GB2338500A

GB2338500A - Method and apparatus for sealing and transferring force in a well bore

Info

Publication number: GB2338500A
Application number: GB9921717A
Authority: GB
Inventors: Buskirk Richard Glenn Van; Michael J Loughlin; Rustom K Mody; Ii Albert A Mullins; Michael H Johnson
Original assignee: Baker Hughes Inc
Current assignee: Baker Hughes Holdings LLC
Priority date: 1995-05-22
Filing date: 1996-05-16
Publication date: 1999-12-22
Anticipated expiration: 2016-05-16
Also published as: GB2338500B; GB9921717D0

Abstract

A wellbore (1) is at least partially obstructed with a partition or obstruction member (5). A fluid slurry of an aggregate mixture of particulate matter is pumped into the wellbore adjacent the partition or obstruction member. The aggregate mixture of particulate material contains at least one component of particulate material, and each of the at least one particulate material components has an average discrete particle dimension different from that of the other particulate material components. Fluid pressure then is applied to the aggregate material, and fluid is drained from the aggregate material through a fluid drainage passage in the partition or obstruction member. The fluid pressure and drainage of fluid from the aggregate mixture combined to compact the aggregate mixture into a substantially solid, load-bearing, force-transferring, substantially fluid-impermeable plug member (11), which seals a first wellbore region from fluid flow communication with a second wellbore region. The plug member is easily removed from the wellbore by directing a high-pressure fluid stream toward the plug member, thereby dissolving or disintegrating the particulate material of the plug member into a fluid slurry, which may be circulated out of or suctioned from the wellbore. The invention is directed to the means whereby the particulate material is positioned.

Description

2338500 METHOD OF SEALING AND TRANSFERRING FORCE IN A WELLBORE

1. Field of the Invention:

The present invention relates generally to methods for forming downhole pressure plugs in a wellbore. More particularly, the present invention relates to methods of forming downhole plugs to seal the wellbore and to transfer stress from a wellbore tool to the wellbore itself. Additionally, the invention is directed to the use of particulate matter plugs to either transfer loads or to seal during completion operations.

2. Description of the Prior Art:

It is conventional in the oil and gas industry to seal wellbores using packers, bridge plugs, and the like. Typically, a wellbore tool, such as a packer or bridge plug, is run into the wellbore to a desired location therein. The packer or bridge plug is inflated or otherwise actuated into sealing engagement with the wellbore. Such a seal may be effected to separate regions in the wellbore, to contain fluid pressure either above or below the wellbore tool for fracturing or other well treatment operations, or other conventonal reasons.

Conventional wellbore tools have a force threshold beyond which the wellbore tool wiN fail mechanically, or vAll lose gripping and sealing engagement with the wellbore, which tends to cause undesirable movement of the wellbore tool within the wellbore. The force threshold typically is defined in terms of a maximum or limiting differential pressure across the wellbore tool that the wellbore tool can withstand without failure or movement in the wellbore.

If the force threshold is exceeded, mechanical failure of the wellbore tool or undesirable movement of the wellbore tool may result. Mechanical failure may result in at least partial inoperability of the wellbore tool. If the wellbore tool is rendered inoperable, the wellbore may be undesirably obstructed, requiring expensive 1 fishing remedial operations. Mechanical failure at least will require expensive and time-consuming repair or replacement of the wellbore tool.

W 1 Even if the wellbore tool does not fail and is not otherwise damaged, the wellbore tool may be moved or displaced within the wellbore if the force threshold is exceeded. Such movement or displacement is undesirable because the positioning of the wellbore tool within the wellbore frequently is of great importance. Also, movement or displacement of the wellbore tool could damage other wellbore tools or the producing formation itself, thereby necessitating fishing, Workover, or other remedial wellbore operations. ' In secondary recovery operations, such as formation fracturing, reliable and dependable packers and bridge plugs frequently are necessary. Many secondary recovery operations require sealing off or packing a selected formation interval, and introducing extremely high pressure fluids into the selected interval. High-pressure fluids exert extreme axial forces on the packers or bridge plugs used to seal off the interval. Thus, the possibility of exceeding the force threshold of such wellbore tools is very great in formation fracturing, and requires the use of expensive, reinforced, high-pressure rated wellbore tools. High-pressure wellbore tools typically have relatively large cross-sectional diameters, precluding their use in through-tubing operations or operations in otherwise reduced-diameter or obstructed wellbores.

An alternative to high-pressure rated wellbore tools is to plug or seal the wellborewith cement. Cement plugs have a number of drawbacks. Expensive and specialized cementing equipment usually is required to pump cement into the wellbore to formi a cement plug. AJso, a significant time period must elapse to permit a cement plug to harden or set into a sealing or load- bearing cement plug. Another drawback of cement plugs is that they are relatively permanent, and require expensive and timeconsuming milling operations to remove them from the wellbore.

During wellbore completion operations. a variety of wellbore tools are utilized to either transfer loads Wthin the wellbore or to seal flow paths %ithin the wellbore. For example, cement is utilized to secure sections of casing string in a fLxed 2 position relative to the borehole. Alternatively, or in supplementation to casing cement, external casing packers are utilized to fix a section of casing in position relative to the borehole. Liner hangers are utilized to seal and couple.sections of casing string to one another. Typically, a casing section of radially-reduced dimension is suspended within a larger diameter casing string which is directly above. Generally, liner hangers include a gripping mechanism which allows the weight of the lower string to be transferred laterally to the upper string. Additionally, the liner hangers typically include metal-to-metal or elastomeric sealing elements or a combination of metal-to-metal and elastomeric sealing elements which seal the potential fluid flow path at the junction of the sections of casing strings.

A completion operation typically requires the placement of a tubing string in a concentric position relative to the casing string. Commonly, the tubing string is centralized and fixed in position relative to the casing string by one or more packer elements. Typically, the packers serve the dual purposes of transferring loads laterally and providing a seal in the annular region between the tubing stdng and the casing string. Also during complefion operations, one or more sections of the casing string may be temporarily or permanently plugged to limit or prevent the flow of fluids between particular regions of the central bore of the tubing string.

In short, a large number of wellbore tools are utilized during completion operations to either transfer load wWjn the wellbore or to provide a seal at a potential fluid flow path. These wellbore tools are generally rather expensive components.

Additionally, they are difficult to replace and repair and frequenUy require the removal or all or a portion of the wellbore tubulars from the wellbore in order to allow workmen to replace a component. When, for example, a tubing string is pulled from a wellbore, the well is typically "killed"; that is, chemical additives are introduced into the well to prevent or limit the flow of hydrocarbons from the wellbore. Oil and gas well operators are generally reluctant to "kill" a well, since there is no guarantee that the well will later resume production at the levels of production phor to the "killing" and work over operations.

3 SUMMARY OF THE INVENTION

It is one objective of the present invention to provide a, nethod of sealing a wellbore, wherein a first wellbore region is isolated from fluid communication 5 with a second wellbore region.

It is another objective of the present invention to provide a method of forming a sealing plug member within a wellbore, wherein the plug member transfers force resulting from pressurized fluid in the wellbore to the wellbore itself, obviating the need for high.pressure rated wellbore sealing tools.

It is yet another objective of the present invention to provide a method of sealing a wellbore with a plug member that is both strong and substantially fluid-impermeable, yet is easily and quickly removable from the wellbore using conventional wellbore tools.

These and other objectives of the present invention are accomplished by at least partially obstructing a wellbore with a partition or obstruction member. A fluid slurry of an aggregate mbdure of particulate matter is pumped into the wellbare adjacent the partffion or obstruction member. The aggregate mixture of particulate material contains at least one component of partculate material, and each of the at least one particulate material components has an average discrete particle dimension different from that of the other particulate material components. Fluid pressure then is applied to the aggregate material and fluid is drained from the aggregate material through a fluid drainage passage in the partifion or obstruction member. The fluid pressure and drainage of fluid from the aggregate mixture combined to compact the aggregate mixture into a substantially solid, load-bearing, force-transferring, substantially fluid-impermeable plug member, which seals first wellbore region from fluid flow communication with a second wellbore region. The plug member is easily removed from the wellbore by directing a high-pressure fluid stream toward the plug member, thereby dissolving or disintegrating the particulate material of the plug member into a fluid slurry, which may be circulated out of or suctioned from the wellbore.

4 Preferably, the aggregate mixture of particulate matter contains a binder component comprising a finely dispersed particulate material wflich is. capable of hydrating and swelling to fill pores or interstitial spaces between other particulate 5 material components of the aggregate mixture of the plug member.

It is another objective of the present invention to utilize the particulate matter pressure plug in otherwise conventional completion operations in order to either transfer loads within the well or seal fluid flow paths within the well. In some applications, the particulate matter pressure plug may serve both functions simultaneously.

Other objects features and advantages of the present invention will become apparent to those skilled in the art with reference to the drawings and detailed descxiption, which follow.

BRIEF DESCRIPTION OF THE DRAWINGS

The novel feiturcs believed characzeristic or the invention ire set forth in the appended claims. The invention Itself, however. as well as a preferred mode ofuse, further objectives and advantages thereof, will best be understood by reference to the following detailed description of an illustrvive embodiment when read in conjunction with the accompanying drawings. It should be noted that Figures 1 to 9 are included to provide a full explanation and to place the invention in context, but do not fall within the scope of the claims. In the drawings:

Figure 1 illusrrates. in partial longitudinal section,. a wellbore apparatus including a plug mrber; W Figure 2 schematicaily illustrates relative sizes of the particulate matter that makes up the aggregate mixture, which forms a plug member.; Figure 3 schernatically depicts a wellbcre containing coarse sand particles., Figure 4 illustrates a wellbore containing an aggregate rrixtur-,,' Figure 5 is a table illustrafing the results of permeability tests performed on various mixtures and aggregate mix!ures for use in forming a plug member,, Figure 6 depicts a superimposition of a pair cf graphs of data obtained dL,dr,g testing of a pressure plug or plug rrernber; - Figure 7 Is a graph wmpa,p.g " pressure rating cf wnventional high30 pressure raed inflatable packers wiLi tne pressure rating of a piug nr; i 1 6 1 Figure 8 is a partial longitudinal section view of the sealing and loadbearing apparatus of Figure 1, the apparatus being shown in a plug member removal or washing-out mode of operation; Figures 9a through 9e should be read together and depict a onequarter longitudinal section view of a partition or obstruction member; Figures 10A through 1ON depict utilization of the particulate matter pressure plug of the present invention in otherwise conventiomi completion operations to either supplement or substitute for completion tools or completion methods; and Figures 11A through 11L depict alternative techniques for effecting conveyance, containment, and compaction of the particulate matter in order to form a particulate matter pressure plug in accordance with the present invention.

7 DETAILED DESCRIPTION OF THE INVENTION

Referring now to the figures, and specifically to Figure 1, wellbore apparatus will be described. Figure 1 illustrates, in partial longitudinal section, a wellbore 1. Wellbare 1 is sh as a cased wellbore, but the ap p-arar-us is con::em.ola-ed for use in open wellbores, production tubing, or the like, having conduit or a fluid passageway therethrough in which a pressure-tight seal may be advantageous. Wellbore 1 is provided with a source of a)dai"force, in this case a workstring 3. in the case of workstring 3, the source of a)dal force is fluid pressure, but may be any other source of axial force. A removable partition or obstruction member 5 is disposed in wellbore 1. In this case, partition or obstruction member is an inflatable packer 5. However, the obstruction or partition member may be any sort of wellbore tool that is capable of selectively, and at least partially obstructing fluid flow from a first region of wellbore 1 with. a second region. Inflatable packer 5 is provided at an upper extent with a screen filter asserribly 7, and at a lower end with fluid outlet 9. The utifty and function of screen Filter 7 and fluid outlet 9 will be described hereinafter.

A pressure plug or plug member 11 is disposed adjacent to and above inflatable packer 5. Plug member 11 comprises a compacted aggregate mbdure of particulate matter. Plug member 11 provides a substantially fluid-impermeable seal in "[]bore 1, and thereby isolates a first region of wellbore 1 from fluid flow wmmL:nicaticn with a secend region. Furtlher, plug member 11 serves to transfer axial fcrze "rl the source of axial force (in this case, fluid pressi.;re from workstring 3) laterally to wellbore 1. thereby permitting use of a lewer-p,essure rated inflatable packer 5 or other obstruction of partition member.

The specific wellbore c,cer31,:'cn illustrated in Figure 1 is a sec-, rdary rewve,,y c.ceration. such as fcr7-.ailor,. f-ac-lur.ng. Thus, 1 is provided with two se!s of.-.,erforations 13, 15, Each se, of perforatiens 13, 15 and tne area defines a 1 be v ec region in wellbore 1. In secendary re,::cvery operations. 't rnay ad antag us to isolate one set of perforations. in was case upper set 13, ft-,yn another set cif perforations. in this case lower set 15, so that second" recovery operations COn be directed to only one forrnation through a single set of perforations 13 The secondary ICCOVTl illustrated in Figure 1 is k-,7,vn conventionally as 1 th rac,,uring e formation, In such a fracturing operation, we)ibore 1 Is packed-off, prefembly with a plug member 7 according to the present invention. Workstring 3 then is run into wellbore 1, and fracturing fluid 17, which is conventional, is pumped into wellbore 1, out through perforations 13, and into the formation. Frequently, tremendous pressures are required to force fracturing fluid 17 into the formation. These fluid pressures may be exerted an wellbore 1, plug member 11, and inflatable packer 5.

Such a fracturing operation, if employing only an inflatable packer 5 or other wellbore tool, would require inflatable packer 5 to withstand extreme difterential pressure, and the resulting axial force, without mechanical failure or movement within wellbore 1.

Accordingly, such high-pressure rated inflatable packers 5, as well as other highpressure rated we!lbore tools, are very expensive. Additionally, such wellbore tools generally are larger in diameter, which may preclude their use in through-tubing workover operations.

Plug mTber 11 is advantageous in that it provides a substantially fluidimperrneai,l;e seal in wellbore 1, and transfers axial force (caused in this case by fluid pressure C om wor,string 3) laterally to the wellbore and away from inflatable packer 5.

Therefore, low-pressure rated inflatable packers 5, or other low-pressure rated wellbore tools, can be used in conjunction th plug member 11 and still maintain a substantially fluid-impermeable and strong seal in wellbore 1.

Figure 2 schematicaily illustrates the relative sizes & the classes of particulate rn.arer that makes up the aggregate rnxture that forrns plug ", mber 11.

Preferably, the paTtculate matter is silica sand, cr silicon d'lcx';c!e. Sand, particles 21 s-,hernaticalIy represent grains of w-,ver,.,-;cna:.

3 2, warse 20;- r7.es-,. sand Tne term 'rn.es'," is ^--nve.ntlC-ral in Une anC represents an average discrete pa,1C;e size (c,, par4,iculale Cnale,ia!s, particularly sand. Recommended Practice Number 58, entitled "Recomrnend Practices for 9 Testing Sand Used in Gravel Packing Operations," published bY the American Petroleum Institute, Dallas, Texas, is exemplary of the measurement cf average discrete particle size of sands. Intermediate sand grains 23 schematically Illustrate the size of 100 mesh silica sand, as contrasted to the size of coarse 20140 mesh silica sand. Fine sand particles 25 schematically illustrate the relative size of 200 mesh sand particles, as contrasted to intermediate 100 mesh sand pardcles 23 and coarse 20140 mesh sand particles 21. An aggregate mixture of silica sand particles of various dimensional classes or mesh sizes is employed to form plug member 11. The use of sand particles 21, 23, 25 of varying average discrete particle dimensijon is important to forming the substantially fluidimpermeable, force transferring plug member 11, 1 Figure 3 schematically depicts a wellbore 101 containing coarse sand particles 121. Coarse sand particles 121 are schematically depicted as particles of 20140 mesh silica sand, as illustrated in Figure 2. As is illustrated, there are numerous pores and interstitial spaces between individual sand partdes 121. These pores or interstitial spaces permit the sand to be fluid- permeable, and also provide room for individual sand particles 121 to displace relative to each other in response to forces applied to the sand.

1 Figure 4 illustrates a wellbore 201 containing a plug member 211.

Plug member 211 comprises an aggregate mixture of coarse, 20140 mesh sand particles 221, intermediate, 100 mesh sand particles 223, and fine, 200 mesh sand particles 225. As is illustrated, the aggregate mixture of coarse, intermediate, and fine sand particles cooperate to reduce the volume of pores and interstitial spaces between the various sand particles 221, 223, 225. Such an aggregate mixture results in a more substan5211y fiLlid-impermeable plug member 211, and provides less space for individual sand grains to displace and m ove in response to forces exerted cr, plug rnernber 211.

Figure 5 is a table illuslralirg the results of permeability tests per4, crmed on various mixtures and aggregate mixtures for use In forming plug member 11, 211.

In the left hand column is a number assigned to each test performed. The central column indicates the volumetric or weight percentage of each component making up the aggregate mixture, Wtlerein. ccmponent A is 20140 mesh silica sand (illustrated as 21 in Figure 2, 121 in Figure 3, and 221 in Figure 4), component B is 100 mesh silica sand (illustrated as 223 in Figure 4), component C is 200 mesh silica sand (illustrated as 225 in F1gure 4), and component D is a bentonite or clay "gel." the right hand column indicates the measured or estimated fluid permeability of the mixture or aggregate mixture tested, in millidarcies.

The Darcy is a unit of fluid permeability of materials, which is determined according to Darcys law, wNch follows:

K=OuL PA wherein, P pressure across sand (in bars); g dynamic viscosity of fluid (in centipoise); A cross-sectional area of sand (in square centimeters); L length of sand column (in centimeters); Q volume flow rate of effluent from sand column (in millikers per second); and K = permeability (in centimeters per second).

Accordingly, each aggregate sand mixture tested was formed into a column of known length IL, and kna,m cross-sectional area A A fluid having a knovm dynamic viscosity Ii, in this case water, was placed at one end of the sand column at a known pressure P. At an opposite end of the column, the flow rate of fluid effluent through the column 0 was measured. 7he foregoing known and measured data was inserted into the above-identified mathematical statement of Darcys law, and a permeability K was obtained in millidarcies. For test number one, a sand column of 100% 20140 mesh sand was tested, and yielded an estimated permeability of 2,8W millidarcies. As a second test, an aggre.-al.e mixture containing W% by VC1Lme 20140 mesh sand, 20% by weight 100 mesm sa..,.,t, and 20% by weight 200 mesh sand was tested, and yielded a permeability of 66 millidarcies. As a third test, an aggregate mixture of 80% by weight 20140 mesh sand, 1011% by weight, 100 mesh sand, and 1 00/h 11 by weight 200 mesh sand was tested and yielded a permeability of 415 millidarcies.

As a fourth test, an aggregate mixture of 60% by weight 2014.0 Mesh serd, 30% by weigt-,t 1 X mesh sand, and 10% by weight 200 mesh sand was tested and yielded a permeability of 233 millidarcies. As a fifth test, an aggregate mixture of 60% by weight 20140 mesh sand, 10% by weight 100 mesh sand, and 30% by weight 200 mesh sand was tested and yielded a permeability of 51 millidarcies. As a sixth test, an aggregate mixture of 40% by weight 20140 mesh sand, 30% by weight 100 mesh sand, and 30% by weight 200 mesh sand was tested and yielded a permeability of 50 millidarcies.

Test numbers 7, 8 and 9 reflect aggregate mixtures that are preferred for use in forming plug member 11, 211... The aggregate mixtures tested in tests 7, 8 and 9 contain a fourth or binder component, five to ten percent by weight of bentonite. Bentonite is a rock deposit that wntains quantities of a desirable clay mineral called montmorillonite. Montmorflionite is a colloidal material that disperses in fluid or water into individual, flat, plate-like day crystals with dimensions ranging between about five and five hundred millimicrons.

The flat plate-like clay wystals presumably ovedap each other very tightly to produce a generally substantially fluid-impermeable structure. Additicnally, montmorillonite crystals "hydrate" in water, wherein water molecules bond to the crystals, causing the crystals to swell to enlarged dimensions, which may further obstruct pares or interstitial spaces between coarser particles. Bentonite or bentonitic clays are interchangeable terms for any clay-like material possessing the properties discussed herein.

The addition of a binder of bentonite or bentonitic day material to the aggregate mixtures described herein results in an aggregate mixture having an extremely low fluid permeability. It is believed that the micros=pic nature cf the clay particles, combined with their ability to hydrate and swell, permits the clay particles to fill and almost completely obstruct any pores or interstitial spaces remaining in an aggregate sand mixture (as illustrated in Figure 4). This Lhecr, is 1-, rne Cul by the test results in tests 7, 8, and 9. Fortes', 7, an aggregate of 6001. by weight 20140 mesh sand, 20% by weight 100 mesh sand, 15% by weight 200 mesh sand, and 5% by weight of bentonite material was tested and yielded a permeability of 0.064 12 millidarcies, For test number e, an aggregate mixture of 60% by weight 20140 mesh sand, 15% by weight 100 mesh sand, 10% by weight 200 mesh sand. and 15% by weight of bentonite material was tested, and yielded permeability of 0. 063 rnfflidarcies.

For a ninth and final test, an aggregate mixture of 60% by weight 20140 mesh sand, 20% by weight 100 mesh sand, 15% by weight 200 mesh sand, and 5% by weight bentonite material was tested and yielded a permeability of 0.081 millidarcies.

1 From the foregoing test results, trends indicating preferred compositions of aggregate mixtures for use in forming plug member 11, 211 can be noted. 'Marked decreases in fluid permeability are obtained by adding significant quantities of fine sand particles, such as 200 mesh sand, to a mbdure containing coarse sand and intermediate sand components. A further reduction in permeability is obtained by adding ultra-fine, hydrating particles, such as bentonite or bentonitic clay materials.

Figure 6 depicts a superimposidon of a pair of graphs of data obtained during testing of a pressure plug or plug member 311.

As illustrated in the central portion of Figure 6, the test Mg wrnprises an artificial wellbore, in this case a length of casing 301, with a pardtion member, in this case an inflatable packer 305, disposed within wellbore 301. Inflatable packer 305 is further provided with a screen filter 307 at an uppermost end thereof, which is in fluid communication vith a fluid exhaust member 309 at a lowermost extent of inflatable packer 305.

Adjacent and atop inflatable packer 305 is column of drainage sand 331 approximately 3 feet in height. Drainage sand 307 is a coarse, preferably 20140 mesh, silica sand. Because the relatively coarse drainage sand 331 has a significant quantity of pcres and interstitial spacces beNveen individual sand particles, 307 vAll f.,r.ct'ion as a pre-filter for fluid entehing s-4een filter 307 cf irrliatabie pacj<er 305.

Such a pre-filter is advantageous to prevent extremely fine particles from entering inflatable packer 305 and tending to cause abrasion and resulting failure of inflatable packer 305.

13 9 It is believed to be irnPortant to provide either a column of drainage sand. or to maximize the content (consistent with the desired level of fluid impermeability) of relatively coarse (20140 mesh silica sand) particies in the aggregate mixture so that drainage of plug members 11, 211, 311 is enhanced and to facilitate removal of plug member 11, 211, 311, by washout Without coarse parficles, plug member 11, 211, 311 may compact into a rock-like member that cannot be removed easily.

A pressure plug or plug member 311 is formed atop drainage sand 3jl. According to the preferred embodiment of the present invention, plug member 311 is a column. of aggregate mixture as described herein that is twelve inches in height The preferred aggregate mixture is that described with reference to test number 7 (60% by weight 20140 mesh silica sand, 20% by weight 100 mesh silica sand, 15% by weight 200 mesh silica sand, and 5% by weight bentonite), having a measured fluid permeability of 0.064 millidarcies.

1 1 A quantity of pressurized fluid, in this case water 317, is disposed in wellbare above plug member 311. Pressurized fluid 317 serves as the source of axial force in the illustrated preferred embodiment. Pressurized fluid 317 exerts hydrostatc pressure both in a radial and an axial direcdon within wellbore 301. Because wellbore 301 typically is extremely strong, and resistant to deformation, the axial force compcnen which otherwise would act directly on inflatable packer 305, is the quantity of interest for purposes of the present invention.

Weilbcre 301 is provided with a number of strain gauges 333, 335. 337, 339, 341, wbich measure normalized hoop stress in wellbcre 301, thereby giving an indication of force transferred through plug member 311 to wellbore 301.

Durinc,:'-c test in F;tzure 6,:iL,:j 7 k2s -p 1 n rz' ", 5 U r" 1 n' 70', x 10' k -. rn.' t 1.000 pounJs per square i (ps: is i ne frorn 0 to 6. ', x 10' kg m- (0 psi to 9.000 psi). 7ne resulting str2tn gauge outputs. 1 and implicit force measurements. are plotted over the range of pressure increases in the left hand portion of Figure 6. The abscissa axis of the left hand graph plots the 14 magnitude of nuid pressure in pressurized fluid 317 in wellbore 301. The ordinate ax:s if the left hand graph plots hoop stress values measured by stain gauges 333 335. 337, 339, 341. As is illustrated, strain gauge 333, which is located on an exterior of wellbore 301 at a point in which wellbore 301 is filled with pressurized fluid, shows the largest variation in measured hoop stress 343 as fluid pressure is increased.

Strain gauge 335. which is located on the exterior of wellbore 301 where wellbore 301 is obstructed by plug member 311, indicates the second highest change in measured hoop stress 345. Stain gauge 337, which is located on the exterior of wellbore 301 at a point where wellbore 301 is filled with drainage sand 331, but above sand filter 307, measures a hoop stress 347 maximum of approximately 1,000 psi. Strain gauge 339, which is located on the exterior of wellbore 301 at a locaflon where wellbore 301 is filled with drainage sand 331 and sand filter 307, measures a hoopsturess 349 rr.ax.mur-,iosorne.vhat less than 703 x 10'kg,'m2 (1,000 psi). 5-,, ainaauú,e3,1,wh:chis located on the exterior of wellbore ' W 1 wInere;n wellbore 301 is filled with drainaae sand 33 1, 0 and is jt.,st'oelow screen filter 307 measurles a hoop stress 3 51 maximurn of less than 351 x 103 kem2 (500 psi).

The right hand graph of Figure 6 depicts th pressure distribLdion over tA-le length of wellbore 301, from areas filled by pressurized fluid 317 to the top of inflatable packer 305. The abscissa axis of the right hand graph plots measured hoop stress values, and is substantially similar to the ordinate axis of the left hand graph.

The ordinate axis of the right hand graph corresponds with the height of wellbore 301 and correlates transfer of force from pressurized fluid 317 through plug member 311 and drainage sand 331, to wellbore 301. As is illustrated, upper right portion 451 of the plotted line is substantially vertical and reflects a relatively uniform pressure distribution in wellbore 301, which is to be expected because, at that point, wellbore 301 is filled with pressurized fluid 317, "i-,ich exerts a generally unifonn hydrostatic pressure cin wellbore 301. A central pertion 4.53 of the ploCed line indicates a s.,gnficant measured pressure drop in wellt-ore 301 wtere wellbcre 301 is oczzipied by p1Lg me.mber 311. A lc-v.er le porlicn 455 of the pictted line indicates a fairly sleadl. maintained)cw pressure, wbich averages less th2n 703x 10' kg,'ni. (1.000 psi) in iellber.- 30i 71he signilicant pressure drop in kellbore 301 w.hcre it is occupied by plug mernber 3 11 inIcates thit the 1 axial force exerted by pressurized fluid 317 substantially is transferred by sand plug 311 to,..,,eflbore 301. Thus. a relati.,.,eiy insignificant axial force load cf generally less than psi) is experienced by drainage sand and inflatable packer '(15 Because such a large ningnitude of axial force resulting from pressurised fluid 317 in wellbore 301 is transferred to the generally stronger wellbore 301, much weaker and less expensive inflatable packers 305. or other wellbare fools may be employed %ith plug member 311 to seal a first wellbcre region against fluid flow to or from a second wellbore region.

Figure 7 is a graph COMParing the pressure rating of conventional high pressure rated inflatable packers (such as 305 in Figure 6) with the pressure rating crf plug member 11, 211. 311.. The abscissa axis of the graph plots the values of limiting dWerential pressure of failure threshold that each type of sealing member can withstand and maintain effective sealing integrity. The ordinate axis plots the casing inner diameter of the wellbore to be sealed. Plotted line 457 represents the pressure rating of a high- pressure rated, 3.6cm (3 :318') outer diameter inflatable packing element. The ability of the packing element to wfthstand pressure differentials (limiting di-iferential pressure in Figure 7) is a function of the diarneter of the casing or wellbore that the inflatable packer must seal. For small diameter casing, such as 11.4cm (4Y-.") casing, the limiting differential pressure or -.,llure 0 threshold is relatively high at approximately 6.3 x 10' kgIm2 (9,000 psi). However, as the casinc or wellbore diameter increases, the inflatable packer must e,,Tand further to sealingly engage the casing inner diameter, thus reducing the pressure differential (limiting differential pressure) that it is capable of withstanding. Therefore, for a large diameter c2sina, such 2s 27.3cm (1 O,..") diameter casing. the inflatable packer can only,k.it; 2nd z:ress:7" diffe.-eni.-.al (limiting differential pressure) of approximately I.,' x 10' k,- ni - (2.000 psi). 17, centrast, the pressure rating of a plug member 11. 211. 311. is much higher, and is less sensitive to casing diameter than are c.nr,ver,tior,ai inflatable packing elerrents Area 459 of Figure 7 re.presents the 30 pressure rating of plug mern.bers 11. 211, 311 fc(-ned acwrdirg,.-% the present inventicn, as predicted by tests conducled substantially as described wiGh reference to Figure 6. As is illustrated, in relatively small diarneter casing, plug mernbers 11. 211. 311 can withstand pressure differentials (lifn.iting differential pressure) of upwards Of is v 9.8 x 10 kg/ni' (1.1.000 psi). In diametcrcising. plug members 11. 211. 311 formed according to tile Presellt invent 1 an can withstand pressure differentials (linwing differentizil pressure) ot'ulikk.arki.s it'3 5 x IT k.,-. w: (5.000 psi). From the dati apparent thit plu.-, 1 1, 2 11. 311 possess sIL:tliFica;i: ad.2rlj--"-'; conk....tiiional witlatible packer clenlents and other -ellbore tools.

is Figure 8 is a partial longitudinal section view of the sealing and load- bearing apparatus of Figure 1, the apparatus being shown in a plug member 11 removal or washing-cut mode of operation. As in Figure 1, wellbore 1 has removable partition or obstruction member 5, including screen filter member 7 and fluid exhaust member 9, and plug member 11 disposed therein. Original fracturing vicirkstring 3 is replaced by a circulating or washmA woKstring 503. Circulating cr washout wcrkstr,g 503 is provided Wth a nozzle at a terminal end thereof f,-,r directing a high pressure fluid stream 19 toward plug member 11. High pressure fuid stream 19 is provided to dissolve or wash out plug member 11. As is iJius,rat-ad, the impact of high pressure fluid stream 19 upon plug member 11 causes the parliculate mafter of plug rrember 11 to separate into discrete particles. Relatively slow-m ov,:-.g wellbcre fluid suspends the particles of paf"Liculate maCer so that the particulate mCer and weflbore 1RAd 505 rnay be circulated out of or suctioned icm weiibcre 1. After plug nrember 11 is fully disintegrated, inflatable packer member 5 may be ccnventionally deflated and retrieved. Therefore, plug member 11 while stronger and capable of bearing more load with excellent sealing irlkn- rity, is simply and easily removed from wellbere 1 wber, its presence is no Icr.ger des'.. rabie.

Figures ga thrcugIi ge, wtich so',,ould be read tcget),,e:,, depict in oner,tjae,er 1crgitudinal section, a paij:t;,cr, or cbsljLction r-,e.mber, ir, this case an intlatable trildge plug 605. A sc;aen 607 is pr--,vide.1 at an uppermost e,-,d 01 b(;dge -Lg 605, Sween 607 is.:iug;ed at its L:P1cer and plug mernter 611 A c rr.ect'cfl, tute 613 =.2.-S a ent c p cr, \,th neck 615 nezk 615 is sweer. fniter 607 In fluid prcvided wth a nuid flow wr.dult 615a therethrough fcr nLid Wrr,(-.L,-lica,on with 17 upper element adapter 617. Upper element adapter 617 is connected by threads to fishing neck 615, and is provided with a fluid conduit 617a therethrough and is connected by threads to poppet housing 619.

A mandrel 621 is connected by threads to upper element adapter 617. Mandrel 621 is provided with a fluid conduit 621a therethrough, and also includes a fluid port 621 b. A poppet 623 is disposed between an exterior of mandrel 621 and an interior of poppet housing 619. Poppet 623 is further provided with a pair of seal members 623a. Poppet is biased upwardly by a biasing member or spring 625.

An element adapter 627 is connected by threads to poppet housing 619. Element adapter 627 is connected by threads to an upper element ring 629.

Upper element ring 629 cooperates "ith upper wedge ring 631 to secure a conventional inflatable packer element 633 to element ring 629. Inflatable packer element 633 is conventionally constructed of elastomeric matehals and a plurality of circumferentially overlapping flexible metal strips.

A lower element ring 635 is secured to inflatable packing element 633 by lower wedge ring 637. Lower element ring 629 is connected by threads to a lower element adapter 639. Lower element adapter 639 is provided with a threaded bleed port 641, which is selectively opened and closed to bleed air from between mandrel 621 and inflatable packing element 633 during assembly of bridge plug 605. Lower adapter 639 is connected by threads to a lower housing 643. Lower housing 463 is secured to mandrel 621 by means of a shear member 645, which permits relafive motion between lower housing 643 and mandrel 621 upon applicaflon of a force sufficient to fail shear member 645.

A guide shoe 647 is connected by threads to mandrel 621, and is provided with a fluid conduit 647a in fluid communication vAth fluid conduit 621a of mandrel 621. Guide shoe 647 is further provided with a closure member, in this case a ball seat 647b, which is adapted to receive a ball 649 to selectively obstruct fluid flow through inflatable bridge plug 605. Preferably, ball seat 647b is a pump-through 18 ball seat, which will release bail 549 and permit fluid flow out of bridge plug 605 upon application of fluid pressure of selected magnitude.

In operation, bridge plug 605 according to the present invention is assembled into a workstring (not shown) at the surface of the wellbore (not shown) and is run into the wellbore to a desired location. At the desired location in the wellbore, bridge plug 605 may be set actuated or inflated into sealing engagement with the wellbore by the following procedure.

Pressurized fluid is pumped through workstring and enters bridge plug 605 through screen fitter 607. Pressurized fluid flows from screen filter, fluid conduit 613a in connection tube 613, through iluid conduit 615a in fishing neck 615, through fluid conduit 617a of upper adapter 617, and into fluid conduit 621 a of mandrel 621. Closure member 647b, 649, obstructs the fluid conduit in 621 a in mandrel 621 so that fluid pressure may be increased inside mandrel 621. As fluid pressure increases, fluid flows through port 621b into a chamber defined between mandrel 621, upper adapter 617a, poppet housing 619, and poppet 623. Responsive to fluid pressure, poppet 623 moves relative to mandrel 621 and poppet housing 619 wten the fluid pressure differential acting on poppet 623 exceeds the biasing force of biasing member 625. As poppet 623 moves relative to poppet housing 619, poppet 623 moves past a shoulder 619a formed in the interior wall of poppet housing 619, wherein pressurized fluid is permitted to flow around poppet 623 and poppet seal member 623a. Fluid continues to flow between the exterior of mandrel 621 and inflatable packing element 633 to inflate inflatable packing member 629.

Inflation of inflatable packing element 633 will cause shear member W in lower housing 643 to fail, thereby permitting relative movement between mandrel 621 and lower packing element assembly (which includes lower element ring 635, wedge ring 637, lower element adapter 639, and lower housing 643). Inflation of Inflatable packer element 633 and relative movement between the lower elernent assembly and mandrel 621 permits inflatable packing element 633 to extend generally 19 radially outwardly from mandrel 621 and into seating erigagernent with a sidewall of the,.V,?!fcore Af'.er:;ea!ing is cbtained. fluid 21 may be reduced, which permits biasing member 625 to return pcppet 623 to its original position, blocking fluid flow out of the inflation region defined between mandrel 621 and inflatable packing element 631.

is Bridge plug 605 described herein is arranged as a per-manent bridge plug. Permanent bridge plugs, once set or inflated, cannot be deflated or unset and removed from the wellbore. It is Mthin the scope of the present invention, however, to provide a retrievable bridge plug, which may be selectively inflated and deflated and removed from or repositioned in the wellbore. Such a retrievable bridge plug may be obtaired by provision of conventional deflation means to pe rm it selective ir-,fia'jon and deflat,,-,n cl' the retrievable bridge plug. Bridge plug 605 -provides a drainage passage 621a, in fluid drainage sand (331 in Figure 6) through sand screen 607, and in commuricaticr, with an exhaust member (guide shoe 549),c provide drainage of fluid frcrn. te plug merriber, With reference now to Figures 1 through ge, Le cc-.-:rat,;ci.1 of the apparatus -will be described. The following description is of a through- tubing formation fracturing operation. Hcwever, the apparatus is not limited in utility to either thrcugh-tubing operations orr -acturing and other se=ndary cc.-. raticr.s.

As a preliminary step, -vckstr,.g 3 is prepared a, the s.-yrfac-- a terminal er,,-.' or sub adapted for de'lveri.ig and salting a car,",,icn cr obstruction mern,be,,. p(efe(ably inflatable packer 5, 605, Part5Con or obs,.-, jc!':cn r-.e,-.iber 53 605 need rct, h.cwever, be inflatable -acker 5, 605. bL;t wuld be _any 5-^r4t c' we;!t-,cre tool 3 c zeec,-vely and at leas' pw: 1, Wor4Kstr'ing 3 lhen 'is r.;r \e!l:cre 1 to a de.c,l 0( locat;cn theroin. Asillustrated in Figures 1 ar,-4 S. ie selected depth cr loca' ' ]or, in welit>cce 1 2 rn.ay be a point be.Yeen sets of perforations 13, 15, wherein it is advantageous to eparate and isolate a First.,.,iellbore region cr zone proximal 1,0 one set of perforations 13 from a second region or zone proximal to a second set of perforations 15. At the selected depth or location in wellbore 1, partition or obstruction member 5, 605 is set 5 and released from workstring 3 in a conventional manner.

For through-tubing operations, it is advantageous that workstring 3 and partition or obstruction member 5, 605 have outer diameters that are as small as possible to facilitate movement of workstring 3 and partition or obstruction member 5, 605 through reduced-diameter production tubing or otherwise obstructed wellbore sections.

An inflatable packer 5, 605 is provided with an elongate screen filter assembly 7, 607, which is in fluid flow communication with a fluid exhaust assembly 9, 647 to provide fluid drainage. Preferably with such an inflatable packer, a slurry of drainage or filter sand is (331 in Figure 6) deposited adjacent to inflatable packer 5, 605 in a quantity sufFicient to fully encase or enclose screen filter member assernbly 7, 607. Such a colurr,n of drainage sand provides a pr,--filter for the screen filter assembly 7, 607, preventing abrasive fines from entering inflatable packer 5, 605 and tending to cause premature mechanical failure of inflatable packer 5, 605. A preferred drainage sand column (331 in Figure 6) is formed of coarse, 20140 mesh, silica sand that is pumped into wellbore 11 in a fluid slurry with crdinary fresh water as the slurry fluid.

After partition or obstruction member 5, 605 is set and released, at least partially obstructing wellbore 1, aggregate mixture is prePared at the surface into a fluid slurry. Preferably, the aggregate mixture comprises 60% by weight coarse, 20140 riesh, silica sand, 20% by weight Interm.edlate, 1 CC mesh, silica sand, 15% by weight fine, 200 rnesh, silica sand, and -SID' 1Cy weight bertcr,.ite Or - mate. ial.

Preferably. fresh water is used as Lhe s!ur-,y fluld to hydrate and disperse bentonitiC particies Into a wiloidal form. The slurry should be sufficiently agitated to ensure dispersion of the bentonitic material.

21 The aggregate mixture slurry then is pumped through wor$(string 3 and intowellbore 1 adjacent and atop the drainage sand Wjurnn. oAter a sufficjent volume -,f a-gregaIe mixture nui,,s slur,-1 (a quantity sufficient to rc)(,4,,ce a wiu-,n at least p A period preferably greater than five to ten minutes, should elapse to permit the aggregate mixture fluid slurry to settle to a relatively quiescent condition.

After the settling period has elapsed, fracturing operations may be commenced. In a typical fracturing operation, conventional fracturing fluid (17 in Figure 1 and 317 in Figure 6) is pumped through workstring 3 into wellbore 1 at a volume flow rate sufficient to achieve the necessary fluid pressure for successful EacturnR (,-pically approaching 70 x 10'ka/m2 (10,000 psi)). As fluid pressure increases, the ax;al force exerted by fluid pressure on plug member 11, 211, 311 increases. The increased axial force on plug member 11, 211, 311 compacts plug member 11, 211, 311 and causes drainage of gross water from the aggregate mixture fluid slurry, through drainage sand and drain fitter assembly 7, 607, wherein the gross water is exhausted through fluid exhaust assembly below inflatable packer 5, 605. Gross water is fluid contained in the pores or interstitial spaces between sand grains in the aggregate mixture. Gross water is to be distinguished from hydrated water, which comprises small quantities of water that is hydrated or bonded to bentonitic pardc!es.

It is extremely advantageous to drain gross water from plug member 11, 211, 311, so that the aggregate mixture can be compacted to a strong, substantially solid and substantially fluid-impermeable plug member 11, 211, 311. Hydrated water is desirable because it maintains bentcnitic partides in the hydrated or swelled form, which tends to reduce the fluid permeability of plug member 11, 211, 311.

Thus, a preferred plug member 11, 211, 311 M1 possess two regions of differing permeability: a solid substantially fluid icn.perrneab;e, force transferring region: and a relabvely fluid- oermeable drainage sand re-glon. Sween filter 7, 607 of inflatable packer 5, 605 pe mn ilts drainage of gress water frorn, pijg member 11, 211, 311 yel, prevents sl:gnficant quantities of t, e aggregate mixture of piug member 11, 211. 311 cc drainage sand 331 from Izeing cam, ed ayray wiLli the gress water.

22 1 As fluid pressure is increased, plug member 11, 211. 311 is and con, pacter,' and b,?-me, rnare substantially and szrc)r,,ger. It is believed that plug member 11, 211, 311 employs a "slip-stick" deformation mechanism, which improves the strength and substantial fluid impermeability of plug member 11, 211, 311. It is believed that the combination of coarse. intermediate, and fine sand pafficJes, along with the ultrafine, hydrated, bentonitic particles, permits plug member 11, 211, 311 to deform continuously as axial forces exerted thereon vary. This continuous deformaCon, called the slip-stick mechanism, permits Plug member 11, 211, 311 to compact into a strong and substantially fluid-impermeable plug that continuously redistributes stresses within itself, thereby avoiding disintegration and failure. During the fracturing operation, the slip-stick mechanism of the aggregate material of plug member 11, 211, 311 permits plug member 11, 211, 311 to seal against fluid pressure loss, and to transfer axial loads, which otherwise would be exerted directly on inflatable packer 5, 605, to wellbore 1, which can more easily bear such extrerne loads. Fluid drainage must be provided to permit the aggregate mixture to compact tightly and to achieve the sl,,c-sltick deformation mechanism, which cannot be achieved if the content of gross vater in the aggregate mixture is excessive.

It should be noted that force transfer away from parlidon or cbstruction member 5, 605 is sufficiently substanUal that partition member 5, 605 may be unset or deflated, and plug member 11, 211, 311 will maintain its strength and sealing integrity.

After fracturing operations are complete, plug member 11, 211, 311 may be disintegrated, dissolved, or washed out (substantially as deser,bed with reference to Figure 8) by directing a high-pressure fluid strearn 19 from wcr<string 3. The disintegrated fluid member and fluid may be circulated cL of wellbore 1 or sucticned therefr-.r.-i using a conventional wellbcre tocl.

Thus, tne apparatw- is cperatle In, a of m.cdes of operat!cn, tne modes of operation incjudir.g. a delivery mode of cperation In,,tiicll an aggregate mixture including particulate matter is conveyed into a wellbare In a fluid slurry fcrm to a position adjacent a partition or obstruction member Another mode of 23 Operation i's a Wmpaction mode in wtilch axial force from a source of axial force in the .Yellbr,rg:s applied to the aggregate m. 1xture to compact the agGregate mixture and at leas'. Pa.-;aily forrn a plug men-,rer (et another mode of cpPgration is a for.ce-transfer mode in which the plug member trans.ers force from the wurca Of axial force away from the partition member into the wellbore. Still another mode of operation is a wash out mode of in which the plug member is disintegrated by application of a stream of high-pressure fluid. Still another mode of operation is a communication mode in which the plug member is disintegrated and the partition member is removed from the wellbcre thereby allowing fluid wmmunication between first and second wellbore regions.

The apparatus has a number of advantages, One advantage.

is the provision of a strong, substantially fluid-impermeable means for sealing against fluid flow ccmmunication between a firs', and second regions in a wellbore. Another advantage is that the force transier &,aracteristics of the plug member obviate the need for expensive high pressure rated partition. or obstruction members, such as inflatable packers or bridge plugs. Therefore, through-tubing operations and operations in otherwise obstructed wellbcres are facilitated and rendered less costly. Still advantage - js that the plug mernber is fo mi, ed easily and is disintegrated easily, permiCing rapid and efficient workover or secondary recovery operations.

The particulate matter pressure plug - may be ut, i izzed in completion operations in lie,-, cl; particular wmpleticn tools or prwesses, or in supplerrentation of particular welltcre tocls and processes. Figures 10A through 1ON are s;t-.plified schematic depicticr.s cf particular wellbcre cerrplet'l-cn operations, and will be..,ljlized to provide examples of how the particulae,,na,-er pressure plug may be Liilized in --rnpleticn operations, D u r: ng wm,.c 1 etien cc er s, a,% e!!. tere 10 0 1 s a s L,.rlace lcca,,icn is deFine--4 by a t,-rehcle 1003 extends earth fcr-,naticns 1MS. Njost welltcres lrcLee a casing string 10071 is secired in position re!3t]ve to borehole 1003 by L.ecr.er.t I G09. In scrre situaticils, all or a portion 2.4 W of the casing string is secured in position relative to the borehole through utilization & external casing packers, such as exlernal casing packer 1011 which Is depicted scher-.a,.;cally in Figure 10B The particulate matter pressure plug 1013 may be utilized in combination with cement 1009 andlor extemal casing packer 1011. In this particular configuration, which is shown in Figure 1013, the particulate matter pressure plug 1013js utilized to transfer loads laterally from casing string 1007 to borehole 1003.'Figure 10C depicts particulate matter pressure plug 1013 disposed between upper and lower intervals of cement 1015, 1017, and which facilitates the transfer of loads from casing string 1007 to formation 1005.

During completion operadons, sections of radially reduced casing are suspended from larger diameter casing which is disposed above and secured in a fixed position relative to the borehole. This is shown schematically in the view of Figure 10D. As is shown, lower casing section 1021 is lowered through the central bore 1023 of upper casing section 1019, and secured in position relative to upper casing section 1019 by gripping and sealing assembly 1025, which is shown only schematically in this view. Figure 10E depicts how the particulate matter pressure plug of the present invention may be utilized with a gripping and sealing assembly 1025 in order to transfer loads laterally from lower casing section 1021 to upper casing section 1019, and to simultaneously seal the potential fluid flow path between upper casing section 1019 and lower casing section 1021.

As is shown in Figure 1OE, pafficulate matter pressure plug 1029 may be provided in a position intermediate lower casing section 1021 and upper casing section 1019. In the view of Figure 1OE particulate matter pressure plug 1029 is located intermediate metal-to-metal seal 1033 and gripping assembly 1027, both of which are depicted schematically to simplify the drawing. As is shown, particulate matter containment member 1031 is disposed beneath particulate matter pressure plug 1029 Particulate maCer pressL:re plug 1029 operates to transfer load laterally from lower casing section 1021 to upper casing section 1019, in supplementation of the load transference which occurs through gripping assembly 1027. Additionally. particulate matter pressure plug 1029 may be utilized to seal the potential fluid flow path between lower casing section 1021 and upper casing section 1019, in supplementation of the metal-to-metal seal 1033.

Typically, during completion operations, a workstring (or alternatively a production tubing string) is lowered within the casing string to a desired location. The workstring typically includes one or more perforating guns, one or more valves, and one or more packers, which cooperate to allow for the selective perforation and testing of particular formations. In general terms, the packers are utilized to isolate an annular region between the workstring and the casing string in a region of interest The perforating gun or guns are Utilized to perforate a particular section or sections of the casing string to allow the flow of fluids such as formation water, oil, and gas from the formation into the annular region. The fluids are allowed to pass through one or more valves into the workstring, where they are drawn to the surface and analyzed.

Subsequent to the well testing operations, a production tubing string is lowered into position within the casing string, and packers are set to centralize, stabilize, and locate the production tubing string relative to the casing string, as well as to seal particular annular regions.. Then one or more valves are open to allow production of the fluid from the annular region to the central bore of the production tubing string.

These operations are shown collectively and schematically in Figure 10F. As is shown, a workstring or production tubing sting 1037 is lowered within casing string which is composed of upper casing section 1019 and lower casing section 1021. The workstring of production tubing string includes a packer 1039, a valve 1041, and a perforating gun 1043, all of which are depicted schematically.

In Figure 1OG, production tubing string 1037 is shown in a 2xed position relative to casing string 1045, with packer 1043 set to locate, stabilize, and seal, as is conventional. As is shown perforations 1047 allow the inward flow of hydrocarbons and formation water, which are produced through valve assembly 10.49 and lifted to the earth's surface utilizing either gas lift technology, sucker rod pumping devices, or submersible pumps, none of which are shown in this figure for purposes of simplicity and clarity. As is shown in Figure 10H, a particulate matter pressure plug 1051 may be provided atop and adjacent to packer 1043 to supplement the transference and sealing action of packer 1043.

26 During certain operations, it is desirable to plug temporarily or permanently a tubular conduit, such as production tubing string 1037 of Figure 101.

As is shown, a temporary plug 1053 is located in the central bore of production tubing string 1037, The particulate matter pressure plug 1055 of the present invention may be provided above and adjacent the temporary or permanent plug to bolster the pressure differential which can be accommodated by plug 1053, and to supplement the sealing action of plug 1053. Figure 10J shows an alternative use of the particulate matter pressure plug to bolster the load bearing and sealing action of bridge plug 1057. As is shown, particulate matter pressure plugs 1058, 1059 are located adjacent bridge plug 1057, and operates to increase the sealing and load transference capabilities of bridge plug 1057. In the view of Figure 10K, particulate matter pressure plug 1061 is shown located adjacent annulus safety valve 1063, and may be utilized to bolster the sealing capability of annulus safety valve of 1063.

Figure 10L depicts the utilization of the particulate matter pressure plug of the present invention to seal leaks within the tubular conduit, such as tubing string 1071. As is shown, a partition member 1069 is located adjacent leak 1065 and the particulate matter and binder is located there above and adjacent to leak 1065. The particulate matter pressure plug is utilized in this configuration primarily as a sealing device, and canobviate expensive workover operations which would ordinarily require the pulling of production tubing string 1071 in order to repair leak 1065.

The particulate matter pressure plug of the present invention may also be used in flow control and gravel packing operations, as is depicted schematically in Figures 10M and 1ON. Figure 10M schematically depicts a completed wellbore 1081 with production tubing 1083 disposed therein. A plurality of perforations 1085 are provided to allow the flow of hydrocarbons into the wellbore. The production tubing string 1083 includes a gravel pack screen 1087 which allows wellbore fluids to flow into the production tubing string, but which prevents the flow of gravel pack material 1093 (such as sand, glass beads, or other particulate matter such as gravel) which has been intentionally placed into the wellbore and surrounding formation to check the 27 i inward flow of fine particulate matter such as sand, and to prevent the collapse or deterioration of the wellbore while the well is being produced.

The pressure particulate matter pressure plug 1089 of the present invention may be located in a predetermined position within the gravel pack to prevent or limit the flow of fluids between particular portions of the wellbore. If a complete restriction is desired then the oarticulate matter 1 is compacted sufficiently to form a fluid impermeable barrier., however, if a mere flow restriction is required, then the particulate matter is compacted to a lesser extend to allow for some limited flow through particulate matter pressure plug 1089. This technique is particularly useful when subsurface formations have differing pressure and production characteristics.

The particulate matter pressure plug may be utilized to restrict or block flow between formations which have greatly differing pressures, for example. A plurality of the particulate matter pressure plugs may be located throughout the gravel pack to obtain particular flow and production goals.

Another utilization of the particulate matter pressure plug of the present invention is to obtain a flow objective. As is shown in Figure 1 ON, production tubing string 1084 extends downward within 1082. A plurality of perforations 1088 are provided to allow the flow of wellbore fluids into the annular region. Production tubing string includes production valve 1086 which allows for the inward flow of wellbore fluids. As is shown in Figure ION, the annular region between production tubing string and wellbore 1082 is gravel packed with particulate matter. As is shown, particulate matter pressure plug 1094 is provided to block or restrict the flow of fluids between annular regions 1090 and 1092. A second particulate matter pressure plug 1096 is provided to prevent or restrict the flow of wellbore fluids between annular regions 1092 and 1098. This may be especially useful if the formations above or below valve 1086 are low pressure zones, region of the wellbore surrounding valve 1086 is a high pressure zone. It may be beneficial to block the flow of fluids up and down the wellbore annulus in order to prevent a net loss of pressure from a highpressure zone to a lower pressure zone.

28 1 p itx-- rm of forming the plug ir,ciules,!7ree t)road rriethod szeps The First step is to convey a quar, ',.ty G' matter to a particular wellbore location. Then, the particulate matter is Writained at least temporarily in order to allow compaction. The third step is COMpaction and dehydration of the particulate matter in a manner which generates the useful force transference and seating of the present invention. A variety of alternatives exists for the conveyance, containment, and wmpaction operations, each of whirh will be discussed herebelow. Figures 11A through 111 schematically depict a varie'.'y of wriveyance and containment options available for the particulate matter pressure plug of the present invention.

First with reference to Figure 11A, a dump bailer 1101 may be- LAilized to dump the particulate matter in a wellbore fluid column either remotely from or adjacent a containment member 1106 in order to allow for the aggregation of particulate matter 1103 and formation of the particulate matter pressure plug of the present invention, preferably through application of force through a fluid column, but noll necessarily so. Figure 113 depicts the utilization of a pump 1107whi&, dired's a slurry including the particulate matter through a wellbore conduit 1109 (such as a production tubing string) and a valve 1111 to locate particulate matter 1113 adjacent ccntai,imert barrier 1115. In Figure 11C, the utilization of a coiled tubing Sluing 1117 is depicted to. locate particulate matter 1119 adjacent a' wellbore barrier or containment member. In Figure 11D, an electhcal wireline 1121 is depicted energiz.ing an electrically aCtU2ble pumping and dumping device 1123 which deposits partic-,late rnatter 1125 adjacent a containment barrier in order to form the particulate matter pressure plug of the present invention. Figure 11 E depicts the utilization of a hydraulic =ntral fine 1127 to deposit particulate matter 1129 adjacent a wellbore baffier such as safety valve 1131. Figure 11F depicts the utilization of an cFshore umbilical 1133 to deposit parfitulate matter below subsurface weRhead 1135 to lecate matter 1139 in a subsLr,,lace 1137 adjacent a barn.er or rr.e;nbe.- Figure 11G dePlcs t,l-e Liflizatior, of ar elas.,cmer:e - ha!--cr.-"ype conveyance device which loaded wan pa(,,iculate matter weighted. and dropped Within a wellbore fluid column where it eventually ruptures and deposits the parilculate matter adjacent a wntainment barrier 1145 in a particular locat';C.n 114. 3, Fi gure 11 H 29 f A schematically depicts the utilization of a fluid-permeable sack or containment 1147 which is loaded with particuiate matter and a binder, and which is Pumped down or ra,jitl-driven downward within a particular fluid column to be Iccated adjacent a ---.nta;nrr,ent barrier rnerriber 1149 Figure 111 depicts utilizaticn cf a mesh or wire basket 1151 which may be filled with particulate matter and lowered to a particular location within a wellbare for formation of the pressure plug of the present invention.

Figure 11J is a perspective view of one type of wire mesh basket, As is shown, in this particular e-nbcdiment, the basket is cylindrical in shape, and includes a central bore 1161 which allows the basket to ride to a particular location along the exterior surface of a particular wellbore conduit. Preferably, the basket is formed of a vire having a mesh size which is sufficient to contain all or most of the particulate matter which is loaded therein. Force is applied to the particulate matter through the wire mesh ccritainer by application of a high pressure fluid column thereto in order to forrin a load transfizerring and sealing particulate matter pressure plug.

Figures 11 K and 11 L depict two alternative techniques for wmPacting and dehydrating the particulate matter pressure plug of the present invention. Figure 11 K depicts the utilization ofl an axial loading device which perceives an axial load and applies it through piston head 1173 to particulate matter 1175 to comipress it acainst containment member 1177. An alternative technique is depi","ed in Figure 11 L. This technique involves the initiation of a chemical reaction to generate gas from combustive or explosive material 1181, which acts on movable pis',cn component 1183 which is urged downward to compress particulate matter 1185 against wntainment member 1187.

One significant advantage of the present inver.ticn is that tihe part. ticulate ma"Ler pressure plug is substantially unaffected by high wellbere ternperatures, unlike many wellbcre tools which include elas',%-.mer;lc wmpcnents and in partle:jlar \'.ellbcre tools which include elastomeric sealing ccr--cnents. 7he pressure plug of the present invention may be used, either in lieu of, or In -.; zjppcr+, cf, a c.-r,venlk'.onal wellbere tool, a&-,d may te directly exposed to reg;,cr. s cl; Cle are paiticularly high-temperature r2gic,-,s. The parllwlale rriat4er Cressure plug of the present invention is also advantageous with respect to the prior art insofar as it is extremely low in cost. The particulate matter pressure plug of the present invention is further advantageous over the prior art in that it is easy to locate and remove the particulate matter as compared to mechanical wellbore tools which are difficult to repair or replace.

While the invention has been shown in only one of its forms, it is not thus limited, but is susceptible to various changes and modifications without departing from the scope thereof.

31

Claims

CLAIMS:

1. A method of forming a pressure plug in a wellbore, comprising the method steps of: forming a mixture of a plurality of types of particulate material; depositing said mixture of said plurality of types of particulate material adjacent a selected wellbore structure utilising at least one of the following delivery mechanisms; a) a coiled tubing string; b) an electrically-actuated pump carried on a wire line; c) a hydraulic control line; or d) an offshore umbilical; providing a containment member for locating said plurality of types of particulate matter, formed at least in part of:

a) b) an elastomeric bag; a fluid-permeable sack c) a mesh basket; or d) a wire basket; and compacting said plurality of types of particulate material into a plug by applying force thereto; and draining fluid from at least a portion of said plug during at least compaction.

2. A method of transferring axial force in a wellbore from a fluid column to a wellbore surface, comprising the method steps of: delivering a mass of particulate material to a particular location in said wellbore utilising at least one of the following delivery mechanisms: a) b) wireline; a coiled tubing string; an electrically-actuated pump carried on a 32 1 W c) a hydraulic control line; or d) an offshore umbilical; providing a containment member for locating said particulate matter at said location formed at least in part of:

a) b) c) is an elastomeric bag; fluid-permeable sack mesh basket; or d) a wire basket; and applying said axial force from said fluid column to said mass of particulate material causing mechanical compaction and partial draining of said mass of particulate material and reducing fluid permeability of said mass of particulate material; and transferring through said mass of particulate material a selected amount of axial force to said wellbore surface.

3. A method of transferring axial force according to claim 2, further comprising:

reversibly binding said mass of particulate material together with a binding component.

4. A method of transferring axial force according to claim 3, further comprising:

filling interstitial spaces in said mass of particulate material with said binding component.

5. A method of transferring axial force according to claim 2, further comprising:

filling interstitial spaces in said mass of particulate material with a hydrating component.

6. A method of transferring axial force according to claim 2, further comprising:

33 removing said mass of particulate material from said wellbore by applying a high pressure fluid stream thereto.

7. A method of transferring axial force according to claim 2, further comprising:

disintegrating said mass of particulate material by applying a removal fluid thereto; and removing said mass of particulate material, in slurry form, from said wellbore.

8. The method of transferring axial force according to claim 2, further comprising: removing fluid from said mass of particulate material during compaction.

9. A method of transferring loads in a wellbore, comprising the method steps of: conveying a quantity of particulate matter of differing particulate sizes to a predetermined wellbore location utilizing at least one of the following delivery mechanisms:

a) a coiled tubing string; b) an electrically-actuated pump carried on a wirline; c) a hydraulic control line; or d) an offshore umbilical; containing said particulate matter in a containment member formed at least in part of:

a) an elastomeric bag; b) a fluid-permeable sack c) a mesh basket; or d) a wire basket; and compacting said particulate matter; utilising said particulate matter to transfer 34 p laterally a preselected amount of force in said wellbore.

10. A method of transferring loads according to claim 9, further including: dehydrating at least a portion of said particulate matter; and sealing a flow path in said wellbore with said particulate matter.

is

11. A method of completing an oil and gas wellbore, comprising the method steps of: providing a tubular string; providing a plurality of completion tools; locating selected ones of said plurality of completion tools in preselected locations on said tubular string; lowering said tubular string into said wellbore, utilising selected ones of said plurality of completion tools to perform at least one of (I) fluid flow paths within said wellbore; conveying a quantity of particulate matter of differing particulate size to a predetermined wellbore location; at least temporarily containing said quantity of particulate matter at a predetermined wellbore location in a containment member formed at least in part of: a) an elastomeric bag; b) a fluid-permeable sack c) a mesh basket; or d) a wire basket; and compacting said quantity of particulate matter; utilizing said quantity of particulate matter to perform at least one of (1) transfer load within said 1 i is wellbore, and (2) seal fluid flow paths within said wellbore; wherein said particulate matter is utilised to perform at least one of the following operations:

1) to supplement the action of cement to transfer loads from tubulars within said wellbore formation surrounding said wellbore; 2) to form a seal in said liner hanger assembly; 3) to seal a leak in a particular wellbore tubular; 4) to secure a gravel pack assembly in place; 5) to co-operate with a gravel pack assembly to control fluid flow; 6) to isolate a zone by sealing above and below the zone.

12. A method of completing an oil and gas wellbore, according to claim 11 wherein said quantity of particulate matter is conveyed within said wellbore utilising at least one of:

(1) gravity; (2) a fluid pump; (3) coiled tubing; (4) an electric line delivery mechanism; (5) a control line; and (6) an umbilical.

13. A method of completing an oil and gas wellbore, according to claim 11 wherein said quantity of particulate matter is contained utilising at least one of:

(1) a fluid permeable membrane; (2) a rupturable container; and (3) a mesh housing.

: 40003: RE-SH: RI: FURNWC5 41

36 Amendments to the claims have been filed as follows 1. A method of forming a pressure plug in a wellbore, comprising the method steps of: forming a mixture of a plurality of types of particulate material; depositing said mixture of said plurality of types of particulate material adjacent a selected wellbore structure utilising at least one of the following delivery mechanisms; a) b) wireline; c) d) a coiled tubing string; an electrically-actuated pump carried on a a hydraulic control line; or an offshore umbilical; compacting said plurality of types of particulate material into a plug by applying force thereto; and draining fluid from at least a portion of said plug during at least compaction.

2. A method of transferring axial force in a wellbore from a fluid column to a wellbore surface, comprising the method steps of: delivering a mass of particulate material to a particular location in said wellbore utilising at least one of the following delivery mechanisms: a) a coiled tubing string; b) an electrically-actuated pump carried on a wireline; c) d) a hydraulic control line; or an offshore umbilical; applying said axial force from said fluid column to said mass of particulate material causing mechanical compaction and partial draining of said 1 mass of Particulate material and reducing fluid permeability of said mass of particulate material; and transferring through said mass of particulate material a selected amount of axial force to said wellbore surface.

-1 3. A method of transferring axial force according to claim 2, further comprising:

removing said mass of particulate material from said wellbore by applying a high pressure fluid stream thereto.

7. A method of transferring axial force according to claim 2, further comprising: disintegrating said mass of particulate material by applying a removal fluid thereto; and removing said mass of particulate material, in slurry form, from said wellbore.

19 8. A method of transferring axial force according to claim 2, further comprising: removing fluid from said mass of particulate material during compaction.

WP 9. A method of transferring loads in a wellbore, comprising the method steps of: conveying a quantity of particulate matter of differing particulate sizes to a predetermined wellbore location utilizing at least one of the following delivery mechanisms:

a) a coiled tubing string; b) an electrically-actuated pump carried on a wireline; c) a hydraulic control line; or d) an offshore umbilical; containing said particulate matter; compacting said particulate matter; utilising said particulate matter to transfer laterally a preselected amount of force in said wellbore.

10. A method of transferring loads according to claim 9, further including: dehydrating at least a portion of said particulate matter; and sealing a flow path in said wellbore with said. particulate matter.

11. A method of completing an oil and gas wellbore, comprising the method steps of: providing a tubular string; providing a plurality of completion tools; locating selected ones of said plurality of q 4: 4 044.: do a 00 I.:.

0 0 0 completion tools in preselected locations on said tubular string; lowering said tubular string into said wellbore, utilising selected ones of said plurality of completion tools to perform at least one of (1) fluid flow paths within said wellbore; conveying a quantity of particulate matter of differing particulate size to a predetermined wellbore location; at least temporarily containing said quantity of particulate matter at a predetermined wellbore location; compacting said quantity of particulate matter; utilizing said quantity of particulate matter to perform at least one of (1) transfer load within said wellbore, and (2) seal fluid flow paths within said wellbore; wherein said particulate matter is utilised to perform at least one of the following operations:

12. A method of completing an oil- and gas wellbore, according to claim 11 wherein said quantitv o of particulate matter is conveyed within said wellbore utilising at least one of:

1 (1) gravity; (2) a fluid pump; (3) coiled tubing; (4) an electric line delivery mechanism; (5) a control line; and (6) an umbilical.