Method of Supporting a Subterranean Conduit

Abstract

A method and apparatus for consolidating a formation penetrated by a wellbore utilize radial stress. The radial stress is created by loading the wellbore, wellbore casing or production pipe with preferably round, dense bead like materials. The shape and density of the bead like material transfers the axial direction of stress created by the vertical height of the bead like materials to a radial direction. The radial stress can also be generated by inflating an inflatable device. The radially directed stress can compact the geologic formation. This can include compaction of loose sand which otherwise may enter the production flow of hydrocarbon. The bead like materials can also support the wellbore casing or production piping from point loading. This can include point loading created by the movement of salt or other subterranean formations. The bead like materials can include barite, hematite, iron oxide, ilmenite, metal, alloy and combinations thereof.

Description

FIELD OF INVENTION

A subterranean wellbore, perforation hole, any tube, including casing, or tubing inside the wellbore or casing, can be called a subterranean conduit. These conduits are often under stress or pressure and, in some conditions, these conduits are not strong enough to withstand the stress or pressure. The conduits may fail and generate other problems, including interruptions of hydrocarbon production. This invention provides a method to provide a substantial radial stress to a subterranean conduit high enough to support the conduit to prevent its collapse or the collapse of a wellbore, casing or tubing. It also prevents sand production, prevents closure of a hydraulic fracture for hydrocarbon production and prevents or closes a micro-annulus. The provided radial stress is substantially uniform radially around a subterranean conduit to best support the conduit.

During the production of hydrocarbon, the pressure of a well at a wellbore location and the pressure at a producing formation location may be changing. These locations include those in the rock formation close to or next to the wellbore at the production zone, in the annulus between different sets of casing or between a set of casing and production tubing and in the tubing. When the pressure differentials across these locations are large enough, the wellbore, casing or tubing may collapse or a micro-annulus may form causing a loss of required pressure isolation. For example, during production, heat from the produced hot hydrocarbon may swell the tubing annulus so much that the casing surrounding the tubing may burst. The affected casing or tubing interval can be called an active zone.

Furthermore, the surrounding rock formations of a wellbore may not be stable with the reduction of pressure in the well over time. A sandstone formation producing oil may start to fail and gradually produce sand from the formation. This causes many production issues while enlarging the wellbore in an uncontrolled manner. Controlling the production of formation sand is very important. The wellbore interval of a sand production potential can be called an active zone.

Sometimes steel casing is run into an active zone and cemented in place. In order to produce hydrocarbon from the active zone, perforation holes along the casing are generated to access hydrocarbon bearing formations. These perforation holes may not be stable over time of production and may fail due to lack of support.

In order to enhance oil production, formations of hydrocarbon sometimes are hydraulically fractured. These fractures, which are high permeability channels for flow, are often propped open by proppants such as small ceramic particles or sand to prevent the fractures from closing back up. However, the wellbore pressure may soon decline to a low value causing the pressure to decrease in the fracture to offset the fracture closure stress and to close the fractures. So even with proppants, when the closure stress becomes high enough, the proppants may eventually be crushed or embedded in the formation and the fractures may still close, causing production rates to drop rapidly. This may be especially true in a soft formation such as the chalk formation in the North Sea area.

However, due to the need of a high rate of hydrocarbon production, the pressure differentials between the reservoir and the wellbore may have to be maintained high enough. (This differential may be achieved by maintaining low wellbore pressure.) So looking at only wellbore pressure to support the wellbore or casing, etc. is not enough.

In order to improve production of hydrocarbon, water may be injected into some wells (injectors) to push hydrocarbon out of some other wells (producers). When the formation for injecting water is highly unconsolidated, injecting water can fluidize the formation sand and generate finer particles carried by the injected water flowing to a producer. Gradually a large void may form behind the casing in the injection zone when sand grains are crushed and washed down the water stream to the producers. In a severe condition, a channel may form connecting an injector to a producer causing the failure of the operation. The wellbore interval of a channel formation potential can be called an active zone.

In some salt formations, the salt may encroach onto the casing gradually over years of production and eventually collapse the casing and cause the well to fail. The casing interval of a collapse potential can be called an active zone.

Casing may collapse when the required pressure isolation from structures such as cementing fails and high pressure fluid migrate up into a weak wellbore section where the rating of the pipe is low. The casing interval of a collapse potential can be called an active zone.

Due to hydrocarbon production, the producing formation may undergo a large compaction causing subsidence of the formations. This may collapse the casing and the tubing in the well. The casing or tubing interval of a collapse potential can be called an active zone.

The drilling fluid inside a set of casing tends to be heavy for controlling formation fluid from flowing into the wellbore at the time before the casing annulus is cemented. However, after cement slurry in the annulus has set, the wellbore fluid in the casing may be much lighter to allow the formation fluid such as hydrocarbon to flow in for producing the hydrocarbon. This reduction in density of the wellbore fluid will cause reduction in hydrostatic pressure acting on the inside of the casing. With this pressure reduction, the casing tends to shrink a little. The shrinkage of the casing outer diameter then can separate the casing from the set cement and the tiny space around the casing from this separation is called a micro-annulus. This micron-annulus can cause failure of the required pressure isolation in the annulus intended from cementing for safety or production operations. The interval of a micro-annulus potential can be called an active zone.

So an active zone is an interval of a conduit that is damaged or of concern due to proximity of voids, etc. Any active zone is defined by a zone bottom and a zone top. When a wellbore penetrating a sandstone formation sandwiched by two other formations, the wellbore interval between the interfaces of the sandstone formation and any of the other formation next to it is the active zone when sand production from this sandstone formation is of concern. For preventing fracture closure, an active zone is the interval of the wellbore containing the fracture. For damage by salt encroachment, it is the conduit interval in the salt formation. For damage by the subsidence or compaction, it is the conduit interval where the compaction or subsidence is deemed to happen. For preventing or closing a micro-annulus, it is an interval in the zone of the micro-annulus long enough to perform pressure isolation with the invented method.

This invention is about utilizing bead like materials placed in or around a subterranean conduit to convert a stress applied to the bead like materials in the axial direction of the conduit to a stress in the bead like materials in the radial direction of the conduit. This radial stress, in the bead like materials, is directed in the active zone of the conduit. In order to provide substantial support to the conduit with the radial stress, a substantial stress in the axial direction of the conduit is applied to the bead like materials to eventually generate the substantial radial stress even at the top of the active zone. It will be appreciated that the axial direction of the conduit may be vertical and the radial direction into the formation is horizontal. However this is not necessarily the case.

BACKGROUND ART

Hydrocarbon production zones frequently occur in sandstone formations or other porous media. To produce hydrocarbon from a subterranean hydrocarbon bearing sandstone formation, normally a circular wellbore has to be drilled to access the formation. The wellbore normally is deep and has to be drilled in sections. A drilling process normally begins with a large drill bit to drill a large wellbore to a certain depth. Then a set of casing with a large diameter is run into the wellbore and cement slurry is pumped into the annulus or the space between the wellbore and the casing to secure the casing in place and isolate the annulus. Then the same process continues with a smaller bit to drill a smaller wellbore ahead for a smaller casing until the hydrocarbon bearing formation is finally penetrated. The wellbore section in the hydrocarbon bearing formation can be called an active zone, which is defined between a zone top and a zone bottom corresponding to the top and bottom of the hydrocarbon bearing formation. Production tubing may then be run into the wellbore with packers to isolate the annulus between the tubing and the wellbore around it. Then the hydrocarbon may flow from the formation through the tubing to surface, driven by the formation pressure.

In summary, a wellbore may comprise many conduits. The wellbore itself may be considered a conduit. Each conduit typically is long and of a circular shape having at least an inner diameter. Each conduit may also have an outer diameter. The conduit that has only an inner diameter is typically a wellbore. The conduit that has both an inner diameter and outer diameter is typically casing or tubing. Sometimes, a conduit with a smaller outer diameter may sit inside a conduit with a larger inner diameter. The space between these two conduits is called an annulus. An annulus may be filled with set cement or fluid such as gas or liquid. The following are some typical examples.

1. Sand Production and Sand Control

During hydrocarbon production, sometimes, formation sand is produced with the hydrocarbon flow. The production of formation sand into a well has been a problem plaguing the oil and gas industry. It has an adverse effect on well productivity and equipment. The produced sand has essentially no economic value. But it can plug wells, erode equipment and settle in surface vessels. Controlling formation sand is costly and usually involves slowing the production rate in some way. Though the conventional methods of sand control can enable production for some extended time, failures can be observed from time to time. Repairing a well may have a huge direct cost plus a loss of production.

Sand control techniques to minimize or delay the sand production are normally applied during some well completion operation. These conventional techniques include (1) mechanical retention and (2) chemical consolidation.

All mechanical retention methods are based on the principle of retaining by screening a certain portion of the formation material such as sand of a larger size to prevent the remainder from entering the well. The commonly used devices are screens or slotted liners. These devices may not last for long due to erosion from sand grains. Furthermore, the retaining screens or slotted liners are a two-dimensional filtering mechanism and tend to be plugged and production therefore is compromised. To prevent this problem, large and clean sand particles (which are called gravel because they are much larger than formation sand particles) are placed into the annulus around the screens or slotted liners to form a packing. This method is called gravel packing in general and it was taught in U.S. Pat. No. 2,171,884. A gravel packing forms a three-dimensional filtering mechanism and it is much harder to be plugged by the formation sand. This placement allows the entry of fluids through the gravel but filters the formation sand from the flow stream so that sand-free production is possible. With gravel packing, the sand control effect can last much longer. However, even in most of gravel packs, a finite quantity of solids is still produced. Due to the damage to the formation or to the gravel packing during operations, the production of hydrocarbon may suffer from a so called “skin” effect. This means extra flow resistance is created by either the formation damage or the gravel packing damage. In order to get rid of this negative “skin” effect, frac-and-pack improves gravel packing by also fracturing the near wellbore area to create large flowing channels of hydrocarbon to by-pass the near-wellbore damage. For this improved method, the sand is still retained by the gravel packing.

For an example displayed in FIG. 1 for an open hole completion with gravel packing for sand control, a wellbore is drilled vertically through the cap rock of shale formation 1 and the hydrocarbon producing sandstone formation 2 below the cap rock. There is steel casing 3 set with cement 12 right at the interface of the sandstone and shale formations. In an openhole completion scenario, in the open hole 4 of sandstone, there is production tubing 5 with perforations or slots wrapped with screens 6 and gravel packing 7 is installed around the production tubing in the sandstone formation section. A packer 8 is set close to the top of the sandstone formation inside the casing to isolate the annulus 9 between the casing and the tubing. The hydrocarbon flow 10 is intended to go from the sandstone formation 2 through the gravel packing 7 and the screens 6 into tubing through its perforations or slots 5 then upward to the surface. The mesh size of the screens 6 and the gravel size of the gravel packing 7 are accurately selected such that the majority of the formation sand cannot pass the gravel packing 7 and the gravels cannot pass the screens 6. With gravel packing 7, during hydrocarbon production, some sand, especially those fine sand particles, can still be produced over time, forming some voids 11. During sand production, some gravel packing may be displaced by formation sand and exposing screens directly to sand causing erosion of the screens. Then even larger sand grains can be produced. The produced sand may further plug the production tubing. In severe conditions, the voids 11 can form even behind the casing. These voids 11 may cause subsidence and the well will eventually fail.

If it is a cased hole completion scenario for gravel packing, for the example in FIG. 1, the casing will extend deep to cover all the sandstone formation and be cemented. Then the casing will be perforated by explosive to generate channels or holes on the casing wall so that hydrocarbon can be produced through. Gravel packing then will be installed in the annulus to cover the sandstone formation interval. However, after some sand fines are produced, the formation near the wellbore behind the casing will become loose and sand production will be worsen quickly. It is obvious that, even with cased hole gravel packing, the above mentioned problems can still occur.

In an injection well, water is injected into formations to drive hydrocarbon to a producer well. Particles such as sand fines can migrate away from the injection well creating voids even behind casing. If the injection well is completed without casing covering the injection zone, gravel packing or frac-and-pack may also be used to an injection well to help to stabilize the wellbore. Otherwise, the wellbore may soon collapse.

A chemical consolidation method is basically utilizing chemicals such as resin to solidify the grain-grain contacts of the formation sand in the near-wellbore area to form a consolidated zone. This consolidation normally sacrifices a little of permeability for a higher strength of the formation rock. It has been difficult to ensure all the rock around a wellbore is consolidated evenly so that no channels that can produce sand are left.

2. Casing or Tubing Damage

During the life time of a hydrocarbon production well, casing or tubing may be collapsed due to the following reasons: (1) salt encroaching; (2) subsidence; and (3) higher annulus pressure. Casing or tubing may burst when the pressure inside the casing or tubing is too high.

Some wells are drilled through a thick layer of salt. Salt formations may be plastic and cannot support its overburden above it and may slowly deform over a long time under pressure and temperature. This encroachment normally has a preferred direction. Such encroachment onto casing generates point loading. Casing has much smaller resistance to point loading than its normal rating. The point loading is getting higher over time and may eventually collapse the casing. There have been no good solutions so far. Even with casing much stronger than normally needed, casing can be collapsed easily when salt migrates onto the casing.

During production of hydrocarbon, due to the drawdown of the pressure of the hydrocarbon formation, the support to the overburden formation is getting smaller over time. This can cause severe compaction of the formation and induce subsidence. Either compaction or subsidence may cause the casing to buckle or collapse and the well to fail. Adapting the shrinkage of a formation thickness has been very challenging. Corrugated casing which can contract in the axial direction or along the casing substantially may help. However, such casing is very weak for containing pressure. Letting one set of casing freely move in another set of casing to adapt the length change is another method. However, the long-term sealing between the two sets of casing is difficult to maintain due to the movement under downhole high pressure and high temperature conditions.

During production, hydrocarbon or other fluid may leak into the annulus around casing or tubing through failed cementing sheath causing the pressure in the annulus to increase. However, the casing or tubing pressure has to be maintained low in order to produce hydrocarbon. When the annulus pressure is high enough, it can collapse the casing or the tubing. Due to these high loadings, even strong and thick wall casing may not be a good solution to casing collapse.

One way to protect the casing is to install valves or burst disks to the outer layer of casing to regulate the annulus pressure. These valves may malfunction.

3. Forming a Micro-Annulus

Steel casing is elastic. After cement pumped into an annulus around casing has set and become a cement sheath, the pressure inside the casing may be substantially reduced for production. This reduction of pressure will cause the casing to shrink. This shrinkage may cause the casing to debond or separate from cement sheath around the casing. After debonding, a tiny space between the casing and the cement sheath around the casing called a micro-annulus may form. This micro-annulus can generate the so called sustained casing pressure observed on a wellhead, which is a safety concern for the industry. In a severe condition, the normally required pressure isolation from cement will fail. A micro-annulus is a very tiny space and it is very difficult to pump a material such as cement to regain the sealing or the pressure isolation.

4. Fracture Closure

In FIG. 2, a wellbore 12 is drilled in a hydrocarbon formation 11 and production tubing 13 is placed in the wellbore 12. Hydraulic fractures 14 are created to help to conduct the hydrocarbon flow 15. For a vertical wellbore, the fractures tend to run vertically in the hydrocarbon formation 11 reaching an impermeable cap formation such as a shale formation. When the formation is of a low permeability, the majority of hydrocarbon flow 15 may come through the fractures. When the wellbore pressure is maintained low for a production rate high enough, the pressure inside the fracture will be also low. When the fracture pressure is too low, eventually, the fractures can close and the production rate can drop dramatically.

This invention is to provide a method to solve all of these above problems to the conduits.

SUMMARY OF THE INVENTION

This provisional application incorporates by reference herein provisional application entitled “A Method of Supporting a Subterranean Conduit”, application No. 62/020,003 filed Jul. 2, 2014 and application No. 62/032,300, entitled “A Method of Supporting a Subterranean Conduit” and filed Aug. 1, 2014.

The invented method is to apply a substantial radial stress at least to the active zone of a conduit such as a wellbore formation, casing or tubing, where they may otherwise be damaged or a micro annulus has formed. The radial stress is applied by first placing bead like materials into the conduit or its annulus to cover the active zone in order to form a packing of the bead like materials to provide a substantially uniform and radial support to the conduit. The bead like materials can conform to the wellbore wall. When additional radial stress is generated in the packing, it can be transmitted to the wellbore wall substantially uniformly. The bead like materials may be shaped and dimensioned to transfer axial or vertical stress to radial stress. The material shape and dimensions (structural elements) can fill voids or irregularities within the formation. The bead like materials can be round to readily move against other similar beads in response to stress. The property allows the direction of stress to be readily changed. In one embodiment, the bead like materials are not compressible or deformable thereby facilitating the transfer of direction of stress. Substantial force can then further be optionally applied to the packing to let the packing generate a substantial radial force acting on the wall of the conduit to further support the entire active zone of the conduit to prevent the sand production, fine migration, collapse (or burst) of casing or tubing or prevent or close a micro-annulus and keep fractures open during production. This substantial force can be applied through one or more of inflatable devices such as close-ended rubber tubes run substantially into the bead packing. Preferably, the rubber tubes are be run through at least 50% of the bead packing in the axial direction. Substantial radial stress then can be generated by inflating the device in the packing. Optionally, the tube can be run through the packing multiple times such as with loops. Also optionally the tube can be pressurized to inflate from both ends.

The substantial force applied to the packing may be achieved by added weight of tubing or casing, the weight of more of bead like materials or the weight of a fluid from the top of the packing. The substantial force applied to the packing can also be achieved by an elastic force coming from a spring, pressurized fluid, expanding elastomer or similar acting to the packing.

BRIEF SUMMARY OF DRAWINGS

The accompanying drawings, which are incorporated in and constitute a part of the specification, illustrate preferred embodiments of the invention. These drawings, together with the general description of the invention given above and the detailed description of the preferred embodiments given below, serve to explain the principles of the invention.

FIG. 1 illustrates a cased hole completion wherein the casing extends deep to cover the sandstone formation.

FIG. 2 illustrates a wellbore drilled in a hydrocarbon formation and production tubing is placed in the wellbore. Hydraulic fractures are created to help to conduct the hydrocarbon flow.

FIG. 3 demonstrates a bead packing column 32 of loose beads and the packing has a column height 34.

FIG. 4 illustrates a point near a wellbore of a vertical well, after stress redistribution. Illustrated are the three local principal stresses: the vertical stresses, S_v, the tangential stress, S_t, and the radial stress, S_r.

FIG. 5 illustrates a top view of a vertical wellbore in a sandstone formation. Illustrated is placing bead like materials into the active zone of the wellbore to form a bead packing column.

FIG. 6 illustrates a bow type spring having multiple bows mounted on at least two bow rings. The bows are parallel to the axis of wellbore.

FIG. 7 illustrates an exemplary embodiment of the method to control sand production.

FIG. 8 is a cross sectional view of the wellbore illustrated in FIG. 7.

DETAILS OF THE INVENTION

FIG. 3 demonstrates a bead packing column 32 of loose beads and the packing has a column height 34. When a vertical stress S_v 31 is applied downward at the top of the column, the bead packing tends to bulge radially or demonstrate radial expansion tendency 33. If the bead column is radially confined such as in a conduit and the bulging is not allowed, a radial force or stress S_r 35 then is generated. This radial stress is acting on the wall of the conduit. This means the vertical stress 31 has been converted into a stress in the radial direction. This is a basic property of materials. The magnitude of the stress converted can be related by the Poisson's ratio of the packing. Stress is just force on a unit area. If v is the Poisson's ratio, S_v is the vertical stress, then the radial stress S_r=[v/(1−v)]S_v. With different bead like materials, the packing may behave slightly different in term of the Poisson's ratio, v. It is preferred that the bead like materials are less compressible and deformable to better convert the vertical stress to radial stress. Poisson's ratio can be measured in a lab for a specific type of packing. A packing with a larger Poisson's ratio can convert more of the vertical stress to radial stress. A packing with a smaller Poisson's ratio can convert less of the vertical stress. A packing has its own weight. So without applying additional vertical stress, in a confined condition, the radial stress along the bead column generated by the gravity of the packing itself may look like Line A in FIG. 3. The radial stress is basically zero at the top and changes linearly with the height of the column. If the weight of the packing is ignored and the packing is applied as a vertical stress on the top, the radial stress along the bead column may look like Line B in FIG. 3, where the radial stress is uniform along the height of the column. If a vertical stress is applied at the top and the weight of the column is not ignored, the radial stress may look like Line C in FIG. 3. Line C, which is the sum of Line A and B, indicates that the radial stress even at the top of the packing can be substantial. Apparently, generating substantial radial stress close to the top of the bead column requires a substantial vertical stress applied to the bead packing. The addition of this vertical stress is optional. Furthermore, applying more vertical stress on the column can generate a larger radial stress.

When a column of bead like materials then is placed in or around a conduit to cover its active zone, applying an axial stress to the column can provide additional radial support to the conduit for the entire active zone including the area close to the top of the zone.

The S_r and S_v here are all effective stresses, which are the bead-bead contact stress. However, inside a conduit loaded with bead like materials, there should be fluid present. So both an effective stress and fluid pressure may act on the surface of the conduit to support the conduit though the fluid pressure alone may not be enough to support the conduit by itself.

So in one exemplary embodiment of the method, a packing of bead like materials is first installed into an active zone of a conduit, then a stress in the radial or axial direction of the packing is applied to the packing in order to generate a substantial radial stress along the entire active zone of the conduit to provide substantial radial support for the entire active zone of the conduit including the area close to the top of the active zone.

The radial stress needed can be generated in other ways. In general, the following are some exemplary embodiments.

In one embodiment, the radial stress is applied by the following:

• • a. Install one or more of a first device in or around a conduit to cover the active zone such that the first device can apply radial stress to the conduit.
  • b. Install one or more of a second device that can apply force or stress acting onto the first device so that the first device can generate radial stress to support the conduit.
  • c. Let the second device apply the force or stress to the first device to generate a radial force or stress the conduit even at the top of the active zone.

Furthermore, in one embodiment, the radial stress is applied by the following:

• • a. Install one or more of a first device in a conduit to cover the active zone that can convert a force or stress applied in the axial direction of the conduit onto the first device into a radial force or stress supporting the conduit.
  • b. Install one or more of a second device that can generate a force or stress in the axial direction of the conduit acting onto the first device.
  • c. Let the second device generate the force or stress in the axial direction onto the first device to generate a substantial radial force or stress supporting the conduit including at the zone top.

The first device is preferred to have the capability of converting an axial stress into a radial stress. The first device also is preferred to have the capability of allowing fluid to come through. The first device is preferred to be able to conform to a wellbore wall even if the wall is not smooth. The first device is preferred to substantially transfer radial stress generated within the first device to the wellbore wall. A packing of bead like materials generally is highly permeable to fluid such as hydrocarbon or water and can convert an axial stress into a radial stress in a conduit. So in one embodiment, the first device is a packing of bead like materials. A bead like material has its weight. When a column of bead like materials is long enough in the vertical direction, the vertical force at the bottom of the column generated by the weight or gravity of the bead column can be very large. So in one embodiment, the second device is also a packing of bead like materials.

If the first device is installed away from the bottom of a subterranean wellbore, a packer or cement plug may have to be installed first to support the first device. When the first device is installed right above the bottom of a wellbore, the bottom of the wellbore can provide the support needed.

The first or second device can be installed into the annulus of an inner conduit placed into the outer conduit to cover the active zone. A conduit can be a wellbore, casing or tubing.

The following, taking examples of different damage scenarios, is to demonstrate the method in details.

1. Sand Control for an Injector or a Producer

Due to the weight of all overburden formations, a subterranean sandstone formation producing hydrocarbon is under stresses. Stress is force acting on a unit area. In general, for a uniform subterranean formation, there are three far-field principal stresses at a subterranean location: the Overburden Stress, the Maximum Horizontal Stress, and the Minimum Horizontal Stress, where the Maximum Horizontal Stress may be equal to the Minimum Horizontal Stress. After a wellbore is created, the far-field principal stresses are redistributed around the wellbore. A stress concentration is naturally created around the wellbore. As in FIG. 4, at a point near a wellbore of a vertical well, after stress redistribution, the three local principal stresses now are: the vertical stresses, S_v, the tangential stress, S_t, and the radial stress, S_r. The magnitudes of these local principal stresses are related to those far-field principal stresses. The vertical stress may be several tens of thousands of psi or pounds per square inch. In general, it equals to the Overburden Stress related to the weight of the formations above the point. The tangential stress, S_t, is a stress around the wellbore in the tangential direction. When wellbore pressure is low and little support can be provided to the wellbore, the tangential stress, S_t, naturally increase. This increased tangential stress then may crush the rock around the wellbore when rock is weak or unconsolidated, collapsing the wellbore. A wellbore normally contains some fluid and the fluid pressure may create some radial stress pushing outwardly helping to support the wellbore against the collapsing effect or to stabilize the wellbore. However, for a preferred high production rate, the wellbore pressure is normally intended to be maintained low to increase the drawdown or the pressure differential between the reservoir and the wellbore driving the hydrocarbon to the wellbore from the reservoir. Furthermore, the pressure differential within a short distance such as across a sand grain is normally very small. So the support from the internal wellbore pressure is normally low and limited. During hydrocarbon production, the hydrocarbon flow creates a high stress dragging the rock toward the wellbore, further offsetting the effect from the wellbore pressure stabilizing the wellbore.

Without enough support to a wellbore, the formation rock such as sandstone or chalk around the wellbore can easily fail. This failure causes the sand grains and chalk particles coming off the rock to flow with the hydrocarbon into the wellbore. Without a proper control, especially when these sandstone formations are weak, a large quantity of formation sand may be produced with the flow of the hydrocarbon. In severe conditions, the stress may even crush the sand grains into smaller particles that may easily pass through the gravel packing and the screens that are designed to screen out the sand. With conventional sand control methods, many hydrocarbon wells still produce some sand from sandstone formations. With further sand production, the formation around the wellbore is then loosened or less supported. Over time, this will form an enlarged wellbore or generate voids near the wellbore, worsening the problem. After voids have formed in an unconsolidated formation, much of the sand may be fluidized and flow freely with the hydrocarbon to the wellbore. To minimize or delay sand production, even with conventional sand control methods such as gravel packing, the production rate is normally limited to a relatively low level so that the pressure support from the wellbore outwardly is not too small and the fluid dragging force from the hydrocarbon flow into the well is not too large. These problems have been discussed previously in relation to FIG. 1.

Furthermore, even with the gravel packing 7 and its weight is considered, the support to the wellbore or the radial stress generated from the packing will be very little close to the top of the sandstone formation as shown in the coordinate system in FIG. 1. Due to the lack of support to the wellbore, especially at or near the top of the sandstone formation where the radial stress from the gravel packing is basically zero, the formation sand may be fluidized during production at the near wellbore region. After some sand is produced and voids generated, the stress is further reduced and the sand production may become much more severe over time.

It has been understood that the root cause of sand production is that the sand around a wellbore is loose with little radial stress pushing outwardly. The pressure differential across a sand grain contributing to sand stability is very little, needless to say that this is very limited by the preferred low wellbore pressure. However, applying a mechanical stress outwardly in the radial direction from the wellbore on the formation to substantially increase the radial stress can consolidate the sand to prevent or minimize sand production. This method is based on the principle of grain-like material consolidation with confining stresses. Under confining stresses, unconsolidated sand or loose sand then can be consolidated into a solid rock-like material. Sand grains under the increased stress can be held in place by the stress. The bead like materials can easily allow the hydrocarbon to flow through and provide the radial stress to the wellbore. This can be beneficial for either an injector or producer.

The invented method for sand control can be called a mechanical consolidation method. In this method, a packing of bead like materials is placed into the wellbore where the sand may be produced to cover the entire active zone (sand producing zone). Then force is applied to the packing to cause radial expansion tendency against the wellbore wall to generate radial stress to support the wellbore. The force can be applied from all directions to the packing including from inside the packing. Then, optionally, on top of the packing, a substantial axial stress is applied to the packing in order to generate a substantial radial stress to support or confine the wellbore formation. Alternatively, a substantial force can be applied to the packing by the gravity of the packing itself. This can be done by increasing the density of the bead like materials. Also alternatively, a substantial force can be applied to the packing by a swelling force from the packing itself.

The conventional method of gravel pack utilizes gravel packing to filter the sand out in place. Gravel is just coarse sand with a density of approximately 2.65 gram/cm³. In consideration of fluid buoyancy, the packing can have very little gravity effect. When heavier materials are used, the radial stress generated can be much higher. For example, steel beads have a density of approximately 7.9 gram/cm³ and tungsten carbide beads has a density of approximately 15.6 gram/cm³. In one embodiment, the bead like materials have a density higher than gravel used in the conventional gravel packing. In one embodiment, the bead like materials have a density higher than 6 gram/cm³. In one embodiment, the bead like materials are made of metal materials. In one embodiment, the bead like materials are made of steel, carbon steel, stainless steel, copper, tungsten carbide.

Some or all of the bead like materials can have a potential of swelling when activated. Swelling can be activated and sustained by an activating fluid. The packing should be constrained from the top and bottom of the packing with such as inflatable well packers or other mechanical stoppers (hereinafter “well packers”). Swelling of the bead like materials in the constrained stoppers in the annulus can apply a radial stress to the wellbore forming the annulus around the packing. So in one embodiment, some or all the bead like materials forming the packing are swellable. When the packing is long enough, the friction and weight of the upper packing can serve as a stopper to constrain the swelling of the lower packing. Normally, a packing sits on the bottom of a wellbore and is naturally constrained from the bottom.

The material for the swellable bead like materials includes but not limited to the following exemplary elastomers that swell when exposed to an activating fluid, such as hydrocarbons: rubber, crumb rubber, crumb tire rubber, ethylene propylene rubber (EPM and EPDM), ethylene-propylene-diene terpolymer rubber (EPT), butyl rubber, brominated butyl rubber, chlorinated butyl rubber, chlorinated polyethylene, neoprene rubber, styrenen butadiene copolymer rubber (SBR), sulphonateed polyethylene, ethylene acrylate rubber, epichlorohydrin ethylene oxide copolymer, silicone rubber and fluorsilicone rubber.

The material for the swellable bead like materials also includes but not limited to the following exemplary elastomers that swell when exposed to an activating fluid, such as water: starch-polyacrylate acid graft copolymer, polyvinyl alcohol cyclic acid anhydride graft copolymer, isobutylene maleic anhydride, acrylic acid type polymers, vinylacetate-acrylate copolymer, polyethylene oxide polymers, carboxymethyl cellulose type polymers, starch-poly-acrylonitrile graft copolymers and the like and highly swelling clay minerals such as sodimum bentonite.

These swellable bead like materials can be carried in a non-activating fluid to the location then its activating fluid is allowed to flow to the materials to initiate swelling. The activating fluid can be pumped from the surface. The activating fluid can be a formation fluid such as oil, gas or water flowing from the formation into the wellbore to activate the swelling. The activating fluid can be a solvent.

The size of the majority of these swellable bead like materials can be from 200 micron to 1 inch. But the preferred size is from 400 micron to 2000 micron. It is preferred to have 10 to 75 percent of the bead like packing materials in a packing are swellable. Other non-swelling bead like packing materials can be one or more of ceramics, concrete, plastics, engineering plastics, resin, tungsten carbide, alloy, aluminum, stainless steel, steel, calcium carbonate, glass, sand, gravel, hydraulic fracturing proppants.

Other than radial stress is generated from inside the packing, it can be generated from outside the packing such as from the top or the bottom of the packing.

In one embodiment, a bead like material is placed into a wellbore for sand control to form a packing cover the active zone of the wellbore. Furthermore, optionally, in another embodiment, then a substantial axial stress to the packing is applied.

Furthermore, during the life time of a reservoir, some fines may be produced anyway and this can reduce the stress initially applied to the wellbore. In a severe condition, a void may be generated. It is therefore important for the mechanical consolidation to continuously provide substantial consolidation to compensate the formation stress reduction near the wellbore and to prevent the formation of a void. The bead like materials (under radial stress) can move about to where the stress is low when such as a low stress area or a void is just generated. Then the same stress can continue to act on the formation for consolidation even when some fines are produced.

However, a conventional gravel packing method is not intended to apply stress to wellbore for sand consolidation though it is still typical that the active zone is covered by gravel. No substantial axial stress, however is applied to the gravel pack to generate the needed substantial radial stress, especially at close to the top of the active zone. A void generally is then likely to generate at the top section of the formation and extend to behind the casing. To make it worse, the frac-and-pack method tends to worsen this stress condition by inducing additional tangential stress to the wellbore when the frac-and-pack method is intended to create and prop fractures. This additional tangential stress requires additional radial stress to offset the wellbore collapsing effect from the induced additional tangential stress.

In one of the disclosed embodiments of this invention, substantial axial stress is applied to the packing of the bead like material. In another embodiment, the axial stress applied to the packing is more than 50 psi. Furthermore, in another embodiment, the axial stress applied to the packing is more than 250 psi. In another embodiment, the axial stress applied to the packing is more than 500 psi. In another embodiment, the axial stress applied to the packing is more than 1000 psi.

In one of the disclosed embodiments of this invention, substantial radial stress is applied to the wellbore formation for the entire active zone. In another embodiment, the radial stress applied to the wellbore is more than 50 psi. Furthermore, in another embodiment, the radial stress at the zone top is over 100 psi. In another embodiment, the radial stress at the zone is over 250 psi. In another embodiment, the radial stress at the zone top is over 500 psi. A higher radial stress can create more consolidating effect and enable the formation sands to resist the pressure change during production. For a well production limited by sand production, increasing radial stress can enable hydrocarbon production at a much lower draw down wellbore pressure for a much higher production rate. The higher the radial stress is, the higher the production rate can be without sand production. In general the radial stress is preferred to be close to the horizontal stress of the formation before the wellbore is drilled. In one embodiment, the radial stress applied to the wellbore formation is within 60% of the horizontal principal stress at the zone top location. In another embodiment, the radial stress applied to the wellbore formation is within 35% of the horizontal principal stress at the zone top location. In another embodiment, the radial stress applied to the wellbore formation is within 5% of the horizontal principal stress at the zone top location.

FIG. 5 illustrates a top view of a vertical wellbore 51 in a sandstone formation 52. Illustrated is placing bead like materials into the active zone of the wellbore 51 to form a bead packing column 53. The bead like materials are confined by the wellbore 51 and applying force to compress the column vertically can generate a radial stress 54 (normal to the axial direction of the well bore) to consolidate the sandstone formation in the active zone.

As one of the disclosed embodiments of this invention, a first device is a first packing of one or more bead like materials.

The first device can contain one or more of a bow like bars that can bend more and push radially against a conduit such as a wellbore formation to apply a radial stress when the bars are compressed in the axial direction of the conduit.

As one of the disclosed embodiments of this invention, the first device is a bow type spring. As shown in FIG. 6, a bow type spring has multiple bows 61 mounted on at least two bow rings 62. The bows 61 are parallel to the axis of wellbore 63 and distributed circumferentially around the wellbore 63. The bow type spring has a diameter smaller than the wellbore 63 without expansion, i.e., in a relaxed state. This can ensure it can be run into the wellbore. Such a bow type spring is ready to be pushed outwardly for expansion when force is applied from the top of the bow type spring. It will be appreciated that the lower bow ring is in a fixed position in the conduit and the upper bow ring can be compressed proximate to the lower bow ring.

However, it is necessary that the bow type spring can continue to apply stress even when the wellbore is enlarged. After being expanded, the diameter of the bow type spring can be substantially larger than the diameter of the wellbore. This can continue to apply stress to the wellbore or formation even when much sand has been produced causing the wellbore severely enlarged. There can be multiple of bow type springs installed for a sandstone formation where sand control is required. In one of the embodiments, the bow type spring is wrapped with screens that can be expanded. In another embodiment, the screens are corrugated. Together with the screens that can be expanded, after the bow type spring being placed in the sandstone wellbore section, force is to be applied to the bow rings to expand the bows outwardly to push against the formation for sand control.

Alternatively, the first device can be one or more of inflatable devices. These may include close-ended rubber tubes. These may also include inflatable rubber tubes to be pressurized from both ends. This device is intended to be long and inflatable with its inflating fluid pressure. After being installed in the wellbore of an active zone, the first device can be connected to a second device that can provide fluid pressure to inflate the first device. The second device can be fluid in the annulus or pipe. The second device may further include a pump to increase the pressure. A pump can be used to pump fluid into the first device to apply radial stress to the formation. Alternatively, the pressure can come from the hydrostatic head of the fluid. In other words, the device can be inflated by applying the weight of the fluid above the device or the hydrostatic pressure. The weight of the fluid can be adjusted by the fluid column height or the density to change its hydrostatic head. In order to inflate the device, the pressure applied to the device must be higher than the pressure surrounding the device. When inflating the first device that touches the wellbore wall directly or indirectly through solid materials such as a bead packing, radial stress then starts to generate. A packer may be needed to separate the pressure for the inflatable device from the formation pressure of the active zone so that the pressure differential inflating the inflatable device can be maintained. Preferably the packer is an annulus packer. The packer is preferred to be installed at the top of the inflatable device. The packer may make the annulus fluid and the fluid inside the inflatable device in the same pressure system when pressure is applied to the inflatable device from the annulus. Alternatively, a one-way check valve can be installed to the inflatable device to prevent the fluid pumped into the device from flowing back so that the inflation and generated radial stress can be maintained even when the annulus pressure is decreased afterwards.

Furthermore, multiple first or second devices can be installed. In one exemplary embodiment, a bow type spring is installed inside the bead packing covering the active zone. In another exemplary embodiment, an inflatable device is installed inside the bead packing covering the active zone. In another embodiment, the second device(s) is installed to apply stress to one or more of the first devices. In another embodiment, pump pressure, hydrostatic pressure and gravity of beads all are applied to multiple first devices at the same time in the same wellbore.

FIGS. 10 and 11 illustrate an exemplary embodiment of the current invention. In an openhole wellbore 107 extended by casing 101 to surface penetrating through shale formation 102 and into sandstone formation 110, a bead packing 108 is installed within the sandstone formation top around tubing 105 in the wellbore for hydrocarbon flow 109. The wellbore with the bead packing can be vertical, deviated or horizontal. An inflatable rubber tube 111 is installed in the packing 108. An annulus packer 106 is installed at the top of the packing 108 to isolate the annulus of the tubing and of the inflatable tube but allow the annular fluid 104 above the packer 106 to flow into the inflatable rubber tube 111. Hydrocarbon 109 produced from the sandstone formation 110 flows through the tubing 105 up to the surface. Annulus fluid 104 weight or hydrostatic head can then be applied to the tube 111 to inflate it to generate radial stress acting to the wall of the wellbore 107 through the bead packing 108. Furthermore, pump pressure can be applied to the annulus fluid 104 to further inflate the tube for additional radial stress. Alternatively, the hydrostatic head can be increased by pumping heavier fluid into the annulus to displace the lighter fluid in the annulus or raising the fluid level in the annulus.

Preferrably an inflatable tube is installed on the lower side of a deviated or horizontal wellbore to not directly contact the wellbore wall.

Normally during hydrocarbon production, to maintain a drawdown for a production rate, the wellbore pressure has to be reduced over time, causing a larger sanding tendency. To make it worse, due to the decreasing of the formation pressure, the formation effective stress is increasing, so the wellbore stress is even more unbalanced or unsupported, sanding is getting easier. During a normal production process, the annulus pressure is substantially constant. The pressure differential between in the annulus and in the wellbore becomes larger with production. So an inflatable tube in a bead packing can naturally be inflated to apply more radial stress to the packing and the wellbore when the wellbore needs more of such support.

So optionally the inflatable tube is inflated naturally during production. Also optionally the inflatable tube is not inflated at the beginning of production. Also optionally the inflatable tube is only partially inflated at the beginning of the production. Optionally, more inflation is done later either by increasing the pressure inside the annulus or by decreasing the pressure at the hydrocarbon bearing formation.

The method can be used to support perforations of the cased hole for sand control. A perforation hole can be viewed as a wellbore conduit. After packing the perforation holes with bead like materials, applying more stress to the formed packing in the holes can provide additional support to the holes to prevent its failure or sanding.

An inflatable device in a packing of bead like materials can be formed in place. In this case, a conduit to conduct a fluid of a sealing capacity is installed in the packing first. The sealing fluid is designed to form a sealing layer on the packing surface quickly. Then the sealing fluid is pumped into the conduit to form a sealing layer on the packing surface along the conduit and an inflatable tube then is formed inside the packing along the conduit. Pumping more fluid into the formed tube along the conduit can then squeeze the packing tighter by inflating the tube. Furthermore, the sealing fluid can be used to fix a leaky tube inside the packing with its sealing capacity.

The fluid used to inflate an inflatable tube can be any fluid. The fluid may be water based, oil based, synthetic oil based. The fluid can contain solids. An inflatable tube can be inflated with settable fluid such as cement slurry.

The inflatable device is preferred to be in a non-inflated condition which occupies little volume when it is being run into the active zone so that it can apply more stress when it is inflated. It is also preferred that the device can be inflated to occupy a large space to maximize its stress applying capacity. This large space can be as big as the wellbore volume of the active zone.

It may be advantageous to have a screen installed between the formation and the first device in the active zone when the conduit is an open hole wellbore. This can better let the first device apply stress to the formation and screen out the sand. The screen may have to be strong enough in order to apply a high stress. In one embodiment, there is a screen installed between the formation and the first device. The screen has a mesh size from API 200 to 5 mesh. The screen has multiple layers of the same or different meshes.

Bead like materials can be placed between the screen and the formation to adapt to the irregularity of a wellbore. In one embodiment, bead like materials are placed between the screen and the formation.

A conduit such as production tubing can be extended into the first device so that the hydrocarbon needs to flow only a short distance through the first device into the tubing. This is needed when the flow resistance in the packing is too high and placing tubing into the first device can substantially reduce the flow resistance. In one embodiment, a conduit is extended into the first device.

The axial force or stress applied to the first device from the second device is from one or more of the following:

• • a. gravity or weight.
  • b. pressure.
  • c. elastic energy.

Gravity or the weight of the second device can be applied to the first device. In order to apply enough radial stress, the weight of a second device must be high enough. It will be appreciated that the increased weight pushes down on the upper bow ring, causing circumferential expansion of the bow springs.

The second device that can apply weight to the first device includes the weight of solids above the first device. The weight of solids include a column of a packing of beads like materials, tubing, casing or any objects placed on top of the first device. Some heavy objects can be attached to tubing or casing placed on top of the first device. The objects can apply weight to the first device individually or together.

A high column of a packing of beads like materials can have a high weight. As one of the disclosed embodiments of this invention, the second device is a second packing of one or more bead like materials.

Over time of production, some sand may be produced and the bead like materials then are pushed further away from the wellbore in order to maintain the radial stress. With this process on going for a long time, the bead like materials may run out. Therefore it is advantageous to have the same bead like materials for the first and second packing so that there will be more bead like materials from the second packing when the bead like materials from the first packing run out. In another embodiment, the first packing and the second packing are the same.

The bead like materials can be of any shape such as round, oval, cubic, prism, column, sand, etc. as long as they can pack a permeable packing. Preferably they are round so that they can easily roll to the position where the stress is relatively low. In one embodiment, the packing is formed by a plurality of the bead like materials of the shape of one or more of round, oval, cubic, prism, column, sand. The bead like materials can also be of holes to enhance the permeability of the packing. In another embodiment, the bead like materials have one or more holes. In a preferred embodiment, one of the bead like materials is of the shape of a short tube.

The bead like materials are sand, gravel, or made of ceramic, metal or plastic materials. It is preferred that some of the materials are rigid so that the pores between the materials will not close under stress.

The weight of the packing, especially the second packing, is used to apply the radial stress. It is therefore advantageous to have the packing of a high density materials such as steel. In one embodiment, the bead like materials are made of steel. In another embodiment, the bead like materials are made of stainless steel.

In one embodiment, the second device is casing or tubing set on top of the first device. The casing or tubing, positioned to utilize gravity, can have a thicker wall than otherwise required for normal use. In one embodiment, the casing or tubing is substantially thicker and heavier when applying weight to the first device is considered. Furthermore, in another embodiment, the casing or tubing has heavy objects attached to provide weight to the first device.

The weight can also be applied by fluid on top of the first device. In this case, a movable seal is required between the first and second device so that the fluid will not leak into the active zone and lose its function. For this purpose, the fluid may be weighted to a high density to provide the needed weight with a certain fluid column height.

When such a seal exists, fluid pressure can be applied to the movable seal to provide the needed force.

Fluid column weight and pressure can first be applied to the movable seal and then to the first device. In another embodiment, the fluid column weight and pressure can be applied simultaneously to the moveable seal and first device.

The seal or the pressure isolation can be achieved by sealing particulates in fluid. The pressure isolation mechanism is a rubber like a diaphragm. The pressure isolation mechanism is a piston like device inside casing or tubing.

The force required to act onto the first device includes weight of solids, weight of fluid, pressure and elastic energy individually or together.

Movable pressure isolation can be created by sealing particles or a film or by liners such as a rubber film or liner or both on top of the first device. The space above the pressure isolation can have a confined space so that fluid pressure can be increased in the space. Then pressure equivalent to the required gravity or weight is applied from the fluid to the movable pressure isolation further to the first device packing directly or indirectly. The pressure can be applied by one of more of the following: (1) pumping more fluid into the space above the movable pressure isolation and/or (2) heating the fluid above the movable pressure isolation to cause expansion.

A device can provide elastic energy is a spring. The second device is a spring. The elastic energy of the spring comes from shortening the spring or the compression. This shortening can be done by applying weight of casing or tubing on the spring. It can also be done by a threaded plug that can travel down by rotation of the plug to shorten the spring.

In one embodiment, the spring is of a spiral shape around a casing or tubing. Steel casing or tubing is also elastic. In another embodiment, the spring is casing or tubing. Then the spring is shortened or compressed by weight of the casing or tubing and is secured to the wall of the wellbore on its uphole far end away from the first device. The first device then is loaded with the required stress for sand control by the spring.

Some fines may be produced or migrate during production or water injection even with a high radial stress applied. With this production or migration, the diameter of the wellbore may be substantially enlarged if the same or similar radial stress is still applied to the wellbore. If the first device cannot apply the radial stress when the wellbore is substantially enlarged, the radial stress may decrease rapidly and the mechanical consolidation effect is basically gone. It is therefore important for the first device to be able to continuously apply the radial stress even when the wellbore is substantially enlarged. In one embodiment, the first device still can apply a radial stress even at the top of the active zone when the wellbore at this location has been enlarged by 5%. In another embodiment, the first device still can apply a radial stress at the top of the active zone when the wellbore at this location has been enlarged by 10%. In another embodiment, the first device still can apply a radial stress at the top of the active zone when the wellbore at this location has been enlarged by 50%.

When the first device is a packing of bead like materials, the bead like materials can be pushed by their gravity or the force from the second device to move or roll sideways to fill the enlarged wellbore or any voids that may be generated during the life time of the production or injection.

When the first device is a bow type spring, the bows can be designed to be able to greatly expand their reach even when the wellbore is severely enlarged.

The method can be applied in vertical, deviated and horizontal wells. However, the weight of solids or fluid of the second device cannot help unless the second device is installed in the non-horizontal section of the wellbore. The vertical length of the second device needed is defined based on the needed force acting on to the first device.

The sandstone formation stress can be known by other means such as a mini-frac analysis and other well testing methods. A conventional sand production analysis can be modified to determine the best value of radial stress needed for the sand control. The quantity of the radial stress required to control sand production can be from 50 psi up to the far-field principal stress of the sandstone formation, either at the beginning or end of the hydrocarbon production. A radial stress more than the far-field horizontal principal stress may also be good as long as the stress is not so high as to crush the sand grains. Radial stress is preferred to be substantially equal to far-field principal stress of the sandstone formation requiring sand control.

Sand production is unwanted. Hydrocarbon production is wanted. In reality, hydrocarbon production is preferred to be as high as possible with zero sand production. However, a higher hydrocarbon production rate requires a lower wellbore pressure that tends to result in a tendency for larger sand production. Then when a radial stress is provided to the wellbore, the lowered wellbore pressure is compensated and support to the wellbore can be even larger than with the pressure only. The needed radial stress for a wellbore can be determined by the preferred maximum hydrocarbon production rate without sand production. A typical sand production analysis can be used to identify the typical radial stress for a target hydrocarbon production rate. Without considering other factors such as cost of applying the radial stress or the limitation of the casing capacity for increasing the axial stress with the bead like materials, the higher the radial stress is, the lower wellbore pressure can be for a higher the hydrocarbon production rate without causing sand production.

The vertical height of the second packing, H, can be determined by the required radial stress, S_r, to be generated acting on the wellbore. This can be done by determining the density, ρ, of the bead like materials of the second packing to be placed on the top of the first device and stress conversion ratio of the first device. The stress conversion ratio of the first device is the ratio of the radial stress generated to the stress in the wellbore direction applied to the first device. This ratio can be tested in a lab for a specific type of the first device. When the first device is a first packing of the bead like materials, the conversion ratio is defined by the Poisson's ratio, v, of the packing. The packing normally is in a fluid having a density of ρ_f generating buoyancy offsetting some of the gravity of the second packing. A packing efficiency, k, needs to be considered for the porosity of the packing. For example, for random packing of round shape beads, the porosity is about 37%. So k=1−37%=0.63. The vertical stress generate by the weight or gravity of the second packing S_vg=k(ρ−ρ_f)gH, where g is the gravitational acceleration. Once again, these are all effective stresses. When the friction at the wall is not considered, then the vertical height of the second packing H is calculated as follows.

H=S_r/{[v/(1−v)]k(ρ−ρ_f)g}.

If the wellbore is deviated from vertical, or friction is considered, the length of the weight packing generally needs to be longer to give enough vertical height of H for the required force or stress.

Bead like materials will have some friction on the wall of either casing, tubing or a wellbore. This friction will reduce the gravity effect to the packing. In order to apply more weight to the packing, it is preferred that lubricants are applied when the packing is installed. Furthermore, the bead like materials are preferred to be round and smooth on the bead surface to further reduce the friction.

In order to increase the packing efficiency to reduce the vertical height H for a certain required radial stress, the bead like materials can be a mixture of various sizes. The size and the portion of each size component can be defined by minimizing its packing porosity. These can also be defined by the so called ideal packing theory.

Another way to reduce the vertical height is to increase the density of the bead like materials.

Friction may need to be considered. Friction can reduce the vertical stress effect when bead like materials are added in. Friction can increase the vertical stress effect when the wellbore pressure is reduced and the wellbore tends to shrink. In order to consider friction, a 10% more of the vertical height of H may be added to the previously calculated H only based on the needed radial stress.

In one embodiment, H is at least 300 ft or feet. In another embodiment, S_r is at least 50 psi (effective stress). In another embodiment, S_r is the radial stress at the top of the active zone. In another embodiment, S_r is the average of the radial stress of the active zone. In another embodiment, S_r is the minimum radial stress of the active zone.

The following are some of the preferred embodiments of the bead like materials.

The bead like materials comprise shapes like a ball, a bearing ball, a cylinder, sand, gravel, a cube, a short tube, a drum, a prism, an ellipsoidal shape or a half or a fragment of these above or any small solid objects or a mixture of the above.

The bead like materials prefer to be made of one or more materials of the following: ceramics, concrete, rubber, plastics, engineering plastics, resin, tungsten carbide, alloy, aluminum, stainless steel, steel, calcium carbonate, glass, sand, gravel, hydraulic fracturing proppants to better transfer stress.

In order to apply more radial stress with a shorter height H, it is preferred to have high density bead like materials. In one embodiment, it is preferred that the bead like materials are made of materials of a high density including but not limited to barite, hematite, iron oxide, ilmenite, metal, alloy and combinations thereof. The gravel is just coarse sand with a density of approximately 2.65 gram/cm³. When heavier materials are used, the radial stress generated can be much higher. In another embodiment, the bead like materials have a density higher than gravel used in the conventional gravel packing. The bead like materials prefer to have a ratio of the largest dimension to the smallest dimension less than 4:1, preferably 1:1.

The bead like materials prefer to have a true density of 0.8˜18 gram/cm³.

The bead like materials prefer to be of a higher density so that the gravity force is higher for the same column height or for the same gravity force the required weight packing column is shorter.

The bead like materials can further be porous or have one or more holes so that hydrocarbon can flow through.

The bead like materials are sand or gravel.

The bead like materials are stainless steel ball bearings.

The size of the bead like materials is from 0.01 to 50 mm or millimeter. It is favorable to have smaller bead like materials in the active zone and favorable size is approximately 6 times the sand grain size. Though having a much smaller size, sand grains can form arches on the bead like materials and the sand arches can prevent sand grains to further flow into the packing of the bead like materials. Formed sand arches at the interface of the bead like materials and the sandstone formation can be substantially stabilized when the radial stress is high. With a high stability, the arches may be stable during rate changes or under a high rate of production or injection. Due to the mechanical consolidation from the radial stress, the bead like materials can allow a much lower wellbore pressure without producing much sand. This is substantially different from a regular sand control with gravels where normally there is very little radial stress, especially at or close to the top of an active zone.

In a special scenario, a layer of smaller bead like materials can be placed in the active zone to block the sand grains and larger bead like materials can be placed behind the smaller bead like materials to block the smaller bead like materials. More bead like materials then can be placed on top of the larger bead like materials for the vertical stress needed. With this method, screen wrapped or slotted pipe to hold the smaller bead like materials is not needed. The smaller bead like materials can be placed into perforations to block the sand grains if perforated casing is present.

The bead like materials are mixed in a carrying fluid and pumped down hole to be placed in pace by the fluid.

The bead like materials are dumped into a wellbore to fall to place by gravity.

The bead like materials in the first packing and in the second packing are the same.

FIG. 7 demonstrates an exemplary embodiment of the method to control sand production. FIG. 8 is an A-A section of the wellbore in FIG. 7.

As shown in FIG. 7 and FIG. 8, a vertical wellbore 71 is drilled through a cap rock of shale formation 73 into an oil reservoir in the sandstone formation 72. Casing 74 is set and cemented at the interface of shale formation 73 and sandstone formation 72. Production tubing 75 is run into the active zone of the wellbore 71 in the sandstone formation 72. There are slots in the part of tubing 75 in the active zone and screens 79 are wrapped around the part with slots to cover the slots. A first packing 76 of a type of bead like materials is installed in the annulus of tubing in the sandstone formation 72. A second packing 77 of the same type of bead like materials is installed right above the first packing 76 in the annulus of the tubing in the shale formation 73 and the formation above. The second packing 77 is tall enough so that weight of the second packing 77 acting on the first packing 76 enables the first packing 76 to generate a radial stress high enough to mechanically consolidate the wellbore 71 in the active zone. An annular packer 78 is installed above the second packing 77 to isolate the tubing annulus above the second packing 77. Hydrocarbon flow 80 then goes from the sandstone formation 72 through the first packing 76, screens 79 and slots into tubing 75 then upwardly to surface.

When the first device is a packing of the bead like materials installed in the active zone, the second device is an expandable tube-shape screen placed in the center of the packing. An expandable screen is of a tubular shape with multiple layers of screens that are designed not to let the bead like materials to pass through and can be expanded into a larger diameter. One common form of the screens is corrugated along the wellbore direction. Multiple layers of screens can be used to provide enough strength. Then the screen is expanded with a large diameter cone shape tool running through the center of the tube-shape screen to expand the screen toward the wellbore to apply force to the packing and further the formation. The screen can also be expanded by hydraulic pressure when an impermeable liner is inside the tube-shape screen.

In one embodiment, first place the second device which is an expandable tube-shape screen in the center of the wellbore of the active zone. Then in the annulus between the screen and the wellbore, install the first device which is a packing of the bead like materials covering the entire active. Then expand the expandable tube-shape screen against the packing and wellbore to generate a substantial radial stress. The minimum radial stress generated along the wellbore in the active zone is at least 250 psi.

In order to favor production, the wellbore size in the active zone can be enlarged as much as needed before installing the first device.

In order to favor production, some sand can be produced intentionally by applying less stress to the first device to generate a large wellbore size before ramping up the stress applied to the first device.

This invented method is suitable for mechanically consolidating a wellbore in an injection well. In an injection well, the flow of hydrocarbon is replaced by water or brine and the flow direction is reversed or from the surface to the formation.

2. Preventing Casing or Tubing Buckling or Collapse

Potential casing or tubing buckling or collapse can be identified with review and analysis of a casing design of a well and the hydrocarbon production plan. The industry has been using computer software programs to help to identify the potential problems. In one embodiment, the potential active zone of casing or tubing collapse is identified first.

Casing or tubing is designed to withstand a high amount of pressure but not a high point load since it is hollow. Casing or tubing can resist more load if additional support is available. During the process of subsidence or salt encroachment, casing or tubing may experience an ever growing point loading on a location of the casing or tubing. This point loading can collapse casing or tubing at a much lower load that what the casing or tubing can normally withstand if the load were uniformly distributed in all directions. Providing direct support to casing or tubing at the point loading spot may prevent the failure of the casing or tubing. Furthermore, if support is provided to a section of casing or tubing from all direction circumferentially, the casing or tubing may be able to sustain much great pressure without failure. Similarly, if support is provided to a section of casing or tubing from all direction circumferentially, the casing or tubing may resist buckling from such as subsidence of the formation.

Due to its little compressibility, a packing of bead like materials inside a conduit can provide the needed support for casing or tubing. Furthermore, bead like materials in a packing normally can move about a little to distribute a point load into a much larger area rather than focusing at a point. Bead like materials if placed around or inside casing or tubing in a wellbore to form a packing where the point loading may occur can distribute the point loading to around the casing or tubing and form a more uniform load around the casing or tubing. Similarly, if the packing formed in the annulus of casing or tubing, it can support the casing or tubing for much higher pressure without burst. If the packing formed inside casing, it can support the casing to prevent the casing from being collapse from outside by pressure or a point loading. Furthermore, when the packing formed either inside casing or tubing or outside the casing or tubing in its annulus, it can further provide a radial support to help to prevent the buckling of the casing or tubing.

If the point loading is from outside casing or tubing, the packing can be installed around the casing or tubing where the point loading may occur. This can distribute the point loading in a larger area. Alternatively, the packing can be installed inside the casing or tubing where the point loading may occur to support the casing or tubing to prevent the collapse of the casing or tubing.

For preventing casing or tubing burst, the packing is normally installed outside the casing or tubing.

At the bottom of the packing, a packer, cement plug or similar can be installed before installing the packing. After the packing has been installed, another packer, cement plug or similar can be installed above the packing to secure the packing in place.

Alternatively, the packing can be secured by the weight of the packing and/or the friction to the packing upward movement. The packing height needs to be large enough so that the magnitude of the anticipated point loading will not move the packing upwardly.

In one embodiment, a packing of bead like materials is installed inside the annulus between casing and production tubing. In another embodiment, a packing of bead like materials is installed inside casing. In another embodiment, a packing of bead like materials is installed inside tubing. In another embodiment, a packing of bead like materials is installed a casing annulus where it is surrounded by a salt formation.

Subsidence may occur in the reservoir formation. In one embodiment, a packing of bead like materials is installed in the annulus of the casing to be protected in the active zone. In one embodiment, a packing of bead like materials is installed in the annulus of the tubing to be protected in the active zone. Sometimes, the protection can be extended into the zone above the active zone. In one embodiment, a packing of bead like materials is installed in the annulus of the casing to be protected in the active zone and extended substantially into a zone above the active zone. In one embodiment, a packing of bead like materials is installed in the annulus of the tubing to be protected in the active zone and extended substantially into a zone above the active zone. Optionally and furthermore, an axial stress is applied to the packing to increase its resistance with a higher radial stress to the point loading.

3. Closing or Preventing a Micro Annulus

A micro annulus can be identified by the wellhead casing pressure monitored throughout the production of hydrocarbon. When a micro annulus exists, the wellhead may show sustained casing pressure. Further review of the cementing of the well and cement bond logs can reveal where the micro annulus is formed. Review of the hydrocarbon plan can also show where in a wellbore a micro annulus may form later. In one embodiment, a micro annulus is identified first. In another embodiment, a potential micro annulus is identified first.

A packing of bead like materials inside casing, when it is heavy enough, can expand the casing. This expansion can offset the casing shrinkage due to the reduction of casing pressure for production after cement in the annulus of the casing has set.

In one embodiment, where a micro annulus may form around casing, place bead like materials into the casing to form a bead like material packing at a height such that the gravity of the bead like material packing creates enough expansion of the casing so that the casing cannot shrink to form the micro annulus even when the pressure inside casing is as low as practical for production. The covered casing interval length can be from 500 ft. to 50,000 ft. Production tubing can be placed in the packing for producing hydrocarbon.

Similarly in another embodiment, where a micro annulus has been created around a casing, place bead like materials into the casing to form a bead like material packing at a height such that the gravity of the bead like material packing creates enough expansion of the casing so that the casing micro annulus is closed.

It is not necessary to let the bead like material packing cover the entire micro annulus zone. A packing length is long enough as long as the zonal isolation objective is achieved. A typical covered zone is from 300 ft to 20,000 ft. In one embodiment, the covered zone is 500 ft.

The required gravity of the bead like material packing can be partially replaced by one or more of the following:

• • a. The required gravity or weight can be replaced partially by the weight of casing or tubing sitting on the top of the stress packing or the top of a section of the weight packing. The casing or tubing for applying the weight can have a thicker wall than otherwise required for normal use.
  • b. The required gravity or weight can be replaced partially by pressure. A wellbore is normally filled with fluid such as oil, gas or water. A low permeability layer can be created by movable pressure isolation by such as either sealing particles or a film or liner such as a rubber film or liner or both on top of the packing. Then pressure equivalent to the required gravity or weight is applied from the fluid to the movable pressure isolation further to the packing. The pressure can be applied by one of more of the following: (1) pumping more fluid into the wellbore; (2) heating the fluid to cause expansion; and (3) increasing the density of the wellbore fluid above the pressure isolation.
  • c. The required gravity or weight can be replaced partially by elastic force stored in such as a spring. The spring can be of a spiral shape around a casing or tubing. The spring can be the casing or tubing. Then the spring is shortened by weight of the casing or tubing and is secured to the wall of the wellbore on the uphole end of the spring away from the bead like material packing. The packing then is loaded with the required stress.

4. Preventing Fracture Closing

For enhancing hydrocarbon production from hydraulic fractures, preventing fracture closing due to production is important. In order to keep the fracture open, a first device can be installed in the wellbore with fractures and then a second device can be installed to apply stress to the first device so that the first device can apply a radial stress to the wellbore. When the radial stress is large enough, the fracture can be kept open.

FIG. 9 is a cross section of an active zone of a wellbore using a packing of bead-like materials installed in the active zone to prevent fractures from closing. In FIG. 9, hydrocarbon flow 95 goes toward the wellbore 92 either through hydrocarbon formation 91 or through hydraulic fracture 94. Hydrocarbon flows through the bead-like materials 96 into tubing 93 to be produced. With an axial stress applied to bead like materials, a radial stress is generated to prop the fracture open.

Claims

1. A method of providing support to a subterranean wellbore structure comprising

a) placing bead material into the wellbore structure;

b) extending the volume of bead material to a selected height within the wellbore structure;

c) swelling the size of one or more of beads comprising the bead material;

d) generating a radial force from the swelling of the size of the beads; and

e) supporting the wellbore structure with the radial force.

2. The method of claim 1 comprising swellable beads and swelling the size of one or more beads by exposing the swellable beads to an activating fluid.

3. The method of claim 2 comprising swelling the size of one or more beads wherein the swellable beads comprise at least one of the following: rubber, crumb rubber, crumb tire rubber, ethylene propylene rubber (EPM) and ethylene propylene diene monomer (EPDM), ethylene-propylene-diene terpolymer rubber (EPT), butyl rubber, brominated butyl rubber, chlorinated butyl rubber, chlorinated polyethylene, neoprene rubber, styrenen butadiene copolymer rubber (SBR), sulphonateed polyethylene, ethylene acrylate rubber, epichlorohydrin ethylene oxide copolymer, silicone rubber and fluorsilicone rubber.

4. The method of claim 1 comprising swelling the size of one or more beads by exposing the swellable beads to water or other polar fluid.

5. The method of claim 4 comprising swelling the size of one or more beads wherein the swellable beads comprise at least one of the following: starch-polyacrylate acid graft copolymer, polyvinyl alcohol cyclic acid anhydride graft copolymer, isobutylene maleic anhydride, acrylic acid type polymers, vinylacetate-acrylate copolymer, polyethylene oxide polymers, carboxymethyl cellulose type polymers, starch-poly-acrylonitrile graft copolymers and the like and highly swelling clay minerals such as sodium bentonite.

6. The method of claim 1 providing support to a wellbore structure comprising using the weight of the bead material to create radial stress on the wellbore structure.

7. The method of claim 1 providing support to a wellbore structure comprising

a) including within the wellbore structure one or more perforations in a wellbore casing; and

b) placing bead material within a wellbore casing.

8. The method of claim 1 providing support to a wellbore structure wherein

a) the wellbore structure containing a fractured geologic formation proximate to a fractured wellbore; and

b) placing bead material within at least a portion of the fracture.

9. The method of claim 1 further comprising

a) introducing the bead material into the wellbore structure;

b) forming a bead packing;

c) allowing the bead packing to expand; and

d) allowing the expanding bead packing to press onto the wellbore structure wall.

10. The method for providing support to a subterranean wellbore structure comprising introducing bead material into the wellbore structure, forming a bead packing, and pressing the bead packing onto the wellbore structure wall.

11. The method of claim 10 further comprising

a) placing an inflatable device in the bead packing;

b) inflating the inflatable device in the packing of the bead material; and

c) increasing the radial force pressing against the wellbore structure wall.

12. The method of claim 11 further comprising:

a) including swellable bead material in the bead material introduced into the wellbore structure;

b) activating the swellable bead material, swelling the bead material in the packing, and

c) creating radial stress on the wall of the wellbore structure.

13. A method of providing support to a wellbore structure comprising:

a) placing a inflatable device positioned in and extending along a portion of the axial length of the wellbore structure; and

b) inflating the inflatable device within or proximate to bead material.

14. The method of claim 13 further comprising

a) inserting an inflatable device along a portion of the axial length of the wellbore structure;

b) inserting the inflatable device within the bead material placed in the wellbore structure;

c) inflating the inflatable device;

15. A device for supporting a wellbore structure comprising a plurality of swellable bead material installed above the bottom of a wellbore or above one or more well packers.

16. The device of claim 15 further comprising a packing of bead material structured to be permeable to hydrocarbon, water or gas.

17. The device of claim 15 comprising bead material of stainless steel, steel, carbon steel, tungsten carbide.

18. The device of claim 15 further comprising bead material having a diameter of from 0.01 mm to 50 mm.

19. The device of claim 15 for applying stress to a wellbore comprising an inflatable device structured to apply stress to the bead material.

20. The device of claim 19 further comprising installing one or more of the inflatable devices proximate to or within a packing of bead material.

21. A device comprising one or more inflatable devices that extend along the longitudinal axis of the wellbore proximate to or within a packing of bead material.

22. The device of claim 21 further comprising one or more inflatable devices that are tubular shaped.

23. The device of claim 21 further comprising the inflatable device embedded within a volume of bead material wherein at least one of the beads is swellable.

24. The swellable bead material of claim 15 comprising at least one or more of the following: rubber, crumb rubber, crumb tire rubber, ethylene propylene rubber (EPM and EPDM), ethylene-propylene-diene terpolymer rubber (EPT), butyl rubber, brominated butyl rubber, chlorinated butyl rubber, chlorinated polyethylene, neoprene rubber, styrenen butadiene copolymer rubber (SBR), sulphonateed polyethylene, ethylene acrylate rubber, epichlorohydrin ethylene oxide copolymer, silicone rubber or fluorsilicone rubber.

25. The swellable bead material of claim 15 comprising one or more of the following: starch-polyacrylate acid graft copolymer, polyvinyl alcohol cyclic acid anhydride graft copolymer, isobutylene maleic anhydride, acrylic acid type polymers, vinylacetate-acrylate copolymer, polyethylene oxide polymers, carboxymethyl cellulose type polymers, starch-poly-acrylonitrile graft copolymers, sodium bentonite or highly swelling clay minerals.