, includes a lock ring housing, upper slip wedge, dower slip wedge, and lower slip support made of soft cast iron. These components are mounted on a mandrel made of medium hardness cast iron.
The EZ Drill~ squeeze packer is similarly constructed. The Halliburton EZ Drills' bridge plug is also similar, except that it does not provide for fluid flow therethrough.
All of the above-mentioned packers are disclosed in Halliburton Services Sales and Service Catalog No. 43, pages 2561-2562, and the bridge plug is disclosed i.n the same catalog on pages 2556-2557.
The EZ Dril1~ packer and bridge plug and the EZ Drill SV~
packer are designed for fast removal from the well bore by either rotary or cable tool drilling methods. Many of the components in these drillable packing devices are locked together to prevent their spinning while being drilled, and the harder slips are grooved' so that they will be broken up in small pieces. Typically, standard "tri-cone" rotary drill bits are used which are rotated at speeds of about 75 to about 120 rpm. A load of about 5,000 to about 7,000 pounds of weight is applied to the bit for initial drilling and increased as necessary to drill out the remainder of the packer or bridge plug, depending upon its size. Drill collars may be used as required for weight and bit stabilization.
Such drillable devices have worked well and provide improved operating performance at relatively high temperatures and pressures. The packers and plug mentioned above are designed to withstand pressures of about 10,000 psi and temperatures of about 425° F. after being set in the well bore. Such pressures and temperatures require the cast iron components previously discussed.
However, drilling out iron components requires certain techniques. Ideally, the operator employs variations in rotary speed and bit weight to help break up the metal parts and reestablish bit penetration should bit penetration cease while drilling. A phenomenon known as "bit tracking" can occur, wherein the drill bit stays on one path and no longer cuts into the downhole tool. When th~.s happens, it is necessary to pick up the bit above the drilling surface and rapidly recontact the bit with the packer or plug and apply weight while continuing rotation. This aids in breaking up the established bit pattern and helps to reestablish bit penetration. If this procedure is used, there are rarely problems. However, operators may not apply these techniques or even recognize when bit tracking has occurred. The result is that drilling times are greatly increased because the bit merely wears against the surface of the downhole tool rather than cutting into it to break it up.
While cast iron components may be necessary for the high pressures and temperatures for which they are designed, it has been determined that many welt's experience pressures less than 10,000 psi and temperatures less than 4~5° F. This includes most wells cemented. In fact, in the majority of wells, the pressure is less than about 5,000 psi, and the temperature is less than about 2S0° F. Thus, the heavy duty metal construction of the previous downhole tools, such as the packers and bridge plugs described above, is not necessary for many applications, and ia: cast iron components can be eliminated or minimi2;edJ the potential drilling problems resulting from bit tracking might be avoided as well.
The downhole tool of the present invention solves this problem by providing an apparatus wherein at least some of the components, including pressure bearing components, are made of non-metallic materials, such as engineering grade plastics.
Such plastic component:--.~ are mu<:h mor°e eas:a.ly drilled than cast iron, and new drilling methods may be employed which use alternative drill bits such as polycrystalline diamond compact bits, or the like, rather than standard tri-cone bits.
Summary Of The Invention The downhole tool apparatus of the present invention utilizes non-metallic mateYials, such as engineering grade plastics, to reduce weighty to reduce manufacturing time and labor, to improve performance through reducing frictional forces of sliding surfaces, to reduce costs and to improve drillability of the apparatus when drilling is required to remove the apparatus from the well bore Primarily, in this disclosure, the downhole tool is characterized by well bore packing apparatus, but it is not intended that the invention be limited to such packing devices. The non-metallic components in the downhole tool apparatus also allow the use of alternative drilJ_ing techniques v~o those previously known.
In packing apparatus embodimen~::s of the present invention, the apparatus may utilize the same general geometric configuration of previously known drillable packers and bridge plugs while replacing at least some of the metal components with non-metallic materials which can still withstand the pressures and temperatures exposed thereto in many well bore applications. In other embodiments of the present invention, the apparatus may com~~r.ise specific design changes to accommodate the advantages of elastic materials and also to allow for the reduced strengths thereof compared to metal components.
In one embodimen of the downhole tool, the invention comprises a center mandrel and slips means disposed on the mandrel for grippingly engaging the well bore when in a set position. In packing embodiments, the apparatus further comprises a packing means disposed on the mandrc;l for sealingly engaging the well bore when in a set position.
In accordance with a further general aspect of the invention, there is provided a downhole tool for use in a well bore, the tool comprising a mandrel comprised of plastic, packing means disposed on the mandrel for sealingly engaging the well bore when in a set position, upper slip means disposed on the mandrel above the packing means, the upper slip means for grippingly engaging the well bore when in a set position, and lower slip means disposed on the mandrel below the packing means, the lower slip means for grippingly engaging the well bore when in a set position The slip means may comprise a wedge engaging a plurality of slips with a slip support on the opposite side of the slips from the wedge. Any of the mandrel, slips, slip wedges or slip supports may be made of the non-metallic material, such as plastic. Specific plastics include nylon, phenolic materials and epoxy resins.
The phenolic materials may further include any of Fiberite'~' FM4056J, Fiberite~~M
FM4005 or ResinoidT"' 1360. The plastic ~ompot~ents may be molded or machined.
One preferred plastic material for at least some of these components is a glass reinforced phenolic resin having a tensile strength of about 18,000 psi and a compressive strength of about 40,00U psi, although the invention is not intended to be limited to this particular plastic or a plastic having these specif a physical properties. The plastic materials are preferably selected such that the packing apparatus can withstand well pressures less than about 10,000 psi and temperatures less than about 425° F. In one preferred embodiment, but not by way of limitation, the plastic materials of the packing apparatus are selected such that the apparatus can withstand well pressures up to about 5,000 psi and temperatures up to about 250° F.
Most of the companents of the slip means are subjected to substantially compressive loading when in a sealed operating position in the well bore, although same tensile loading may also be experienced. The center mandrel typically has tensile loading applied thereto when setting the packer and when the packer is in its operating position.
One new method of the invention is a well bore process comprising the steps of positioning a downhole tool into engagement with the wel:~ bore; prior to the step of positioning, constructing the tool such that a component thereof is made of a non-metallic material; and then drilling the tool out of the well bore.. The tool may be selected from the group consisting packers and bridge plugs, but is not limited to these devices.
The component made of non--metallic material, may be one of several such components. The components may be substantially subject to compressive loading. Such components in the tool may include lock ring housings, slips, slip wedges and slip supports. Same components, such as center mandrels of such tools may be substantially subjected to tensile loading.
In another embodiment, the step of drilling is carried out using a polycrystalline diamond compact bit. Regardless of the type of drill. bit used, the ~arocess may further comprise the step of drilling using ~ drill bit without substantially varying the weight applied to the drill bit.
In another method of the invention, a well bore process comprises the steps of positioning and setting a packing device in the well bore, a portion of the device being made of engineering grade plastic; contacting the device with well fluids; and drilling out the device using a drill bit having no moving parts such as a polycrystalline diamond compact bit.
This or a similar drill bit might have been previously used in drilling the well bore itself, so the process may be said to further comprise the step of , prior to the step of positioning and setting the packer, drilling at least a portion of the well bore using a drill bit such as a polycrystalline diamond compact bit.
In one preferred embodiment, the step of contacting the packer is at a pressure of less than about 5, 000 psi and a temperature of less than about 2~0~~ F, although higher pressures and temperatures may also be encountered.
It is an important object of the invention to provide a downhole tool apparatus utilizing components made of non-metallic materials and methods of drilling thereof.
It is another object of the invention to provide a well bore packing apparatus using components made of engineering grade plastic.
An additional object of the invention is to provide a packing apparatus having a valve housing disposed substantially below a l~~wer end of a center mandrel and having a valve in the valve housing belo~the lower end of the center mandrel.
It is a further object of the invention to provide a packing apparatus which may be drilled by alternate methods to those using standard rotary drill bits.
Additional objects and advantages of the invention will become apparent as the following detailed description of the preferred embodiments is read in conjunction with the drawings which illustrate such preferred embodiments.
Brief Description Of The Drawinas FIG. 1 generally illustrates the downhole tool of the present invention positioned in a well bore with a drill bit disposed thereabove.
FIG. 2 illustrates a cross section of one embodiment of a drillable packer made in accordance with the invention.
FIGS. 3A and 38 show a cross section of a second embodiment of a drillable packer.
FIGS. 4A and 4B show a third drillable packer embodiment.
FIGS. 5A and 5B illustrate a fourth embodiment of a drillable packer.
FIGS. 6A and 6B show a fifth drillafPle packer embodiment with a poppet valve therein.
FIG. 7 shows a gross section of one embodiment of a drillable bridge plug made in accordance with the present invention.
FIG. 8 illustrates a second embodiment of a drillable bridge plug.
Description Of The Preferred Embodiment Referring now to the drawings, and more particularly to FIG. 1, the downhole tool apparatus of the present invention is shown and generally designated by the numeral 10.
Apparatus 10, which may include, but is not limited to, packers, bridge plugs, or~~similar devices, is shown in an operating position in a well bore 12. Apparatus 10 can be set in this position by any manner known in the art such as setting on a tubing string or wire line. A drill bit 14 connected to the end of a tool or tubing string 16 is shown above apparatus 10 in a position to commence the drilling out of apparatus 10 from well bore 12. Methods of drilling will be further discussed herein.
First Packer Embodiment Referring now to FIG. 2, the details of a first squeeze packer embodiment 20 of apparatus 10 wi.l.l be described. The size and configuration of packer 20 is substantially the same as the previously mentioned prior art ~'Z Driil SV~ squeeze packer. Packer 20 defines a generally central opening 21 therein.
Packer 20 comprises a center mandrel 22 on which most of the other components are mounted. F~ lock ring housing 24 is disposed around an upper end of mandrel 22 and generally encloses a lock ring 26.
Disposed below lack ring housing 24 and pivotally connected thereto are a plurality of upper slips 28 initially held in place by a retaining band 30. A generally conical upper slip wedge is disposed around nnandrel 22 adjacent to upper slips 30. Upper slip wedge 32 is held in place on mandrel 22 by a wedge retaining ring 34 and a plurality of screws 36.
Adjacent to the lower end of upper slip wedge 32 is an upper back-up ring 37 and arr'upper packer shoe 38 connected to the upper slip wedge by a pin 39. Below upper packer shoe 38 are a pair of end packer elements 40 separated by center packer element 42. A lower packer shoe 44 and lower back-up ring 45 are disposed adjacent to the lowermost end packer element 40.
A generally conical lower slip wedge 46 is positioned around mandrel 22 adjacent to lower packer shoe 44, and a pin 48 connects the lower packer shoe to the lower slip wedge.
Lower slip wedge 46 is initially attached to mandrel 22 by a plurality of screws 50 and a wedge retaining ring 52 in a manner similar to that for upper. slip wedge 32. A plurality of lower slips 54 are disposed adjacent tra lower slip wedge 46 and are initially held in place by a reta:~.ning band 56. Lower slips 54 are pivotally connected to the upper end of a lower slip support 58. Mandrel 22 is attached t.o lower slip support 58 at threaded connection 6i7.
Disposed in mandrel 22 at the upper end thereof is a tension sleeve 62 below which is an internal seal 64. Tension sleeve 62 is adapted for connection with a setting tool (not shown) of a kind known in the art.
A collet-latch sl,;ding valve 66 is :~lidably disposed in central opening 21 at the lower end of mandrel 22 adjacent to fluid ports 68 in the mandrel. Fluid ports 68 in mandrel 22 are in communication with f luid ports 7o in lower slip housing 58. The lower end of lower slip support 58 is closed below ports 70.
Sliding valve 66 defir~s a plurality of valve ports 72 ~~' which can be aligned with fluid ports 68 in mandrel 22 when sliding valve 66 is in an open position. Thus, fluid can flow through central opening 21.
On the upper end of sliding valve 66 are a plurality of collet fingers 67 which are adapted for latching and unlatching with a valve actuation tool knot shown) of a kind known in the art. This actuation tool is used to open and close sliding valve 66 as further discussed herein. As illustrated in FIG. 2, sliding valve 66 is in a closed position wherein fluid parts 68 are sealed by upper and lower valve seals 74 and 76.
In prior art dril.l.able packers and bridge plugs of this type, mandrel 22 is made of a medium hardness cast iron, and lock ring housing 24, upper slip wedge 32, lower slip wedge 46 and lower slip support 58 are made of soft cast iron for drillability. Most: ~~f the other components are made of aluminum, brass or rubber which, of course, are relatively easy to drill. Prior art upper and lower slips 28 and 54 are made of hard cast ircn, but are grooved so that they will easily be broken up in small. pa.eces when contacted by the drill bit during a drilling operation.
As previously described, the soft east iron construction of prior art lock ring housings, upper and lower slip wedges, and lower slip supports are adapted for relatively high pressure and temperature conditions, while a majority of well applications do not require a design for such conditions.
Thus, the apparatus of the present invention, which is generally designed for pressures lower than 10,000 psi and temperatures lower than 425° f., utilizes engineering grade plastics for at least .some of the components. For example, the apparatus may be designed for pressures up to about 5,000 psi and temperatures up to about 250° F., a:~though the invention is not intended to be limited to these particular conditions.
In first packer embodiment 20, at least some of the previously soft cast iron components of the slip means, such as lock ring housing 24, upper and lower slip wedges 32 and 46 and lower slip support 58 are made of engineering grade plastics. In particular, upper and lower slip wedges 32 and 46 are subjected to substantially compressive loading. Since engineering grade plastics exhibit good strength in compression, they make excellent choices for use in components subjected to compressive loading. Lower- slip support 58 is also subjected to substantially compressive loading and can be made of engineering grade plastic when packer 20 is subjected to relative law pressures and temperatures.
Lock ring housing 24 is mostly in compression, but does exhibit some tensile loading. However, in most situations, this tensile loading is minimal, and look ring housing 24 may also be made of an engineering grade; plastic of substantially the same type as upper and lower slips wedges 32 and 4(i anti also lower slips housing 58.
Upper and lower slips 28 and 54 may also be of plastic in some applications.
Hardened inserts for gripping well bore 12 when packer 20 is set may be required as part of the plastic slips. Such construction is discussed in more detail herein for other embodiments of the invention.
Lock ring housing 24, upper slip wedge 32, lower slip wedge 46, and lower slip housing 58 comprise approximately 75~%~ of the cast iron of the prior art squeeze packers. Thus, replacing these components with similar components made of engineering grade plastics will enhance the drillability of packer 20 and reduce the time and cost required therefor.
Mandrel 22 is subjected to tensile loading during setting and operation, and many plastics will not be acceptable materials therefore. However, some engineering plastics exhibit good tensile load~Tlg characteristics, so that construction of mandrel 22 from such plastics is possible. Reinforcements may be provided in the plastic resin as necessary.
Example A first embodiment packer 20 was constructed in which upper slip wedge 32 and lower slip wedge 46 were constructed by molding the parts to size from a phenolic resin plastic with glass reinforcement. The specific material used was FiberiteT"' 4056) manufactured by Fiberite Corporation of Winona, Minnesota. This material is classified by the manufacturer as a two stage phenolic with glass reinforcement. It has a tensile strength of 18,000 psi and a compressive strength of 40,000 psi.
The test packer 20 held to 8,500 psi without failure to wedges 32 and 46, more than sufficient for most well bore °w conditions.
Second Packer Embodiment Referring now to FIGS. 3A and 3B, the details of a second squeeze packer embodiment 100 of packing apparatus 10 are shown. While first embodiment 20 incorporates the same configuration and general components as prior art packers made of metal, second packer embodiment 100 and the other embodiments described herein comprise specific design features to accommodate the benefits and problems of using non-metallic components, such as plastic.
Packer 100 comprises a center mandrel 102 on which most of the other components are mounted. Mandrel 102 may be described as a thick cross-sectional mandrel having a relatively thicker wall thickness than typical packer mandrels, including center mandrel 22 of first embodiment 20.
A thick cross-sectional mandrel. may be r,~enerally defined as one in which the central opening therethrough has a diameter less than about half of the outside diameter of the mandrel.
That is, mandrel central opening 104 in central mandrel 102 has a diameter less than about half the outside of center mandrel 102. It is contemplated that. a thick cross-sectional mandrel will be required if it is constructed from a material having relatively low physical properties. In particular, such materials may include phenolics and similar plastic materials.
An upper support 106 is attached to the upper end of center mandrel 102 at trrreaded connection 108. In an alternate embodiment, center mandrel 102 and upper support 106 are integrally formed and there is no threaded connection 108.
A spacer ring or upper slip support 110 is disposed on the outside of mandrel 102 just below upper support 106. Spacer ring 110 is initially attached to center mandrel 102 by at least one shear pin 112. A downwardly and inwardly tapered shoulder 114 is defined on the lower side of spacer ring 110.
Disposed below spacer ring 110 are a plurality of upper slips 116. A downwardly and inwardly sloping shoulder 118 forms the upper end of each slip i16. The taper of each shoulder 118 conforms to the taper of shoulder 114 on spacer ring 110, and slips 116 are adapted for sliding engagement with shoulder 114, as will be further described herein.
An upwardly and inwardly facing taper 12o is defined in the lower end of each slip 116. Each taper 120 generally faces the outside of center mandrel 102.
A plurality of hardened inserts or teeth 122 preferably are molded into upper slips 116. In the embodiment shown in FIG. 3A, inserts 122 have a generally square cross section and are positioned at an angle so that a radially outer edge I24 protrudes from the corresponding upper slip 116. Outer edge 124 is adapted for grippingly engaging well bore 12 when packer 100 is set. It is not intended that inserts 322 be of square cross section and have a distinct outer edge 124.
Different shapes of inserts may also be used. Inserts 122 can be made of any suitable hardened material.
An upper slip wedge 126 is disposed adjacent to upper slips 116 and engages taper 120 therein. Upper slip wedge 126 is initially attached to center mandrel 102 by one or more shear pins 128.
Below upper slip wedge 126 are upper back-up ring 37, upper packer shoe 38~ end packer elements 40 separated by center packer element 42, lower packer shoe 44 and lower back-up ring 45 which are substantially the same as the corresponding components in first embodiment packer 20.
Accordingly, the same reference numerals are used.
Below lower back-up ring 45 is a lower slip wedge 130 which is initially attached to center mandrel 102 by a shear pin 132. Preferably, lower slip wedge 130 is identical to upper slip wedge 126 except that it i.s positioned in the opposite direction.
Lower slip wedge :L38 is in engagement with an inner taper I34 in a plurality of lower slips 236. Lower slips 136 have inserts or teeth 138 molded therein, and preferably, lower slips 136 are substantially identical to upper slips 126.
Each lower slip 136 has a downwardly facing shoulder which tapers upwardly and inwardly. Shoulders 136 are adapted for engagement with a corresponding shoulder 142 defining the ~$
upper end of a valve housing 144. Shoulder 142 also tapers upwardly and inwardly. Thus, valve housing 144 may also be considered a lower slip support 144.
Referring now also t,o FIG. 3B, valve housing 146 is attached to the lower end of center mandrel 102 at threaded connection 146. A sealing m?eans, such as O-ring 148, provides sealing engagement between valve hauling 144 and center mandrel 102.
Below the lower end of center mandrel 102, valve housing 104 defines a longitudinal opening 150 therein having a longitudinal rib 152 in the lower end thereof. At the upper end of opening 150 is an annular recess 1.54.
Below opening 150, valve housing 244 defines a housing central opening including a bore 156 therein having a closed lower end 158. A plurality of transverse ports 160 are defined through valve housing 144 and intersect bore 156. The wall thickness of valve housing 144 is thick enough to accommodate a pair of annular seal grooves 162 defined in bore 156 on opposite sides of ports 160.
Slidably disposed in valve housiz~~g 144 below center mandrel 102 is a sliding valve 164. SLie~ing valve 164 is the same as, or substantially similar to, sliding valve 66 in first embodiment packer 20. At the upper end of sliding valve 164 are a plurality of upwardly extending collet fingers 166 which initially engage recess 154 in valve housing 144.
Sliding valve 164 is shown in an uppermost, closed position in FIG. 3B. It will be seen that the lower end of center mandrel 102 prevents further upward movement of sliding valve 164.
Sliding valve 164 defines a valve central opening 168 therethrough which is in communication with central opening 104 in center mandrel 102. A chamfered shoulder 170 is located at the upper end of valve central opening 168.
Sliding valve 164 defines a plurality of substantially transverse ports 172 therethrough which intersect valve central opening 168. As will be further discussed herein, ports 172 are adapted for alignment with ports 160 in valve housing 144 when sliding valve 164 is in a downward, open position thereof. Ri.b 152 fits between a pair of collet fingers 166 so that sliding valve 164 cannot rotate within valve housing 144, thus insuring proper alignment of ports 172 and 160. Rib 152 thus provides an alignment means.
A sealing means, :such as O-ring 174, is disposed in each seal groove 162 and provides sealing engagement between sliding valve 164 and valve housing 144. It will thus be seen that when sliding valve 164 is moved downwardly to its open position, O-rings 174 seal on opposite sides of ports 172 in the sliding valve.
Referring again t:o FIS. ~A, a tension sleeve 174 is disposed in center mandrel 102 and attached thereto to threaded connection 176. Tension sleeve 174 has a threaded portion 178 which extends from center mandrel 102 and is adapted for connection to a standard setting tool (not shown) of a kind known in the art.
Below tension sleeve 174 is an internal seal 180 similar to internal seal 64 in first embodiment. 20.
Third Packer Embodiment Referring now to FIGS. 4A and 4B, a third squeeze packer embodiment of the present invention ishown and generally designated by the numeral 200. It will be clear to those skilled in the art that third embodiment 200 is similar to second packer embodiment 100 but has a couple of significant differences.
Packer 200 comprises a center mandrel 202. Unlike center mandrel 102 in second embodiment 100, center mandrel 202 is a thin cross-sectional mandrel. That is, it may be said that center mandrel 102 has a mandrel central opening 204 with a diameter greater than about half of the=. outside diameter of center mandrel 202. It is contemplaf:ed that thin cross-sectional mandrels, such as center mandrel 202, may be made of materials having relatively higher physical properties, such as epoxy resins.
The external components of third packer embodiment 200 which fit on the outside of center mandrel 202 are substantially identical to the outer womponents on second embodiment 100, and therefore the same reference numerals are shown in FIG. 4A. In a manner similar to second embodiment packer 100, center mandrel 202 and upper support 106 may be integrally formed so that there is no threaded connection 108.
The lower end of center mandrel 202 is attached to a valve housing 206 at threaded connectio~a 208. on the upper end of valve housing 20E is an upward~.y and inwardly tapered shoulder 210 against which shoulder 104 on lower slips 136 are slidably disposed. Thus, valve housing 206 may also be referred to as a lower slip support 206.
Referring now also to FIG. 4B, a sealing means, such as O-ring 212, provides sealing engagement between center mandrel 202 and valve housing 206.~~
Valve housing 206 defines a housing central opening including a bore 214 therein with a closed lower end 216. At the upper end of bare 214 is an annular recess 218. Valve housing 204 defines a plurality of substantially transverse ports 220 therethrough which intersect bore 214.
Slidably disposed in bore 214 in valve housing 206 is a sliding valve 222. At. the upper end of sliding valve 222 are a plurality of collet fingers 224 which initially engage recess 218.
Sliding valve 22'~ defines a plurality of substantially transverse ports 226 t:herei.n which intersect a valve central opening 228 in the sliding valve. Valve central opening 228 is in communication with mandrel central opening 204 in center mandrel 202. At the upper end of central opening 228 is a chamf eyed shou lder 2 3 () .
As shown in FIG. 4B, sliding valve 222 is in an uppermost closed position. It will be seen that the lower end of center mandrel 202 prevents further upward movement of sliding valve 222. When sliding valve 222 is moved d~~wnwardly to an open position, ports 226 are substantially aligned with ports 220 in valve housing 206. An alignment means, such as an alignment bolt 232, Extends from valve housing 206 inwardly between a pair of adjacent collet fingers 224. A sealing means, such as O-ring 234, provides sealing engagement between alignment bolt 232 and value housing 206. Alignment bolt 234 prevents rotation of sliding valve 222 within valve housing 204 and insures proper ali'~nment of ports 226 and 220 when sliding valve 222 is in its downwardmost, open position.
The wall thickness of sliding valve 222 is sufficient to accommodate a pair of spaced seal grooves 234 are defined in the outer surface of sliding valve 222, and as seen in FIG.
4B, seal grooves 234 are disposed on opposite sides of ports 220 when sliding valve 222 is in the open position shown. A
sealing means, such as seal 236, is disposed in each groove 234 to provide sealing engagement between sliding valve 222 and bore 214 in valve housing 2.06.
Referring again to FTG. 4A, a tension sleeve 238 is attached to the upper end of center mandrel 202 at threaded connection 240. A threaded portion 242 of tension sleeve 238 extends upwardly from center mandrel 202 and is adapted for engagement with a setting apparatus (not shown) of a kind known in the art.
An internal seal 244 is disposed in the upper end of center mandrel 202 below tension sleeve 238.
Fourth Packer Embodiment Referring now to FIGS. 5A and 58, a fourth squeeze packer embodiment is shown and generally designated by the numeral 300. As illustrated, fourth embodiment 300 has the same center mandrel 202, and all of the components positioned on the outside of center mandrel 202 are identical to those in the second and third packer embodiments. Therefore, the same reference numerals are used for these components. Tension sleeve 238 and internal seal 244 positioned on the inside of the upper end of center mandrel 202 are also substantially identical to the corresponding components in third embodiment packer 200 and therefore shown with the same reference numerals.
The difference between fourth packer embodiment 300 and third packer embodiment 200 is that in the fourth embodiment shown in FIGS. 5A and 5B, the lower end of center mandrel 202 is attached to a different valve housing 302 at threaded connection 304. Shoulder 140 on each lower slip I36 slidingly engages an upwardly and inwardly tapered shoulder 306 on the top of valve housing 302. Thus, valve housing 302 may also be referred to as Lower slip support 302.
Referring now to ~'IG. 5B, a sealing means, such as O-ring 308, provides sealing engagement between the lower end of center mandrel 202 and valve housing 3U2.
Valve housing 3U2 defines a housing central opening including a bore 310 therein with a closed lower end 312. A
bumper seal 314 is disposed adjacent to end 312.
Valve housing 3U2 defines a plurality of substantially transverse ports 316 therethrough which intersect bore 310.
A sliding valve 318 is dispos~:d in bore 310, and is shown in an uppermost, closed pasitioz~ ire FIG. 5B. It will be seen that the lower end of center mandrel 202 prevents upward movement of sliding valve 318. Sliding valve 318 defines a valve central opening 320 therethrough which is in communication with mandrel central opening 204 in center mandrel 202. At the upper end of valve central opening 320 in sliding valve 318 is an upwardly facing chamfered shoulder 322.
On the outer surface of sliding valve 318, a pair of spaced seal grooves 324 are defined, In the closed position shown in FIG. 5B, seal grooves 324 are on opposite sides of ports 316 in valve housing 302. A sealing means, such as seal 326, is disposed in each seal groove 324 and provides sealing engagement between sliding valve 318 and bore 310 in valve housing 302.
When sliding valve 318 is opened, as will be further described herein, the sliding valve 318 is moved downwardly such that upper end 328 thereof is below ports 316 in valve housing 302. Downward movement of sliding valve 318 is checked when lower end 330 thereof contacts bumper seal 314.
Bumper seal 314 is made of a res.i.l ien~t material which cushions the impact of sliding valve 318 thereon.
Fifth Packer Embodiment Referring now to FIGS. 6A and 6B, a fifth squeeze packer embodiment is shown and generally designated by the numeral 400. As illustrated, fifth packer embodiment 400 incorporates the same thick cross-sectional center mandrel 102 as does second packer embodiment 100 shown in fIG;~. 3A and 3B. Also, the external components positioned on center mandrel 102 are the same as in the second, third and fourth packer embodiments, so the same reference numerals will be used.
Further, tension sleeve 1~4 and internal seal 180 in second embodiment 100 are also incorporated in fifth embodiment 400, and therefore these same a~eference numerals have also been used.
The difference between fifth packer embodiment 400 and second embodiment 100 is that the lower end of center mandrel 102 is attached to a lower slip support 402 at threaded connection 404. Shoulders 140 on lower slips 136 slidingly engage an upwardly and inwardly tapered shoulder 406 at the upper end of lower slip support 402.
Referring now to ~'.IG. 6B, a sealing means, such as O-ring 408, provides sealing engagement between the lower end of center mandrel 102 and. lower slip support 402.
Lower slip support 402 defines a first bore 410 therein and a larger second bor_-e 422 spaced down~rardly from the first bore. A tapered seat surface 414 extends between first bore 410 and second bore 412.
The lower end of lower support 402 is attached to a valve housing 416 at threaded connection 418. Valve housing 416 defines a first bore 420 and a smaller second bore 422 therein. An upwardly facing annular shoulder 424 extends between first bore 420 and second bore 42'.?. Below second bore 422, valve housing 416 defines a third bore 426 therein with an internally threaded surface 428 forming a port at the lower end of the valve housing.
Disposed in first bare 420 in valve housing 416 is a valve body 430 with an upwardly facing annular shoulder 432 thereon. An elastomeric valve seal 434 and a valve spacer 436, which provides support for the valve seal, are positioned adjacent to shoulder 432 on~valve body 430. A conical valve head 438 is positioned above valve seal 434 and is attached to valve body 430 at threaded connection 440. It will be seen by those skilled in the art that valve seal 434 is adapted for sealing engagement with seat surface 414 in lower slip support 402 when valve body 430 is moved upwardly.
The lower end of valve body 430 is connected to a valve holder 442 by one or more pins 444. Valve holder 442 is disposed in second bore 422 of valve housing 416. A sealing means, such as D-ring 446 provides sealing engagement between valve holder 442 and valve housing 416.
Above shoulder 424 in valve housing 416, valve body 430 has a radially outwar°dly extending flange 448 thereon. A
biasing means, such as spring 450, is disposed between flange 448 and shoulder 424 foci biasing valve body 430 upwardly with respect to valve housing 416.
Valve holder 442 defines a first bore 452 and a smaller second bore 454 therein with an upwardly facing chamfered shoulder 456 extending therebetween. A ball 458 is disposed in valve holder 442 and is adapted for engagement with shoulder 456.
First Bridae Plua Embodiment Referring now to FIG. 7, a first bridge plug embodiment of the present invention is shown and generally designated by the numeral 500. First bridge plug embodiment 500 comprises the same center mandrel 102 and the external components positioned thereon as does4the second packer embodiment 100.-Therefore, the reference numerals for these components shown in FIG. 7 are the same as in FIG. 3A.
The lower end of center mandrel 102 in first bridge plug embodiment 500 is connected to a lower slip support 502 at threaded connection 504. An upwardly and inwardly tapered shoulder 506 on lower slip support 502 engages shoulders 140 on lower slips 136. As with the other embodiments, slips 136 axe adapted for sliding alc>ng shoulder 706.
Lower slip support 502 defines a bore 508 therein which is in communication wi ~h mandrel central opening 104 in center mandrel 102.
A bridging plug 51o is disposed in the upper portion of mandrel central opening 104 in center mandrel 102 and is sealingly engaged with internal seal 180. A radially outwardly extending flange 512 prevents bridging plug 510 from moving downwardly through center mandrel 102.
Above bridging plug 510 is tension sleeve 174, previously described far second packer embodiment 100.
Second Br~dae Plua Embodiment Referring now to FIG. 8, a second bridge plug embodiment of the present invention is shown and generally designated by the numeral 600. Second bridge plug embodiment 600 uses the same thin cross-sectional mandrel 202 as does third packer eembodiment 200 shown in FIG. 4A.
Also, the extE>rna.l component:s ,aositioned on center mandrel 202 are the same as pre~.riously described, so the same reference numerals are i..~sed in FIG. 8.
In second bridge plug embodiment 600, the lower end of center mandrel 202 is t~ttached to the same lower slip support 502 as first bridge plug embodiment 500 at threaded con.n~~ction 602. It will be seen that bare 508 irx lower sip support 502 is in communication with mandrel central opening 204 in center mandrel 202.
A bridging plug 604 is positioned in the upper end of mandrel centhal opening 204 in center mandrel 202. A shoul_dei: 608 in central. opening 204 prevents downward movement of bridging plug 604, A sealing means, such as a plurality of O-rings 606, provide sealing engagement between bri~~c~ing plug 604 and center mandrel 202.
Tension sleeve 2.38, previously described, is positioned above bridging plug 604.
Setting, And O~er~tion _Of_'Ihe A paratus Downhole tool apparatus 10 is positioned in well bore 12 and set into engagement therewith in a manner similar to prior art devices made with metallic c;omponent.s. Fc>r example, a pric3r art apparatus and setting thereof: is disc-Losed in the above-referenced U. S. Patent No. 4, 15~',.., 875 to Sull~way.
For first packer embodiment 20, the setting tool pulls upwardly on tension sleeve 62, and thereby on mandrel 22, while holding lock ring housing 24. The lock ring housing is thus moved relatively downwardly along mandrel 22 which forces upper slips 28 outwardly and shears screws 36, pushing upper slip wedge 32 downwardly against packer° elements 40 and 42.
Screws 50 are also sheared and lower slip wedge 46 is pushed downwardly toward lower slip support 58 to force lower slips 54 outwardly. Eventually, upper. slips 28 and lower slips 54 are placed in gripping engagement with well bore 12 and packer elements 40 and 42 are in sealing engagement with the well bore. The action of upper slips 28 and 54 prevent packer 20 from being unset. As will. be seen by Chase skilled in the art, pressure below packer 2o cannot fozmce the packer out of well bore 12, but instead, causes it to be even more tightly engaged.
Eventually, in the setting operation, tension sleeve 62 is sheared, so the setting tool may be removed from the well bore.
The setting of second packer embodiment 100, third packer embodiment 200, fourth packer embodiment 300, fifth packer embodiment 400, first bridge plug embodiment 5U0 and second bridge plug embodiment 600 is similar to that for first packer embodiment 20. The setting tool is attached to either tension sleeve 174 or 238. During setting, the setting tool pushes downwardly on upper slip support 110, thereby shearing shear pin 112. Upper slips 116 are moved downwardly with respect to upper slip wedge 126. Tapers 120 and upper slips 116 slide along upper slip wedge 126, and shoulders 118 on upper slips 116 slide along shoulder 114 on upper slip support 110. Thus, upper slips 116 are moved radially outwardly with respect to center mandrel 102 or 202 such that edges 124 of inserts 122 grippingly well bore 12.
Also during the setting operation, upper slip 126 is forced downwardly, shearing shear pin 128. This in turn causes packer elements 40 a»d 42 to be squeezed outwardly into sealing engagement with the well bore.
The lifting on center mandrel 102 or 202 causes the lower slip support (valve housing 144 in first packer embodiment 100, valve housing 206 in second packer embodiment 200, valve housing 302 in fourth packer embodimE~nt 300, lower slip support 402 in fifth packer embodiment 400, and lower slip support 502 in first bridge plug embodiment 500 and second bridge plug embodiment 600) to be moved up and lower slips 136 to be moved upwardly with respect to lower slip wedge 130.
Tapers 134 in lower slips 136 slide along lower slip wedge 130, and shoulders 140 on lower slips 136 slide along the corresponding shoulder 142, 210, 306, 406, or 506. Thus, lower slips 136 are moved radially outwardly with respect to center mandrel 102 or 202 sa that inserts 138 grippingly engage well bare 12.
Also during the setting operation, lower slip wedge 130 is forced upwardly, shearing shear pin 132, to provide additional squeezing force on packer elements 40 and 42.
The engagement of inserts 122 in upper slips 116 and inserts 138 in lowe~x~ slips 136 with well bore 12 prevent packers 100, 200, 300, 400 and bridge plugs 500, 600 from coming unset.
Once any of packers 20, 100, 200, 300, 400 are set, the valves therein may be actuated in a manner known in the art.
Sliding valve 164 in second packer embodiment 126, and sliding valve 22 in third packer embodiment 200 are set in a similar, if not identical manner. sliding valve 318 in fourth packer embodiment 300 is also set in a similar manner, but does not utilize collets, nor is alignment of sliding valve 318 with respect to ports 316 in valve housing 302 important. Sliding valve 318 is simply moved below ports 316 to open the valve.
Bumper seal 314 cushions the downward movement of sliding valve 318, thereby minimizing the possibility of damage to sliding valve 318 or valve housing 302 during an opening operation.
In fifth packer embodiment 400, the valve assembly comprising valve body 432, valve seal 434, valve spacer 436, valve head 438 and valve holder 442 is ~~perated in a manner substantially identical to that of the Ilal.liburton EZ Drills squeeze packer of the prior art.
Drillinc,~ Out The Packer Apparatus Drilling out any embodiment of downhole tool 10 may be carried out by using a standard drill bit at the end of tubing string 16. Cable tool drilling may also be used. With a standard "tri-cone" drill bit, the drilling operation is similar to that of the prior art except that variations in rotary speed and bit weight are not critical because the non-metallic materials are considerably softer than prior art cast iron, thus making tool 10 much easier to drill out. This greatly simplifies the drilling operation and reduces the cost and time thereof. ~' "
In addition to standard tri-cone drill bits, and particularly if tool 10 is constructed utilizing engineering grade plastics for the mandrel as well as for slip wedges, slips, slip supports and housings, alternate types of drill bits may be used which would be impossible for tools constructed substantially of cast iron. For example, polycrystalline diamond compact (PDC) bits may be used. Drill bit 14 in FIG. 1 is illustrated as a FDC bit. Such drill bits have the advantage of having no moving parts which can jam up.
Also, if the well bore itself was drilled with a PDC bit, it is not necessary to replace it with another or different type bit in order to drill out tool 10.
While specific sdueeze packer and bridge plug configurations of packing apparatus 10 has been described herein, it will be understood by those skilled in the art that other tools may also be constructed utilizing components selected of non-metallic materials, such as engineering grade plastics.
Additionally, components of the various packer embodiments may be interchanged. For example, thick cross-sectional center mandrel 102 may be uved with valve housing 206 in second packer embodiment 200 or valve housing 302 in fourth packer embodiment 300. Similarly, thin cross-sectional center mandrel 202 could be used with valve body 144 in second packer embodiment 100 or lower slip support 402 and valve housing 416 in fifth packer embodiment 400. The intent of the invention is to provide devises of flexible design in which a variety of configurations may be used.
It will be seen, therefore, that the downhole tool packer apparatus and methods of drilling thereof of the present invention are well adapted to carry out the ends and advantages mentioned as well as thaw inherent therein. While presently preferred embodiments of the apparatus and various drilling methods have been discussed for the purposes of this disclosure, numerous changes in the arrangement and construction of parts and the steps of the methods may be made by those skilled in the art. In particular, the invention is not intended to be limited to squeeze packers or bridge plugs.
AlI such changes are encompassed within the scope and spirit of the appended claims.
packer are designed for fast removal from the well bore by either rotary or cable tool drilling methods. Many of the components in these drillable packing devices are locked together to prevent their spinning while being drilled, and the harder slips are grooved' so that they will be broken up in small pieces. Typically, standard "tri-cone" rotary drill bits are used which are rotated at speeds of about 75 to about 120 rpm. A load of about 5,000 to about 7,000 pounds of weight is applied to the bit for initial drilling and increased as necessary to drill out the remainder of the packer or bridge plug, depending upon its size. Drill collars may be used as required for weight and bit stabilization.
Such drillable devices have worked well and provide improved operating performance at relatively high temperatures and pressures. The packers and plug mentioned above are designed to withstand pressures of about 10,000 psi and temperatures of about 425° F. after being set in the well bore. Such pressures and temperatures require the cast iron components previously discussed.
However, drilling out iron components requires certain techniques. Ideally, the operator employs variations in rotary speed and bit weight to help break up the metal parts and reestablish bit penetration should bit penetration cease while drilling. A phenomenon known as "bit tracking" can occur, wherein the drill bit stays on one path and no longer cuts into the downhole tool. When th~.s happens, it is necessary to pick up the bit above the drilling surface and rapidly recontact the bit with the packer or plug and apply weight while continuing rotation. This aids in breaking up the established bit pattern and helps to reestablish bit penetration. If this procedure is used, there are rarely problems. However, operators may not apply these techniques or even recognize when bit tracking has occurred. The result is that drilling times are greatly increased because the bit merely wears against the surface of the downhole tool rather than cutting into it to break it up.
While cast iron components may be necessary for the high pressures and temperatures for which they are designed, it has been determined that many welt's experience pressures less than 10,000 psi and temperatures less than 4~5° F. This includes most wells cemented. In fact, in the majority of wells, the pressure is less than about 5,000 psi, and the temperature is less than about 2S0° F. Thus, the heavy duty metal construction of the previous downhole tools, such as the packers and bridge plugs described above, is not necessary for many applications, and ia: cast iron components can be eliminated or minimi2;edJ the potential drilling problems resulting from bit tracking might be avoided as well.
The downhole tool of the present invention solves this problem by providing an apparatus wherein at least some of the components, including pressure bearing components, are made of non-metallic materials, such as engineering grade plastics.
Such plastic component:--.~ are mu<:h mor°e eas:a.ly drilled than cast iron, and new drilling methods may be employed which use alternative drill bits such as polycrystalline diamond compact bits, or the like, rather than standard tri-cone bits.
Summary Of The Invention The downhole tool apparatus of the present invention utilizes non-metallic mateYials, such as engineering grade plastics, to reduce weighty to reduce manufacturing time and labor, to improve performance through reducing frictional forces of sliding surfaces, to reduce costs and to improve drillability of the apparatus when drilling is required to remove the apparatus from the well bore Primarily, in this disclosure, the downhole tool is characterized by well bore packing apparatus, but it is not intended that the invention be limited to such packing devices. The non-metallic components in the downhole tool apparatus also allow the use of alternative drilJ_ing techniques v~o those previously known.
In packing apparatus embodimen~::s of the present invention, the apparatus may utilize the same general geometric configuration of previously known drillable packers and bridge plugs while replacing at least some of the metal components with non-metallic materials which can still withstand the pressures and temperatures exposed thereto in many well bore applications. In other embodiments of the present invention, the apparatus may com~~r.ise specific design changes to accommodate the advantages of elastic materials and also to allow for the reduced strengths thereof compared to metal components.
In one embodimen of the downhole tool, the invention comprises a center mandrel and slips means disposed on the mandrel for grippingly engaging the well bore when in a set position. In packing embodiments, the apparatus further comprises a packing means disposed on the mandrc;l for sealingly engaging the well bore when in a set position.
In accordance with a further general aspect of the invention, there is provided a downhole tool for use in a well bore, the tool comprising a mandrel comprised of plastic, packing means disposed on the mandrel for sealingly engaging the well bore when in a set position, upper slip means disposed on the mandrel above the packing means, the upper slip means for grippingly engaging the well bore when in a set position, and lower slip means disposed on the mandrel below the packing means, the lower slip means for grippingly engaging the well bore when in a set position The slip means may comprise a wedge engaging a plurality of slips with a slip support on the opposite side of the slips from the wedge. Any of the mandrel, slips, slip wedges or slip supports may be made of the non-metallic material, such as plastic. Specific plastics include nylon, phenolic materials and epoxy resins.
The phenolic materials may further include any of Fiberite'~' FM4056J, Fiberite~~M
FM4005 or ResinoidT"' 1360. The plastic ~ompot~ents may be molded or machined.
One preferred plastic material for at least some of these components is a glass reinforced phenolic resin having a tensile strength of about 18,000 psi and a compressive strength of about 40,00U psi, although the invention is not intended to be limited to this particular plastic or a plastic having these specif a physical properties. The plastic materials are preferably selected such that the packing apparatus can withstand well pressures less than about 10,000 psi and temperatures less than about 425° F. In one preferred embodiment, but not by way of limitation, the plastic materials of the packing apparatus are selected such that the apparatus can withstand well pressures up to about 5,000 psi and temperatures up to about 250° F.
Most of the companents of the slip means are subjected to substantially compressive loading when in a sealed operating position in the well bore, although same tensile loading may also be experienced. The center mandrel typically has tensile loading applied thereto when setting the packer and when the packer is in its operating position.
One new method of the invention is a well bore process comprising the steps of positioning a downhole tool into engagement with the wel:~ bore; prior to the step of positioning, constructing the tool such that a component thereof is made of a non-metallic material; and then drilling the tool out of the well bore.. The tool may be selected from the group consisting packers and bridge plugs, but is not limited to these devices.
The component made of non--metallic material, may be one of several such components. The components may be substantially subject to compressive loading. Such components in the tool may include lock ring housings, slips, slip wedges and slip supports. Same components, such as center mandrels of such tools may be substantially subjected to tensile loading.
In another embodiment, the step of drilling is carried out using a polycrystalline diamond compact bit. Regardless of the type of drill. bit used, the ~arocess may further comprise the step of drilling using ~ drill bit without substantially varying the weight applied to the drill bit.
In another method of the invention, a well bore process comprises the steps of positioning and setting a packing device in the well bore, a portion of the device being made of engineering grade plastic; contacting the device with well fluids; and drilling out the device using a drill bit having no moving parts such as a polycrystalline diamond compact bit.
This or a similar drill bit might have been previously used in drilling the well bore itself, so the process may be said to further comprise the step of , prior to the step of positioning and setting the packer, drilling at least a portion of the well bore using a drill bit such as a polycrystalline diamond compact bit.
In one preferred embodiment, the step of contacting the packer is at a pressure of less than about 5, 000 psi and a temperature of less than about 2~0~~ F, although higher pressures and temperatures may also be encountered.
It is an important object of the invention to provide a downhole tool apparatus utilizing components made of non-metallic materials and methods of drilling thereof.
It is another object of the invention to provide a well bore packing apparatus using components made of engineering grade plastic.
An additional object of the invention is to provide a packing apparatus having a valve housing disposed substantially below a l~~wer end of a center mandrel and having a valve in the valve housing belo~the lower end of the center mandrel.
It is a further object of the invention to provide a packing apparatus which may be drilled by alternate methods to those using standard rotary drill bits.
Additional objects and advantages of the invention will become apparent as the following detailed description of the preferred embodiments is read in conjunction with the drawings which illustrate such preferred embodiments.
Brief Description Of The Drawinas FIG. 1 generally illustrates the downhole tool of the present invention positioned in a well bore with a drill bit disposed thereabove.
FIG. 2 illustrates a cross section of one embodiment of a drillable packer made in accordance with the invention.
FIGS. 3A and 38 show a cross section of a second embodiment of a drillable packer.
FIGS. 4A and 4B show a third drillable packer embodiment.
FIGS. 5A and 5B illustrate a fourth embodiment of a drillable packer.
FIGS. 6A and 6B show a fifth drillafPle packer embodiment with a poppet valve therein.
FIG. 7 shows a gross section of one embodiment of a drillable bridge plug made in accordance with the present invention.
FIG. 8 illustrates a second embodiment of a drillable bridge plug.
Description Of The Preferred Embodiment Referring now to the drawings, and more particularly to FIG. 1, the downhole tool apparatus of the present invention is shown and generally designated by the numeral 10.
Apparatus 10, which may include, but is not limited to, packers, bridge plugs, or~~similar devices, is shown in an operating position in a well bore 12. Apparatus 10 can be set in this position by any manner known in the art such as setting on a tubing string or wire line. A drill bit 14 connected to the end of a tool or tubing string 16 is shown above apparatus 10 in a position to commence the drilling out of apparatus 10 from well bore 12. Methods of drilling will be further discussed herein.
First Packer Embodiment Referring now to FIG. 2, the details of a first squeeze packer embodiment 20 of apparatus 10 wi.l.l be described. The size and configuration of packer 20 is substantially the same as the previously mentioned prior art ~'Z Driil SV~ squeeze packer. Packer 20 defines a generally central opening 21 therein.
Packer 20 comprises a center mandrel 22 on which most of the other components are mounted. F~ lock ring housing 24 is disposed around an upper end of mandrel 22 and generally encloses a lock ring 26.
Disposed below lack ring housing 24 and pivotally connected thereto are a plurality of upper slips 28 initially held in place by a retaining band 30. A generally conical upper slip wedge is disposed around nnandrel 22 adjacent to upper slips 30. Upper slip wedge 32 is held in place on mandrel 22 by a wedge retaining ring 34 and a plurality of screws 36.
Adjacent to the lower end of upper slip wedge 32 is an upper back-up ring 37 and arr'upper packer shoe 38 connected to the upper slip wedge by a pin 39. Below upper packer shoe 38 are a pair of end packer elements 40 separated by center packer element 42. A lower packer shoe 44 and lower back-up ring 45 are disposed adjacent to the lowermost end packer element 40.
A generally conical lower slip wedge 46 is positioned around mandrel 22 adjacent to lower packer shoe 44, and a pin 48 connects the lower packer shoe to the lower slip wedge.
Lower slip wedge 46 is initially attached to mandrel 22 by a plurality of screws 50 and a wedge retaining ring 52 in a manner similar to that for upper. slip wedge 32. A plurality of lower slips 54 are disposed adjacent tra lower slip wedge 46 and are initially held in place by a reta:~.ning band 56. Lower slips 54 are pivotally connected to the upper end of a lower slip support 58. Mandrel 22 is attached t.o lower slip support 58 at threaded connection 6i7.
Disposed in mandrel 22 at the upper end thereof is a tension sleeve 62 below which is an internal seal 64. Tension sleeve 62 is adapted for connection with a setting tool (not shown) of a kind known in the art.
A collet-latch sl,;ding valve 66 is :~lidably disposed in central opening 21 at the lower end of mandrel 22 adjacent to fluid ports 68 in the mandrel. Fluid ports 68 in mandrel 22 are in communication with f luid ports 7o in lower slip housing 58. The lower end of lower slip support 58 is closed below ports 70.
Sliding valve 66 defir~s a plurality of valve ports 72 ~~' which can be aligned with fluid ports 68 in mandrel 22 when sliding valve 66 is in an open position. Thus, fluid can flow through central opening 21.
On the upper end of sliding valve 66 are a plurality of collet fingers 67 which are adapted for latching and unlatching with a valve actuation tool knot shown) of a kind known in the art. This actuation tool is used to open and close sliding valve 66 as further discussed herein. As illustrated in FIG. 2, sliding valve 66 is in a closed position wherein fluid parts 68 are sealed by upper and lower valve seals 74 and 76.
In prior art dril.l.able packers and bridge plugs of this type, mandrel 22 is made of a medium hardness cast iron, and lock ring housing 24, upper slip wedge 32, lower slip wedge 46 and lower slip support 58 are made of soft cast iron for drillability. Most: ~~f the other components are made of aluminum, brass or rubber which, of course, are relatively easy to drill. Prior art upper and lower slips 28 and 54 are made of hard cast ircn, but are grooved so that they will easily be broken up in small. pa.eces when contacted by the drill bit during a drilling operation.
As previously described, the soft east iron construction of prior art lock ring housings, upper and lower slip wedges, and lower slip supports are adapted for relatively high pressure and temperature conditions, while a majority of well applications do not require a design for such conditions.
Thus, the apparatus of the present invention, which is generally designed for pressures lower than 10,000 psi and temperatures lower than 425° f., utilizes engineering grade plastics for at least .some of the components. For example, the apparatus may be designed for pressures up to about 5,000 psi and temperatures up to about 250° F., a:~though the invention is not intended to be limited to these particular conditions.
In first packer embodiment 20, at least some of the previously soft cast iron components of the slip means, such as lock ring housing 24, upper and lower slip wedges 32 and 46 and lower slip support 58 are made of engineering grade plastics. In particular, upper and lower slip wedges 32 and 46 are subjected to substantially compressive loading. Since engineering grade plastics exhibit good strength in compression, they make excellent choices for use in components subjected to compressive loading. Lower- slip support 58 is also subjected to substantially compressive loading and can be made of engineering grade plastic when packer 20 is subjected to relative law pressures and temperatures.
Lock ring housing 24 is mostly in compression, but does exhibit some tensile loading. However, in most situations, this tensile loading is minimal, and look ring housing 24 may also be made of an engineering grade; plastic of substantially the same type as upper and lower slips wedges 32 and 4(i anti also lower slips housing 58.
Upper and lower slips 28 and 54 may also be of plastic in some applications.
Hardened inserts for gripping well bore 12 when packer 20 is set may be required as part of the plastic slips. Such construction is discussed in more detail herein for other embodiments of the invention.
Lock ring housing 24, upper slip wedge 32, lower slip wedge 46, and lower slip housing 58 comprise approximately 75~%~ of the cast iron of the prior art squeeze packers. Thus, replacing these components with similar components made of engineering grade plastics will enhance the drillability of packer 20 and reduce the time and cost required therefor.
Mandrel 22 is subjected to tensile loading during setting and operation, and many plastics will not be acceptable materials therefore. However, some engineering plastics exhibit good tensile load~Tlg characteristics, so that construction of mandrel 22 from such plastics is possible. Reinforcements may be provided in the plastic resin as necessary.
Example A first embodiment packer 20 was constructed in which upper slip wedge 32 and lower slip wedge 46 were constructed by molding the parts to size from a phenolic resin plastic with glass reinforcement. The specific material used was FiberiteT"' 4056) manufactured by Fiberite Corporation of Winona, Minnesota. This material is classified by the manufacturer as a two stage phenolic with glass reinforcement. It has a tensile strength of 18,000 psi and a compressive strength of 40,000 psi.
The test packer 20 held to 8,500 psi without failure to wedges 32 and 46, more than sufficient for most well bore °w conditions.
Second Packer Embodiment Referring now to FIGS. 3A and 3B, the details of a second squeeze packer embodiment 100 of packing apparatus 10 are shown. While first embodiment 20 incorporates the same configuration and general components as prior art packers made of metal, second packer embodiment 100 and the other embodiments described herein comprise specific design features to accommodate the benefits and problems of using non-metallic components, such as plastic.
Packer 100 comprises a center mandrel 102 on which most of the other components are mounted. Mandrel 102 may be described as a thick cross-sectional mandrel having a relatively thicker wall thickness than typical packer mandrels, including center mandrel 22 of first embodiment 20.
A thick cross-sectional mandrel. may be r,~enerally defined as one in which the central opening therethrough has a diameter less than about half of the outside diameter of the mandrel.
That is, mandrel central opening 104 in central mandrel 102 has a diameter less than about half the outside of center mandrel 102. It is contemplated that. a thick cross-sectional mandrel will be required if it is constructed from a material having relatively low physical properties. In particular, such materials may include phenolics and similar plastic materials.
An upper support 106 is attached to the upper end of center mandrel 102 at trrreaded connection 108. In an alternate embodiment, center mandrel 102 and upper support 106 are integrally formed and there is no threaded connection 108.
A spacer ring or upper slip support 110 is disposed on the outside of mandrel 102 just below upper support 106. Spacer ring 110 is initially attached to center mandrel 102 by at least one shear pin 112. A downwardly and inwardly tapered shoulder 114 is defined on the lower side of spacer ring 110.
Disposed below spacer ring 110 are a plurality of upper slips 116. A downwardly and inwardly sloping shoulder 118 forms the upper end of each slip i16. The taper of each shoulder 118 conforms to the taper of shoulder 114 on spacer ring 110, and slips 116 are adapted for sliding engagement with shoulder 114, as will be further described herein.
An upwardly and inwardly facing taper 12o is defined in the lower end of each slip 116. Each taper 120 generally faces the outside of center mandrel 102.
A plurality of hardened inserts or teeth 122 preferably are molded into upper slips 116. In the embodiment shown in FIG. 3A, inserts 122 have a generally square cross section and are positioned at an angle so that a radially outer edge I24 protrudes from the corresponding upper slip 116. Outer edge 124 is adapted for grippingly engaging well bore 12 when packer 100 is set. It is not intended that inserts 322 be of square cross section and have a distinct outer edge 124.
Different shapes of inserts may also be used. Inserts 122 can be made of any suitable hardened material.
An upper slip wedge 126 is disposed adjacent to upper slips 116 and engages taper 120 therein. Upper slip wedge 126 is initially attached to center mandrel 102 by one or more shear pins 128.
Below upper slip wedge 126 are upper back-up ring 37, upper packer shoe 38~ end packer elements 40 separated by center packer element 42, lower packer shoe 44 and lower back-up ring 45 which are substantially the same as the corresponding components in first embodiment packer 20.
Accordingly, the same reference numerals are used.
Below lower back-up ring 45 is a lower slip wedge 130 which is initially attached to center mandrel 102 by a shear pin 132. Preferably, lower slip wedge 130 is identical to upper slip wedge 126 except that it i.s positioned in the opposite direction.
Lower slip wedge :L38 is in engagement with an inner taper I34 in a plurality of lower slips 236. Lower slips 136 have inserts or teeth 138 molded therein, and preferably, lower slips 136 are substantially identical to upper slips 126.
Each lower slip 136 has a downwardly facing shoulder which tapers upwardly and inwardly. Shoulders 136 are adapted for engagement with a corresponding shoulder 142 defining the ~$
upper end of a valve housing 144. Shoulder 142 also tapers upwardly and inwardly. Thus, valve housing 144 may also be considered a lower slip support 144.
Referring now also t,o FIG. 3B, valve housing 146 is attached to the lower end of center mandrel 102 at threaded connection 146. A sealing m?eans, such as O-ring 148, provides sealing engagement between valve hauling 144 and center mandrel 102.
Below the lower end of center mandrel 102, valve housing 104 defines a longitudinal opening 150 therein having a longitudinal rib 152 in the lower end thereof. At the upper end of opening 150 is an annular recess 1.54.
Below opening 150, valve housing 244 defines a housing central opening including a bore 156 therein having a closed lower end 158. A plurality of transverse ports 160 are defined through valve housing 144 and intersect bore 156. The wall thickness of valve housing 144 is thick enough to accommodate a pair of annular seal grooves 162 defined in bore 156 on opposite sides of ports 160.
Slidably disposed in valve housiz~~g 144 below center mandrel 102 is a sliding valve 164. SLie~ing valve 164 is the same as, or substantially similar to, sliding valve 66 in first embodiment packer 20. At the upper end of sliding valve 164 are a plurality of upwardly extending collet fingers 166 which initially engage recess 154 in valve housing 144.
Sliding valve 164 is shown in an uppermost, closed position in FIG. 3B. It will be seen that the lower end of center mandrel 102 prevents further upward movement of sliding valve 164.
Sliding valve 164 defines a valve central opening 168 therethrough which is in communication with central opening 104 in center mandrel 102. A chamfered shoulder 170 is located at the upper end of valve central opening 168.
Sliding valve 164 defines a plurality of substantially transverse ports 172 therethrough which intersect valve central opening 168. As will be further discussed herein, ports 172 are adapted for alignment with ports 160 in valve housing 144 when sliding valve 164 is in a downward, open position thereof. Ri.b 152 fits between a pair of collet fingers 166 so that sliding valve 164 cannot rotate within valve housing 144, thus insuring proper alignment of ports 172 and 160. Rib 152 thus provides an alignment means.
A sealing means, :such as O-ring 174, is disposed in each seal groove 162 and provides sealing engagement between sliding valve 164 and valve housing 144. It will thus be seen that when sliding valve 164 is moved downwardly to its open position, O-rings 174 seal on opposite sides of ports 172 in the sliding valve.
Referring again t:o FIS. ~A, a tension sleeve 174 is disposed in center mandrel 102 and attached thereto to threaded connection 176. Tension sleeve 174 has a threaded portion 178 which extends from center mandrel 102 and is adapted for connection to a standard setting tool (not shown) of a kind known in the art.
Below tension sleeve 174 is an internal seal 180 similar to internal seal 64 in first embodiment. 20.
Third Packer Embodiment Referring now to FIGS. 4A and 4B, a third squeeze packer embodiment of the present invention ishown and generally designated by the numeral 200. It will be clear to those skilled in the art that third embodiment 200 is similar to second packer embodiment 100 but has a couple of significant differences.
Packer 200 comprises a center mandrel 202. Unlike center mandrel 102 in second embodiment 100, center mandrel 202 is a thin cross-sectional mandrel. That is, it may be said that center mandrel 102 has a mandrel central opening 204 with a diameter greater than about half of the=. outside diameter of center mandrel 202. It is contemplaf:ed that thin cross-sectional mandrels, such as center mandrel 202, may be made of materials having relatively higher physical properties, such as epoxy resins.
The external components of third packer embodiment 200 which fit on the outside of center mandrel 202 are substantially identical to the outer womponents on second embodiment 100, and therefore the same reference numerals are shown in FIG. 4A. In a manner similar to second embodiment packer 100, center mandrel 202 and upper support 106 may be integrally formed so that there is no threaded connection 108.
The lower end of center mandrel 202 is attached to a valve housing 206 at threaded connectio~a 208. on the upper end of valve housing 20E is an upward~.y and inwardly tapered shoulder 210 against which shoulder 104 on lower slips 136 are slidably disposed. Thus, valve housing 206 may also be referred to as a lower slip support 206.
Referring now also to FIG. 4B, a sealing means, such as O-ring 212, provides sealing engagement between center mandrel 202 and valve housing 206.~~
Valve housing 206 defines a housing central opening including a bore 214 therein with a closed lower end 216. At the upper end of bare 214 is an annular recess 218. Valve housing 204 defines a plurality of substantially transverse ports 220 therethrough which intersect bore 214.
Slidably disposed in bore 214 in valve housing 206 is a sliding valve 222. At. the upper end of sliding valve 222 are a plurality of collet fingers 224 which initially engage recess 218.
Sliding valve 22'~ defines a plurality of substantially transverse ports 226 t:herei.n which intersect a valve central opening 228 in the sliding valve. Valve central opening 228 is in communication with mandrel central opening 204 in center mandrel 202. At the upper end of central opening 228 is a chamf eyed shou lder 2 3 () .
As shown in FIG. 4B, sliding valve 222 is in an uppermost closed position. It will be seen that the lower end of center mandrel 202 prevents further upward movement of sliding valve 222. When sliding valve 222 is moved d~~wnwardly to an open position, ports 226 are substantially aligned with ports 220 in valve housing 206. An alignment means, such as an alignment bolt 232, Extends from valve housing 206 inwardly between a pair of adjacent collet fingers 224. A sealing means, such as O-ring 234, provides sealing engagement between alignment bolt 232 and value housing 206. Alignment bolt 234 prevents rotation of sliding valve 222 within valve housing 204 and insures proper ali'~nment of ports 226 and 220 when sliding valve 222 is in its downwardmost, open position.
The wall thickness of sliding valve 222 is sufficient to accommodate a pair of spaced seal grooves 234 are defined in the outer surface of sliding valve 222, and as seen in FIG.
4B, seal grooves 234 are disposed on opposite sides of ports 220 when sliding valve 222 is in the open position shown. A
sealing means, such as seal 236, is disposed in each groove 234 to provide sealing engagement between sliding valve 222 and bore 214 in valve housing 2.06.
Referring again to FTG. 4A, a tension sleeve 238 is attached to the upper end of center mandrel 202 at threaded connection 240. A threaded portion 242 of tension sleeve 238 extends upwardly from center mandrel 202 and is adapted for engagement with a setting apparatus (not shown) of a kind known in the art.
An internal seal 244 is disposed in the upper end of center mandrel 202 below tension sleeve 238.
Fourth Packer Embodiment Referring now to FIGS. 5A and 58, a fourth squeeze packer embodiment is shown and generally designated by the numeral 300. As illustrated, fourth embodiment 300 has the same center mandrel 202, and all of the components positioned on the outside of center mandrel 202 are identical to those in the second and third packer embodiments. Therefore, the same reference numerals are used for these components. Tension sleeve 238 and internal seal 244 positioned on the inside of the upper end of center mandrel 202 are also substantially identical to the corresponding components in third embodiment packer 200 and therefore shown with the same reference numerals.
The difference between fourth packer embodiment 300 and third packer embodiment 200 is that in the fourth embodiment shown in FIGS. 5A and 5B, the lower end of center mandrel 202 is attached to a different valve housing 302 at threaded connection 304. Shoulder 140 on each lower slip I36 slidingly engages an upwardly and inwardly tapered shoulder 306 on the top of valve housing 302. Thus, valve housing 302 may also be referred to as Lower slip support 302.
Referring now to ~'IG. 5B, a sealing means, such as O-ring 308, provides sealing engagement between the lower end of center mandrel 202 and valve housing 3U2.
Valve housing 3U2 defines a housing central opening including a bore 310 therein with a closed lower end 312. A
bumper seal 314 is disposed adjacent to end 312.
Valve housing 3U2 defines a plurality of substantially transverse ports 316 therethrough which intersect bore 310.
A sliding valve 318 is dispos~:d in bore 310, and is shown in an uppermost, closed pasitioz~ ire FIG. 5B. It will be seen that the lower end of center mandrel 202 prevents upward movement of sliding valve 318. Sliding valve 318 defines a valve central opening 320 therethrough which is in communication with mandrel central opening 204 in center mandrel 202. At the upper end of valve central opening 320 in sliding valve 318 is an upwardly facing chamfered shoulder 322.
On the outer surface of sliding valve 318, a pair of spaced seal grooves 324 are defined, In the closed position shown in FIG. 5B, seal grooves 324 are on opposite sides of ports 316 in valve housing 302. A sealing means, such as seal 326, is disposed in each seal groove 324 and provides sealing engagement between sliding valve 318 and bore 310 in valve housing 302.
When sliding valve 318 is opened, as will be further described herein, the sliding valve 318 is moved downwardly such that upper end 328 thereof is below ports 316 in valve housing 302. Downward movement of sliding valve 318 is checked when lower end 330 thereof contacts bumper seal 314.
Bumper seal 314 is made of a res.i.l ien~t material which cushions the impact of sliding valve 318 thereon.
Fifth Packer Embodiment Referring now to FIGS. 6A and 6B, a fifth squeeze packer embodiment is shown and generally designated by the numeral 400. As illustrated, fifth packer embodiment 400 incorporates the same thick cross-sectional center mandrel 102 as does second packer embodiment 100 shown in fIG;~. 3A and 3B. Also, the external components positioned on center mandrel 102 are the same as in the second, third and fourth packer embodiments, so the same reference numerals will be used.
Further, tension sleeve 1~4 and internal seal 180 in second embodiment 100 are also incorporated in fifth embodiment 400, and therefore these same a~eference numerals have also been used.
The difference between fifth packer embodiment 400 and second embodiment 100 is that the lower end of center mandrel 102 is attached to a lower slip support 402 at threaded connection 404. Shoulders 140 on lower slips 136 slidingly engage an upwardly and inwardly tapered shoulder 406 at the upper end of lower slip support 402.
Referring now to ~'.IG. 6B, a sealing means, such as O-ring 408, provides sealing engagement between the lower end of center mandrel 102 and. lower slip support 402.
Lower slip support 402 defines a first bore 410 therein and a larger second bor_-e 422 spaced down~rardly from the first bore. A tapered seat surface 414 extends between first bore 410 and second bore 412.
The lower end of lower support 402 is attached to a valve housing 416 at threaded connection 418. Valve housing 416 defines a first bore 420 and a smaller second bore 422 therein. An upwardly facing annular shoulder 424 extends between first bore 420 and second bore 42'.?. Below second bore 422, valve housing 416 defines a third bore 426 therein with an internally threaded surface 428 forming a port at the lower end of the valve housing.
Disposed in first bare 420 in valve housing 416 is a valve body 430 with an upwardly facing annular shoulder 432 thereon. An elastomeric valve seal 434 and a valve spacer 436, which provides support for the valve seal, are positioned adjacent to shoulder 432 on~valve body 430. A conical valve head 438 is positioned above valve seal 434 and is attached to valve body 430 at threaded connection 440. It will be seen by those skilled in the art that valve seal 434 is adapted for sealing engagement with seat surface 414 in lower slip support 402 when valve body 430 is moved upwardly.
The lower end of valve body 430 is connected to a valve holder 442 by one or more pins 444. Valve holder 442 is disposed in second bore 422 of valve housing 416. A sealing means, such as D-ring 446 provides sealing engagement between valve holder 442 and valve housing 416.
Above shoulder 424 in valve housing 416, valve body 430 has a radially outwar°dly extending flange 448 thereon. A
biasing means, such as spring 450, is disposed between flange 448 and shoulder 424 foci biasing valve body 430 upwardly with respect to valve housing 416.
Valve holder 442 defines a first bore 452 and a smaller second bore 454 therein with an upwardly facing chamfered shoulder 456 extending therebetween. A ball 458 is disposed in valve holder 442 and is adapted for engagement with shoulder 456.
First Bridae Plua Embodiment Referring now to FIG. 7, a first bridge plug embodiment of the present invention is shown and generally designated by the numeral 500. First bridge plug embodiment 500 comprises the same center mandrel 102 and the external components positioned thereon as does4the second packer embodiment 100.-Therefore, the reference numerals for these components shown in FIG. 7 are the same as in FIG. 3A.
The lower end of center mandrel 102 in first bridge plug embodiment 500 is connected to a lower slip support 502 at threaded connection 504. An upwardly and inwardly tapered shoulder 506 on lower slip support 502 engages shoulders 140 on lower slips 136. As with the other embodiments, slips 136 axe adapted for sliding alc>ng shoulder 706.
Lower slip support 502 defines a bore 508 therein which is in communication wi ~h mandrel central opening 104 in center mandrel 102.
A bridging plug 51o is disposed in the upper portion of mandrel central opening 104 in center mandrel 102 and is sealingly engaged with internal seal 180. A radially outwardly extending flange 512 prevents bridging plug 510 from moving downwardly through center mandrel 102.
Above bridging plug 510 is tension sleeve 174, previously described far second packer embodiment 100.
Second Br~dae Plua Embodiment Referring now to FIG. 8, a second bridge plug embodiment of the present invention is shown and generally designated by the numeral 600. Second bridge plug embodiment 600 uses the same thin cross-sectional mandrel 202 as does third packer eembodiment 200 shown in FIG. 4A.
Also, the extE>rna.l component:s ,aositioned on center mandrel 202 are the same as pre~.riously described, so the same reference numerals are i..~sed in FIG. 8.
In second bridge plug embodiment 600, the lower end of center mandrel 202 is t~ttached to the same lower slip support 502 as first bridge plug embodiment 500 at threaded con.n~~ction 602. It will be seen that bare 508 irx lower sip support 502 is in communication with mandrel central opening 204 in center mandrel 202.
A bridging plug 604 is positioned in the upper end of mandrel centhal opening 204 in center mandrel 202. A shoul_dei: 608 in central. opening 204 prevents downward movement of bridging plug 604, A sealing means, such as a plurality of O-rings 606, provide sealing engagement between bri~~c~ing plug 604 and center mandrel 202.
Tension sleeve 2.38, previously described, is positioned above bridging plug 604.
Setting, And O~er~tion _Of_'Ihe A paratus Downhole tool apparatus 10 is positioned in well bore 12 and set into engagement therewith in a manner similar to prior art devices made with metallic c;omponent.s. Fc>r example, a pric3r art apparatus and setting thereof: is disc-Losed in the above-referenced U. S. Patent No. 4, 15~',.., 875 to Sull~way.
For first packer embodiment 20, the setting tool pulls upwardly on tension sleeve 62, and thereby on mandrel 22, while holding lock ring housing 24. The lock ring housing is thus moved relatively downwardly along mandrel 22 which forces upper slips 28 outwardly and shears screws 36, pushing upper slip wedge 32 downwardly against packer° elements 40 and 42.
Screws 50 are also sheared and lower slip wedge 46 is pushed downwardly toward lower slip support 58 to force lower slips 54 outwardly. Eventually, upper. slips 28 and lower slips 54 are placed in gripping engagement with well bore 12 and packer elements 40 and 42 are in sealing engagement with the well bore. The action of upper slips 28 and 54 prevent packer 20 from being unset. As will. be seen by Chase skilled in the art, pressure below packer 2o cannot fozmce the packer out of well bore 12, but instead, causes it to be even more tightly engaged.
Eventually, in the setting operation, tension sleeve 62 is sheared, so the setting tool may be removed from the well bore.
The setting of second packer embodiment 100, third packer embodiment 200, fourth packer embodiment 300, fifth packer embodiment 400, first bridge plug embodiment 5U0 and second bridge plug embodiment 600 is similar to that for first packer embodiment 20. The setting tool is attached to either tension sleeve 174 or 238. During setting, the setting tool pushes downwardly on upper slip support 110, thereby shearing shear pin 112. Upper slips 116 are moved downwardly with respect to upper slip wedge 126. Tapers 120 and upper slips 116 slide along upper slip wedge 126, and shoulders 118 on upper slips 116 slide along shoulder 114 on upper slip support 110. Thus, upper slips 116 are moved radially outwardly with respect to center mandrel 102 or 202 such that edges 124 of inserts 122 grippingly well bore 12.
Also during the setting operation, upper slip 126 is forced downwardly, shearing shear pin 128. This in turn causes packer elements 40 a»d 42 to be squeezed outwardly into sealing engagement with the well bore.
The lifting on center mandrel 102 or 202 causes the lower slip support (valve housing 144 in first packer embodiment 100, valve housing 206 in second packer embodiment 200, valve housing 302 in fourth packer embodimE~nt 300, lower slip support 402 in fifth packer embodiment 400, and lower slip support 502 in first bridge plug embodiment 500 and second bridge plug embodiment 600) to be moved up and lower slips 136 to be moved upwardly with respect to lower slip wedge 130.
Tapers 134 in lower slips 136 slide along lower slip wedge 130, and shoulders 140 on lower slips 136 slide along the corresponding shoulder 142, 210, 306, 406, or 506. Thus, lower slips 136 are moved radially outwardly with respect to center mandrel 102 or 202 sa that inserts 138 grippingly engage well bare 12.
Also during the setting operation, lower slip wedge 130 is forced upwardly, shearing shear pin 132, to provide additional squeezing force on packer elements 40 and 42.
The engagement of inserts 122 in upper slips 116 and inserts 138 in lowe~x~ slips 136 with well bore 12 prevent packers 100, 200, 300, 400 and bridge plugs 500, 600 from coming unset.
Once any of packers 20, 100, 200, 300, 400 are set, the valves therein may be actuated in a manner known in the art.
Sliding valve 164 in second packer embodiment 126, and sliding valve 22 in third packer embodiment 200 are set in a similar, if not identical manner. sliding valve 318 in fourth packer embodiment 300 is also set in a similar manner, but does not utilize collets, nor is alignment of sliding valve 318 with respect to ports 316 in valve housing 302 important. Sliding valve 318 is simply moved below ports 316 to open the valve.
Bumper seal 314 cushions the downward movement of sliding valve 318, thereby minimizing the possibility of damage to sliding valve 318 or valve housing 302 during an opening operation.
In fifth packer embodiment 400, the valve assembly comprising valve body 432, valve seal 434, valve spacer 436, valve head 438 and valve holder 442 is ~~perated in a manner substantially identical to that of the Ilal.liburton EZ Drills squeeze packer of the prior art.
Drillinc,~ Out The Packer Apparatus Drilling out any embodiment of downhole tool 10 may be carried out by using a standard drill bit at the end of tubing string 16. Cable tool drilling may also be used. With a standard "tri-cone" drill bit, the drilling operation is similar to that of the prior art except that variations in rotary speed and bit weight are not critical because the non-metallic materials are considerably softer than prior art cast iron, thus making tool 10 much easier to drill out. This greatly simplifies the drilling operation and reduces the cost and time thereof. ~' "
In addition to standard tri-cone drill bits, and particularly if tool 10 is constructed utilizing engineering grade plastics for the mandrel as well as for slip wedges, slips, slip supports and housings, alternate types of drill bits may be used which would be impossible for tools constructed substantially of cast iron. For example, polycrystalline diamond compact (PDC) bits may be used. Drill bit 14 in FIG. 1 is illustrated as a FDC bit. Such drill bits have the advantage of having no moving parts which can jam up.
Also, if the well bore itself was drilled with a PDC bit, it is not necessary to replace it with another or different type bit in order to drill out tool 10.
While specific sdueeze packer and bridge plug configurations of packing apparatus 10 has been described herein, it will be understood by those skilled in the art that other tools may also be constructed utilizing components selected of non-metallic materials, such as engineering grade plastics.
Additionally, components of the various packer embodiments may be interchanged. For example, thick cross-sectional center mandrel 102 may be uved with valve housing 206 in second packer embodiment 200 or valve housing 302 in fourth packer embodiment 300. Similarly, thin cross-sectional center mandrel 202 could be used with valve body 144 in second packer embodiment 100 or lower slip support 402 and valve housing 416 in fifth packer embodiment 400. The intent of the invention is to provide devises of flexible design in which a variety of configurations may be used.
It will be seen, therefore, that the downhole tool packer apparatus and methods of drilling thereof of the present invention are well adapted to carry out the ends and advantages mentioned as well as thaw inherent therein. While presently preferred embodiments of the apparatus and various drilling methods have been discussed for the purposes of this disclosure, numerous changes in the arrangement and construction of parts and the steps of the methods may be made by those skilled in the art. In particular, the invention is not intended to be limited to squeeze packers or bridge plugs.
AlI such changes are encompassed within the scope and spirit of the appended claims.
Claims (40)
1. A downhole tool for use in a well bore, the tool comprising:
a mandrel comprised of plastic;
packing means disposed on the mandrel for sealingly engaging the well bore when in a set position;
upper slip means disposed on the mandrel above the packing means, the upper slip means for grippingly engaging the well bore when in a set position; and lower slip means disposed on the mandrel below the packing means, the lower slip means for grippingly engaging the well bore when in a set position.
a mandrel comprised of plastic;
packing means disposed on the mandrel for sealingly engaging the well bore when in a set position;
upper slip means disposed on the mandrel above the packing means, the upper slip means for grippingly engaging the well bore when in a set position; and lower slip means disposed on the mandrel below the packing means, the lower slip means for grippingly engaging the well bore when in a set position.
2. A downhole tool according to claim 1, wherein:
the packing means comprises at least one packer element on the mandrel;
the upper slip means comprises an upper slip wedge engaging a plurality of upper slips with an upper slip support on the opposite side of the upper slips from the upper slip wedge; and the lower slip means comprises a lower slip wedge engaging a plurality of lower slips with a lower slip support on the opposite side of the lower slips from the lower slip wedge.
the packing means comprises at least one packer element on the mandrel;
the upper slip means comprises an upper slip wedge engaging a plurality of upper slips with an upper slip support on the opposite side of the upper slips from the upper slip wedge; and the lower slip means comprises a lower slip wedge engaging a plurality of lower slips with a lower slip support on the opposite side of the lower slips from the lower slip wedge.
3. A downhole tool for use in a well bore, the tool comprising:
a mandrel comprised of plastic;
at least one packer element on the mandrel;
an upper slip wedge engaging a plurality of upper slips with an upper slip support on the opposite side of the upper slips from the upper slip wedge, wherein the upper slip wedge, the upper slips, and the upper slip support are disposed on the mandrel above the packer element;
and a lower slip wedge engaging a plurality of lower slips with a lower slip support on the opposite side of the lower slips from the lower slip wedge, wherein the lower slip wedge, the lower slips, and the lower slip support are disposed on the mandrel below the packer element.
a mandrel comprised of plastic;
at least one packer element on the mandrel;
an upper slip wedge engaging a plurality of upper slips with an upper slip support on the opposite side of the upper slips from the upper slip wedge, wherein the upper slip wedge, the upper slips, and the upper slip support are disposed on the mandrel above the packer element;
and a lower slip wedge engaging a plurality of lower slips with a lower slip support on the opposite side of the lower slips from the lower slip wedge, wherein the lower slip wedge, the lower slips, and the lower slip support are disposed on the mandrel below the packer element.
4. A downhole tool for use in a well bore, the tool comprising:
a mandrel comprised of plastic;
an elastomeric packer element on the mandrel for sealingly engaging the well bore when in a set position;
an upper slip support on the mandrel above the packer element;
an upper slip wedge on the mandrel above the packer element;
a plurality of upper slips, each slip c>f the plurality of upper slips having one e,nd supported by the upper slip support while the other end engages the upper slip wedge.;
a lower slip wedge on the mandrel below the packer element;
a lower slip support on the mandrel be:lc>w the packer element; and a plurality of lower slips, each slip of the plurality of lower slips having one end supported by the lower slip support while the other end engages the lower slip wedge.
a mandrel comprised of plastic;
an elastomeric packer element on the mandrel for sealingly engaging the well bore when in a set position;
an upper slip support on the mandrel above the packer element;
an upper slip wedge on the mandrel above the packer element;
a plurality of upper slips, each slip c>f the plurality of upper slips having one e,nd supported by the upper slip support while the other end engages the upper slip wedge.;
a lower slip wedge on the mandrel below the packer element;
a lower slip support on the mandrel be:lc>w the packer element; and a plurality of lower slips, each slip of the plurality of lower slips having one end supported by the lower slip support while the other end engages the lower slip wedge.
5. A downhole tool for use in a well bore, the tool comprising:
a mandrel comprised of plastic;
an upper slip support disposed on the mandrel;
a plurality of upper slips disposed aroulrd the mandrel below the upper slip support, the upper slips supported by the upper slip support;
an upper slip wedge disposed on the mandrel, the upper slip wedge engaging the plurality of upper slips on the opposite side of the upper slips from the: upper slip support;
at least one packer element disposed on the mandrel below the upper slip wedge;
a lower slip wedge disposed on the mandrel below the packer element;
a plurality of lower slips disposed around the mandrel below the lower slip wedge, the lower slip wedge engaging the plurality of lower slips;
and a lower slips support disposed on the mandrel and on the opposite side of the lower slips from the lower slip wedge, the lower slips supported by the lower slip support.
a mandrel comprised of plastic;
an upper slip support disposed on the mandrel;
a plurality of upper slips disposed aroulrd the mandrel below the upper slip support, the upper slips supported by the upper slip support;
an upper slip wedge disposed on the mandrel, the upper slip wedge engaging the plurality of upper slips on the opposite side of the upper slips from the: upper slip support;
at least one packer element disposed on the mandrel below the upper slip wedge;
a lower slip wedge disposed on the mandrel below the packer element;
a plurality of lower slips disposed around the mandrel below the lower slip wedge, the lower slip wedge engaging the plurality of lower slips;
and a lower slips support disposed on the mandrel and on the opposite side of the lower slips from the lower slip wedge, the lower slips supported by the lower slip support.
6. The downhole toll according to any one of claims 2-5, wherein the mandrel has a central bore therethrough.
7. The downhole tool according to claim 6, wherein the central bore has a diameter less than about half an outside diameter of the mandrel.
8. The downhole tool according to any one of claims 2-5, wherein the upper slip support comprises a lock ring housing.
9. The downhole tool according to any one of claims 2-5, wherein the lower slip support comprises a valve housing.
10. The downhole tool according to any one of claims 2-5, wherein the upper and lower slips are comprised of plastic.
11. The downhole tool according to claim 10, wherein the upper and lower slips further comprise a plurality of inserts molded into the plastic of the slips.
12. The downhole tool according to claim 11, wherein each of the inserts has an edge adapted for grippingly engaging the well bore.
13. The downhole tool according to any one of claims 2-5, wherein the slip wedges are comprised of plastic.
14. The downhole tool according to any one of claims 2-5, wherein the upper and lower slip wedges are generally conical.
15. The downhill tool according to any one of claims 2-5, further comprising:
means for retaining the plurality of upper slips and the plurality of lower slips in an initial position on the mandrel.
means for retaining the plurality of upper slips and the plurality of lower slips in an initial position on the mandrel.
16. The downhole tool according to any one of claims 2-5, further comprising:
an upper retaining band for retaining the plurality of upper slips in an initial position on the mandrel and a lower retaining band for retaining the plurality of lower slips in an initial position on the mandrel.
an upper retaining band for retaining the plurality of upper slips in an initial position on the mandrel and a lower retaining band for retaining the plurality of lower slips in an initial position on the mandrel.
17. The downhole tool according to any one of claims 2-5, wherein the tool is selected from the group consisting of packers and bridge plugs.
18. The downhole tool according to any one of claims 2-17, wherein the plastic is further comprised of reinforcements.
19. The downhole tool according to claim 18, wherein the reinforcements comprise glass reinforcement.
20. The downhole tool according to any one of claim 2-17, wherein the plastic is an engineering grade plastic.
21. The downhole tool according to any one of claims 2-17, wherein the plastic has a tensile strength of at least 18,000 psi and a compressive strength of at least 40,000 psi.
22. The downhole tool according to any one of claims 2-17, wherein the plastic is nylon.
23. The downhole tool according to any one of claims 2-17, wherein the plastic is a phenolic material.
24. The downhole tool according to any one of claims 2-17, wherein the plastic is a phenolic material with glass reinforcement.
25. The downhole tool according to any one of claims 2-17, wherein the plastic is an epoxy resin.
26. The downhole tool according to any one of claims 2-17, wherein the plastic is molded.
27. A well bore process using the downhole tool according to any one of claims 2-26, the process comprising the steps of:
setting the downhole tool in the well bore;
contacting the tool with well fluids; and drilling the tool out of the well bore.
setting the downhole tool in the well bore;
contacting the tool with well fluids; and drilling the tool out of the well bore.
28. A well bore process using the downhole tool according to any one of claims 2-26, the process comprising the steps of:
setting the downhole tool into locking, sealing engagement with the well bore; and after setting the downhole tool, contacting the tool with well fluids;
and after contacting the tool with well fluids, drilling the tool out of the well bore.
setting the downhole tool into locking, sealing engagement with the well bore; and after setting the downhole tool, contacting the tool with well fluids;
and after contacting the tool with well fluids, drilling the tool out of the well bore.
29. The process according to one of claims 2 7 and 28, wherein the step of setting the downhole tool positions the upper slips and lower slips in gripping engagement with the; well bore and the packer element in sealing engagement with the well bore.
30. The process according to one of claims 27 and 28, wherein the step of setting the downhole tool further comprises the steps of:
using a setting tool to pull upwardly on the mandrel, while holding the upper slip support, whereby the upper slip support is pushed relatively downwardly along the mandrel, the plurality of upper slips are pushed outwardly and downwardly against the upper slip wedge, and the upper slip wedge is pushed downwardly;
continuing to use the setting tool to pull upwardly on the mandrel, while holding the upper slip support, whereby the upper slip wedge pushes downwardly against the packer element;
continuing to use the setting tool to pull upwardly on the mandrel, while holding the upper slip support, whereby the packer element pushes downwardly against the lower slip wedge, the plurality of lower slips are pushed outwardly and downwardly against the lower slip support; and continuing to use the setting tool to pull upwardly on the mandrel, while holding the upper slip support, whereby the upper slips and the lower slips are placed in gripping engagement with the well bore and the packer element is placed in sealing engagement with the well bore.
using a setting tool to pull upwardly on the mandrel, while holding the upper slip support, whereby the upper slip support is pushed relatively downwardly along the mandrel, the plurality of upper slips are pushed outwardly and downwardly against the upper slip wedge, and the upper slip wedge is pushed downwardly;
continuing to use the setting tool to pull upwardly on the mandrel, while holding the upper slip support, whereby the upper slip wedge pushes downwardly against the packer element;
continuing to use the setting tool to pull upwardly on the mandrel, while holding the upper slip support, whereby the packer element pushes downwardly against the lower slip wedge, the plurality of lower slips are pushed outwardly and downwardly against the lower slip support; and continuing to use the setting tool to pull upwardly on the mandrel, while holding the upper slip support, whereby the upper slips and the lower slips are placed in gripping engagement with the well bore and the packer element is placed in sealing engagement with the well bore.
31. The process according to one of claims 27 and 28, wherein the downhole tool further comprises a tension sleeve disposed in the mandrel, the tension sleeve adapted for connection with a setting tool.
32. The process according to claim 31, wherein the step of setting the downhole tool further comprises:
shearing the tension sleeve so the setting tool may be removed from the well bore leaving the downhole tool in a set position in the well bore.
shearing the tension sleeve so the setting tool may be removed from the well bore leaving the downhole tool in a set position in the well bore.
33. The process according to one of claims 27 and 28, wherein the step of contacting the downhole tool with well fluids further comprises:
pumping cement or other slurry down tubing and forcing the slurry out into a formation.
pumping cement or other slurry down tubing and forcing the slurry out into a formation.
34. The process according to one of claims 27 and 28, wherein the step of contacting the downhole tool with well fluids is at a pressure of less than about 10,000 psi and a temperature of less than about 425°f.
35. The process according to one of claims 27 and 28, wherein the step of drilling the downhole tool out of the well bore comprises:
contacting the tool with a drill bit to grind up the components of the downhole tool to remove it from the well bore.
contacting the tool with a drill bit to grind up the components of the downhole tool to remove it from the well bore.
36. The process according to claim 35, wherein the step of drilling the downhole tool out of the well bore further comprises:
using a drill bit having no moving parts.
using a drill bit having no moving parts.
37. The process according to claim 35, wherein the step of drilling the downhole tool out of the well bore further comprises:
using a polycrystalline diamond drill bit.
using a polycrystalline diamond drill bit.
38. The process according to any one of claims 35-37, wherein the step of drilling the downhole tool out of the well bore is carried out without substantially varying the weight applied to the drill bit.
39. The process according to one of claims 27 and 28, further comprising the step of, prior to the step of setting the downhole tool, drilling at least a portion of the well bore.
40. The process according to claim 39, wherein the step of drilling at least a portion of the well bore further comprises:
using a polycrystalline diamond drill bit.
using a polycrystalline diamond drill bit.
Applications Claiming Priority (3)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US07/719,740 US5271468A (en) | 1990-04-26 | 1991-06-21 | Downhole tool apparatus with non-metallic components and methods of drilling thereof |
| US719,740 | 1991-06-21 | ||
| CA002071721A CA2071721C (en) | 1991-06-21 | 1992-06-19 | Downhole tool apparatus with non-metallic components and methods of drilling thereof |
Related Parent Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA002071721A Division CA2071721C (en) | 1991-06-21 | 1992-06-19 | Downhole tool apparatus with non-metallic components and methods of drilling thereof |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| CA2406259A1 CA2406259A1 (en) | 1992-12-22 |
| CA2406259C true CA2406259C (en) | 2006-01-24 |
Family
ID=25675246
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA002406259A Expired - Lifetime CA2406259C (en) | 1991-06-21 | 1992-06-19 | Downhole tool apparatus with non-metallic components and methods of drilling thereof |
Country Status (1)
| Country | Link |
|---|---|
| CA (1) | CA2406259C (en) |
-
1992
- 1992-06-19 CA CA002406259A patent/CA2406259C/en not_active Expired - Lifetime
Also Published As
| Publication number | Publication date |
|---|---|
| CA2406259A1 (en) | 1992-12-22 |
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Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| EEER | Examination request | ||
| MKEX | Expiry |