+

WO2016003629A1 - Procédé de support d'un conduit souterrain - Google Patents

Procédé de support d'un conduit souterrain Download PDF

Info

Publication number
WO2016003629A1
WO2016003629A1 PCT/US2015/035493 US2015035493W WO2016003629A1 WO 2016003629 A1 WO2016003629 A1 WO 2016003629A1 US 2015035493 W US2015035493 W US 2015035493W WO 2016003629 A1 WO2016003629 A1 WO 2016003629A1
Authority
WO
WIPO (PCT)
Prior art keywords
wellbore
packing
bead material
stress
rubber
Prior art date
Application number
PCT/US2015/035493
Other languages
English (en)
Inventor
Wang Hong
Original Assignee
Gravity Sand Control Llc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Gravity Sand Control Llc. filed Critical Gravity Sand Control Llc.
Publication of WO2016003629A1 publication Critical patent/WO2016003629A1/fr

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B33/00—Sealing or packing boreholes or wells
    • E21B33/10—Sealing or packing boreholes or wells in the borehole
    • E21B33/12—Packers; Plugs
    • E21B33/1208—Packers; Plugs characterised by the construction of the sealing or packing means

Definitions

  • a subterranean wellbore, perforation hole, fracture, any tube, including casing, or tubing inside or connect to a wellbore or casing can be called a subterranean conduit or wellbore structure.
  • These wellbore structures are often under stress or pressure and, in some conditions, these wellbore structures are not strong enough to withstand the stress or pressure.
  • the wellbore structures may fail and generate other problems, including interruptions of hydrocarbon production.
  • This disclosure provides a method to provide a substantial stress, typically radial stress, to a wellbore structure high enough to support the structure to prevent its collapse or the collapse of a wellbore formation, 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 wellbore structure to best support the structure.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • [001 1 ] 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.
  • 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.
  • 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.
  • 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.
  • an active zone is the interval of the wellbore containing the fracture.
  • 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 form a packing to apply a stress to support the conduit.
  • swelling of the bead material or expansion within the packing is applied to eventually generate the needed radial stress.
  • Hydrocarbon production zones frequently occur in sandstone formations or other porous media.
  • 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.
  • 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.
  • a wellbore may comprise many conduits.
  • the wellbore itself may be considered a conduit.
  • Each conduit typically may be long and of a circular shape having at least an inner diameter.
  • a perforation hole or a fracture for flowing hydrocarbon can be considered a conduit.
  • 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.
  • 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.
  • the commonly used devices are screens and 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 US patent 2,171 ,884. A gravel packing forms a three-dimensional filtering mechanism and it is much harder to be plugged by the formation sand.
  • 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.
  • a wellbore for gravel packing is similar to a silo for grain.
  • the total weight of the initial gravel placed at the bottom of the wellbore will be borne by the bottom.
  • the volume of gravel extends up the side of the wellbore, some portion of the weight of the newly added gravel will be supported by the side wall of the wellbore.
  • the gravel extends higher up the sides of the wellbore.
  • a greater portion of the weight of the newly added gravel is carried by the side wall and a smaller portion of the weight is carried by the bottom of the wellbore.
  • a wellbore for hydrocarbon production is typically of a diameter of only several inches.
  • the effective height of gravel the weight of which defines the maximum weight carried by the side wall of the wellbore at a point, is approximately 5 ft or feet for a typical hydrocarbon production wellbore. Though there may be hundreds of feet of gravel in a packing above an arbitrary point along the wellbore sidewall, only 5 ft of the weight of the volume of gravel above the point may be applied in a radial direction to that point.
  • Gravel has an approximate density of only 2.65 gram/cm 3 . Gravel is typically placed in hydrocarbon fluid or water which also provides buoyancy to substantially offset the gravity effect from gravel.
  • 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 perforations 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.
  • the packing in the wellbore will be loose due to the "silo" effect. Due to the small size of the perforations to produce hydrocarbon, it is difficult to pack these perforations without generating "hot spots.” These hot spots are undesired and are potentials of sand production later. 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.
  • 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
  • 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.
  • 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.
  • 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
  • a wellbore 22 is drilled in a hydrocarbon formation 21 and production tubing 23 is placed in the wellbore 22.
  • Hydraulic fractures 24 are created to help to conduct the hydrocarbon flow 25.
  • the fractures tend to run vertically in the hydrocarbon formation 21 reaching an impermeable cap formation such as a shale formation.
  • the majority of hydrocarbon flow 25 may come through the fractures.
  • the fracture pressure is maintained and so is the fracture pressure, the production rate will be high.
  • the fracture pressure is too low, eventually, the fractures can close and the production rate can drop dramatically.
  • proppants are typically placed into the created fractures to provide conductivity of the fracture for flowing hydrocarbon. These proppants are typically loosely packed and may flow back with hydrocarbon. When this happens, the fracture also tends to close causing the drop of production rates.
  • This invention is to provide a method to solve all of these above problems to the conduits.
  • the method taught by this disclosure is to apply a substantial supporting stress at least to the active zone of a subterranean wellbore structure such as a wellbore formation or a casing, tubing or conduit within the wellbore formation, (hereinafter "wellbore structure") where they may otherwise be damaged or a micro annulus has formed.
  • the supporting stress is applied by first placing bead like materials
  • bead material into the conduit or its annulus to cover the active zone in order to form a packing of the bead material to provide a substantially uniform support to the wellbore structure.
  • the bead material can be of a high density material.
  • the bead material can conform to the wellbore wall. When additional stress is generated in the packing, it can be transmitted to the wellbore wall substantially uniformly.
  • the material shape and dimensions (structural elements) can fill voids or irregularities within the formation.
  • the bead material can be round to readily move against other similar bead material in response to stress.
  • Substantial force can then further be optionally applied to the packing to let the packing generate a substantial force acting on the wall of the wellbore structure to further support the entire active zone of the structure 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.
  • the rubber tubes are run through at least 50% of the bead packing in the axial direction.
  • Substantial radial stress then can be generated by inflating the inflatable device in the packing.
  • the tube can be run through the packing multiple times such as with loops.
  • the tube can be pressurized to inflate from both ends.
  • the substantial force applied to the packing can also be achieved by an elastic force coming from a spring, swelling or similar acting in the packing.
  • a subterranean wellbore, perforation hole, fracture, any tube, including casing, or tubing inside the wellbore or casing can be called a subterranean conduit or wellbore structure, (hereinafter "wellbore structure").
  • wellbore structure The surface of these structures can be called wellbore structure wall.
  • These structures are often under formation stress and, in some conditions, these wellbore structures are not strong enough to withstand the formation stress.
  • the wellbore structures may fail and generate other problems, including interruptions of hydrocarbon production.
  • This disclosure provides a method to provide a substantial supporting stress, typically radial stress, to a round shape wellbore structure high enough to support the wellbore structure, e.g., casing, tubing, conduit, etc., to prevent its collapse or the collapse of a wellbore structure.
  • a wellbore structure is a fracture with a flat fracture surface for producing hydrocarbon
  • the stress supporting the fracture is typically in the direction normal or perpendicular to the fracture surface.
  • a wellbore structure is a round shape structure such as a wellbore or similar
  • the stress supporting the wellbore is typically in the radial direction of the wellbore and normal or perpendicular to the wellbore wall.
  • the supporting stress 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 wellbore structure to best support the structure.
  • the supporting stress needed can be generated in many ways. In general, the following are some exemplary embodiments.
  • the supporting stress is applied by the following:
  • a. Install one or more of a first device in or around a conduit, casing or tubing of a
  • wellbore structure to cover the active zone such that the first device can apply radial stress to the wellbore structure.
  • the second device apply the force or stress to the first device to generate a radial force or stress the wellbore structure even at the top of the active zone.
  • the supporting stress is applied by the
  • a. Install one or more of a first device in a wellbore structure to cover the active zone that can convert a force or stress applied in the axial direction of the wellbore onto the first device into a radial force or stress supporting the wellbore structure, e.g., casing, conduit, etc.
  • the second device 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 wellbore structure 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 packer or cement plug may have to be installed first to support the first device.
  • 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, perforation hole, fracture, casing or tubing.
  • a packing of bead material generally is highly permeable to fluid such as
  • the first device is a packing of bead material.
  • a packing of bead material In order to apply the radial stress and provide the necessary permeability required for flowing hydrocarbon through, a packing of bead material to cover the active zone can be applied. Furthermore, in order to apply a substantial stress to the wellbore wall to support the wellbore from the packing, a mechanism to generate this stress within the packing can be applied. So in one exemplary embodiment of the method, a packing of bead material is first installed into a conduit to cover an active zone, then a stress in the packing is generated to apply to the conduit to provide substantial support for the entire active zone of the conduit.
  • the stress of a packing of bead material can be generated by the swelling of some of the bead material.
  • the stress of a packing of bead material can also be generated by expanding the packing radially.
  • the tangential stress, S t is a stress around the wellbore in the tangential direction.
  • S t When wellbore pressure is low and little support can be provided to the wellbore, the tangential stress, S t , naturally is high. This high tangential stress 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.
  • 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.
  • 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.
  • the hydrocarbon flow creates a high stress dragging the rock toward the wellbore, further offsetting the effect from the wellbore pressure stabilizing the wellbore.
  • the invented method for sand control can be called a mechanical consolidation method.
  • bead material is placed into the wellbore where the sand may be produced to form a packing 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.
  • a substantial axial stress is applied to the packing in order to generate a substantial radial stress to support or confine the wellbore formation.
  • 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 material.
  • a substantial force can be applied to the packing by a swelling force within the packing itself. Expanding the packing from inside the packing is also an option.
  • 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/cm 3 . 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.
  • steel bead material has a density of approximately 7.9 gram/cm 3 and tungsten carbide bead material has a density of approximately 15.6 gram/cm 3 .
  • the bead material has a density higher than gravel used in the conventional gravel packing. In one embodiment, the bead material has a density higher than 6 gram/cm 3 .
  • the bead material is made of metal materials. In one embodiment, the bead material is made of steel, carbon steel, stainless steel, copper, tungsten carbide.
  • bead material can have a potential of swelling
  • Swelling can be activated and sustained by an activating fluid.
  • the activating fluid then swells the size of the beads of the swellable bead material.
  • the packing can be further constrained from the top and bottom of the packing with such as well packers or other mechanical stoppers (hereinafter "well packers").
  • Swelling of the bead material constrained in the annulus can apply a radial stress to the wellbore forming the annulus around production tubing in the center of the wellbore. So in one embodiment, some bead material forming the packing is swellable. In one embodiment, all the bead material forming the packing is swellable. When the packing is tall enough, the friction and weight of the upper packing can serve as a stopper to constrain the swelling of the lower packing.
  • a packing of swellable bead material is naturally permeable to hydrocarbon or water flow.
  • a high permeability of the packing is desired. It is therefore desirable that the bead material has a similar size since a packing with bead material of a similar size tends to have the highest permeability.
  • a packing can be of a mixture of swellable and non-swellable bead material. In the mixture, the swellable bead after fully swelling is preferred to be the same size as or larger than the non-swellable bead material. The size of the largest swelled swellable bead material in a packing is preferred to be smaller than 1 inch.
  • Figure 4 illustrates a top view of a vertical wellbore 41 in a sandstone formation 42. Illustrated is placing swellable bead material into the active zone of the wellbore 41 to form a bead packing column 43. The bead material is confined by the wellbore 41 and the swellable bead material is activated to swell and generates a radial stress 44 to the wellbore wall to consolidate and support the sandstone formation in the active zone.
  • bead material is placed in a wellbore forming a bead packing, causing the bead material to swell, and pressing the bead packing radially onto the wellbore wall.
  • the material for the swellable bead material includes but not limited to the
  • elastomers that swell when exposed to an activating fluid, such as hydrocarbons: 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.
  • an activating fluid such as hydrocarbons: 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,
  • the material for the swellable bead material 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 sodium bentonite.
  • 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
  • swellable materials such as rubber are typically highly deformable.
  • the swellable bead material should be at least 1 % by volume in the packing. In one embodiment, the swellable bead material is at least 1 % by volume of the total bead material of the packing.
  • This swellable bead material can be carried in a non-activating fluid to be
  • This swellable bead material can also be mounted on a tool such as production tubing to be place into a wellbore structure. For example, swellable bead material is first placed in a permeable bag. Then the bag is wrapped around tubing. Then the tubing is lowered into a wellbore structure to where it is needed.
  • 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 this swellable bead material can be from 200 micron to 1 inch. But the preferred size is from 400 micron to 5000 micron before swelling.
  • a packing of swellable bead material can be a mixture of swellable bead material and non-swellable bead material. It is preferred to have 5 to 100 percent of the bead material in a packing is swellable in order to achieve enough additional radial stress from swelling.
  • Other non-swelling bead material 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.
  • substantial axial stress is applied to the packing of the bead material.
  • the axial stress applied to the packing is more than 50 psi.
  • the axial stress applied to the packing is more than 250 psi.
  • the axial stress applied to the packing is more than 500 psi.
  • the axial stress applied to the packing is more than 1000 psi.
  • substantial radial stress is applied to the wellbore formation for the entire active zone.
  • the radial stress applied to the wellbore is more than 50 psi.
  • the radial stress at the zone top is over 100 psi.
  • 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.
  • the radial stress is preferred to be close to the horizontal stress of the formation before the wellbore is drilled.
  • 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.
  • a first device is a first packing of one or more bead material.
  • 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.
  • the first device is a bow type spring.
  • a bow type spring has multiple bows 51 mounted on at least two bow rings 52.
  • the bows 51 are parallel to the axis of wellbore 53 and distributed circumferentially around the wellbore 53.
  • the bow type spring has a diameter smaller than the wellbore 53 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.
  • the bow type spring can continue to apply stress even when the wellbore is enlarged.
  • 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.
  • the bow type spring is wrapped with screens that can be expanded.
  • 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.
  • 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.
  • 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.
  • the pressure can come from the hydrostatic head of the fluid.
  • 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.
  • the pressure applied to the device must be higher than the pressure surrounding the device.
  • 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.
  • 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.
  • 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.
  • first or second devices can be installed.
  • a bow type spring is installed inside the bead packing covering the active zone.
  • an inflatable device is installed inside the bead packing covering the active zone.
  • the second device(s) is installed to apply stress to one or more of the first devices.
  • pump pressure, hydrostatic pressure and gravity of bead material all are applied to multiple first devices at the same time in the same well bore.
  • Figure 6 and 7 illustrate an exemplary embodiment of the current invention.
  • a bead packing 68 is installed within the sandstone formation top around tubing 65 in the wellbore for hydrocarbon flow 69.
  • the wellbore with the bead packing can be vertical, deviated or horizontal.
  • An inflatable rubber tube 611 is installed in the packing 68.
  • An annulus packer 66 is installed at the top of the packing 68 to isolate the annulus of the tubing and of the inflatable tube but allow the annular fluid 64 above the packer 66 to flow into the inflatable rubber tube 611.
  • Hydrocarbon 69 produced from the sandstone formation 610 flows through the tubing 65 up to the surface.
  • Annulus fluid 64 weight or hydrostatic head can then be applied to the tube 611 to inflate it to generate radial stress acting to the wall of the wellbore 67 through the bead packing 68.
  • pump pressure can be applied to the annulus fluid 64 to further inflate the tube for additional radial stress.
  • 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.
  • an inflatable tube is installed on the lower side of a deviated or
  • the wellbore pressure has to be reduced over time, causing a larger sanding tendency.
  • the formation effective stress is increasing, so the wellbore stress is even more unbalanced or unsupported, sanding is getting easier.
  • 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.
  • the inflatable tube is inflated naturally during production. Also
  • 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
  • the method can be used to support perforations of the cased hole for sand
  • a perforation hole can be viewed as a wellbore conduit. After packing the perforation holes with bead material, 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 material can be formed in place.
  • 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.
  • 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.
  • 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 any fluid.
  • the fluid may be any fluid.
  • the fluid may be any fluid.
  • the fluid may be any fluid.
  • the fluid may be any fluid.
  • the fluid may be any fluid.
  • the fluid may be any fluid.
  • the fluid may be any fluid.
  • the fluid may be any fluid.
  • the fluid may be any fluid.
  • the fluid may be any fluid.
  • 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.
  • the screen may have to be strong enough in order to apply a high stress.
  • the screen has a mesh size from US standard 200 to 5 mesh.
  • the screen has multiple layers of the same or different meshes.
  • Bead material can be placed between the screen and the formation to adapt to the irregularity of a wellbore. In one embodiment, bead material is 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.
  • 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:
  • 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 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. This is more effective when the packing is not too long.
  • the bead material 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.
  • the packing is formed by a plurality of the bead material of the shape of one or more of round, oval, cubic, prism, column, sand.
  • the bead material can also be of holes to enhance the permeability of the packing.
  • the bead material has one or more holes.
  • one bead material is of the shape of a short tube.
  • the bead material is sand, gravel, or made of ceramic, metal or plastic materials.
  • some of the materials are rigid so that the pores between the materials will not close under stress.
  • the bead material is made of steel. In another embodiment, the bead material is made of stainless steel.
  • 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.
  • the casing or tubing is substantially thicker and heavier when applying weight to the first device is
  • 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.
  • 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.
  • the fluid may be weighted to a high density to provide the needed weight with a certain fluid column height.
  • 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.
  • 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
  • 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.
  • the spring is of a spiral shape around a casing or tubing.
  • Steel casing or tubing is also elastic.
  • 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
  • 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%.
  • 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%.
  • the bead material can be pushed by 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.
  • 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.
  • 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.
  • hydrocarbon production is preferred to be as high as possible with zero sand production.
  • a higher hydrocarbon production rate requires a lower wellbore pressure that tends to result in a tendency for larger sand production.
  • 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 required radial stress for a target hydrocarbon production rate.
  • the bead material comprises 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 material prefers to be made of one or more materials of the
  • the bead material is 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/cm 3 . When heavier materials are used, the radial stress generated can be much higher.
  • the bead material has a density higher than gravel used in the conventional gravel packing.
  • the bead material prefers to have a ratio of the largest dimension to the smallest dimension less than 4:1 , preferably 1 :1 .
  • the bead material prefers to have a true density of 0.8-18 gram/cm 3 .
  • the bead material has a density above 6 gram/cm 3 .
  • the bead material prefers to be of a higher density so that the gravity
  • the bead material can further be porous or have one or more holes so
  • the bead material is sand or gravel.
  • the bead material is stainless steel ball bearings.
  • the size of the bead material is from 0.01 to 50 mm or millimeter. It is favorable to have smaller bead material in the active zone and favorable size is approximately 6 times the sand grain size. Due to the mechanical consolidation from the radial stress, the bead material 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.
  • a layer of smaller bead material can be placed in the active zone to block the sand grains and larger bead material can be placed behind the smaller bead material to block the smaller bead material. More bead material then can be placed on top of the larger bead material for the vertical stress needed. With this method, screen wrapped or slotted pipe to hold the smaller bead material is not needed. The smaller bead material can be placed into perforations to block the sand grains if perforated casing is present.
  • the bead material is mixed in a carrying fluid and pumped down hole to be placed in place by the fluid.
  • 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 material 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.
  • 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.
  • [001 19] 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 material 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.
  • the wellbore size in the active zone can be enlarged as much as needed before installing the first device.
  • 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.
  • the flow of hydrocarbon is replaced by water or brine and the flow direction is reversed or from the surface to the formation.
  • 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
  • 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.
  • the casing or tubing may be able to sustain much great pressure without failure.
  • the casing or tubing may resist buckling from such as subsidence of the formation.
  • conduit can provide the needed support for casing or tubing.
  • bead material 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 material 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.
  • the packing formed in the annulus of casing or tubing it can support the casing or tubing for much higher pressure without burst.
  • 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.
  • 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.
  • 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.
  • 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.
  • the packing can be secured by the weight of the packing
  • a packing of bead material is installed inside the annulus between casing and production tubing. In another embodiment, a packing of bead material is installed inside casing. In another embodiment, a packing of bead material is installed inside tubing. In another embodiment, a packing of bead material is installed a casing annulus where it is surrounded by a salt formation.
  • Subsidence may occur in the reservoir formation.
  • a packing of bead material is installed in the annulus of the casing to be protected in the active zone.
  • a packing of bead material is installed in the annulus of the tubing to be protected in the active zone.
  • the protection can be extended into the zone above the active zone.
  • a packing of bead material 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.
  • a packing of bead material 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.
  • an axial stress is applied to the packing to increase its resistance with a higher radial stress to the point loading.
  • a micro annulus can be identified by the wellhead casing pressure
  • a micro annulus is identified first. In another embodiment, a potential micro annulus is identified first.
  • a packing of bead material 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.
  • a micro annulus may form around casing
  • 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.
  • 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 packing can be partially replaced by one or more of the following:
  • 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.
  • 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.
  • 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 packing. The packing then is loaded with the required stress.
  • 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.
  • the radial stress is large enough, the fracture can be kept open.
  • Figure 8 is a cross section of an active zone of a wellbore using a packing of bead material installed in the active zone to prevent fractures from closing.
  • hydrocarbon flow 85 goes toward the wellbore 82 either through
  • hydrocarbon formation 81 or through hydraulic fracture 84 Hydrocarbon flows through the bead material 86 into tubing 83 to be produced. With an axial stress applied to bead material, a radial stress is generated to prop the fracture open.
  • Swellable bead material can be placed in the wellbore to provide the stress when swelling is activated.
  • Swellable bead material can be placed into perforations to support the perforations.
  • swellable bead material can be placed into a fracture connecting to a wellbore so that the swelling of the bead material can help to resist the closing of the fracture.
  • at least some swellable bead material is placed into a perforation.
  • at least some swellable bead material is placed into a fracture.

Landscapes

  • Life Sciences & Earth Sciences (AREA)
  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Mining & Mineral Resources (AREA)
  • Physics & Mathematics (AREA)
  • Environmental & Geological Engineering (AREA)
  • Fluid Mechanics (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Earth Drilling (AREA)

Abstract

La présente invention concerne un procédé et un appareil destinés à supporter une structure de puits de forage souterraine qui font appel à une contrainte de support. La contrainte de support est créée par le chargement de la structure de puits de forage avec un matériau de talon de façon à former un emballage de talon. La contrainte de support peut être générée par le gonflage d'un dispositif gonflable installé à l'intérieur de l'emballage. La contrainte de support peut également être créée par la dilatation d'un matériau de talon pouvant se dilater lorsque l'emballage est au moins en partie formé par un matériau de talon pouvant se dilater. La contrainte dirigée radialement permet de compacter la formation géologique. Ceci peut comprendre le compactage de sable meuble qui autrement peut entrer dans l'écoulement d'hydrocarbure ainsi produit. Le matériau de talon peut également supporter le tubage ou la tuyauterie de production du puits de forage d'un point de chargement créé par le mouvement de sel ou d'autres formations souterraines. Le matériau de talon peut comprendre de la baryte, de l'hématite, de l'oxyde de fer, de l'ilménite, du métal, du sable, du gravier, du caoutchouc, un alliage et des combinaisons de ceux-ci.
PCT/US2015/035493 2014-07-02 2015-06-12 Procédé de support d'un conduit souterrain WO2016003629A1 (fr)

Applications Claiming Priority (6)

Application Number Priority Date Filing Date Title
US201462020003P 2014-07-02 2014-07-02
US62/020,003 2014-07-02
US201462032300P 2014-08-01 2014-08-01
US62/032,300 2014-08-01
US201462083217P 2014-11-22 2014-11-22
US62/083,217 2014-11-22

Publications (1)

Publication Number Publication Date
WO2016003629A1 true WO2016003629A1 (fr) 2016-01-07

Family

ID=55016664

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2015/035493 WO2016003629A1 (fr) 2014-07-02 2015-06-12 Procédé de support d'un conduit souterrain

Country Status (2)

Country Link
US (1) US20160002998A1 (fr)
WO (1) WO2016003629A1 (fr)

Families Citing this family (8)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US9828543B2 (en) 2014-11-19 2017-11-28 Saudi Arabian Oil Company Compositions of and methods for using hydraulic fracturing fluid for petroleum production
GB2554371B (en) 2016-09-22 2019-10-09 Resolute Energy Solutions Ltd Well apparatus and associated methods
US10465484B2 (en) * 2017-06-23 2019-11-05 Saudi Arabian Oil Company Gravel packing system and method
WO2020091775A1 (fr) * 2018-10-31 2020-05-07 Halliburton Energy Services, Inc. Systèmes et procédés pour indiquer l'achèvement d'une opération de cimentation inverse
US11608700B2 (en) * 2019-10-31 2023-03-21 Sharp-Rock Technologies, Inc. Methods and systems for anchoring a plug in a wellbore
CN114058341B (zh) * 2020-07-29 2023-02-28 中国石油化工股份有限公司 一种钻井液用添加剂及钻井液用组合物
US20220381107A1 (en) * 2021-05-28 2022-12-01 Halliburton Energy Services, Inc. Rapid setting expandable metal
DE112021007726T5 (de) * 2021-05-28 2024-03-07 Halliburton Energy Services, Inc. Einzelne separate Stücke aus erweiterbarem Metall

Citations (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7036600B2 (en) * 2002-08-01 2006-05-02 Schlumberger Technology Corporation Technique for deploying expandables
US20070044963A1 (en) * 2005-09-01 2007-03-01 Schlumberger Technology Corporation System and Method for Controlling Undesirable Fluid Incursion During Hydrocarbon Production
US20080135250A1 (en) * 2004-11-18 2008-06-12 Shell Oil Company Method of Sealing an Annular Space In a Wellbore
US20090120640A1 (en) * 2007-11-09 2009-05-14 David Kulakofsky Methods of Integrating Analysis, Auto-Sealing, and Swellable-Packer Elements for a Reliable Annular Seal
US20100126722A1 (en) * 2007-03-28 2010-05-27 Erik Kerst Cornelissen Wellbore system and method of completing a wellbore
US20100175895A1 (en) * 2007-06-26 2010-07-15 Paul David Metcalfe Permeability Modification
US8662172B2 (en) * 2010-04-12 2014-03-04 Schlumberger Technology Corporation Methods to gravel pack a well using expanding materials

Family Cites Families (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2365033A (en) * 1942-05-02 1944-12-12 Standard Oil Dev Co Gravel packing of wells
US5402848A (en) * 1994-04-07 1995-04-04 Kelly; Leo G. Method and apparatus for conducting environmental procedures
US7661481B2 (en) * 2006-06-06 2010-02-16 Halliburton Energy Services, Inc. Downhole wellbore tools having deteriorable and water-swellable components thereof and methods of use
US9816364B2 (en) * 2013-09-25 2017-11-14 Bj Services, Llc Well stimulation methods and proppant

Patent Citations (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7036600B2 (en) * 2002-08-01 2006-05-02 Schlumberger Technology Corporation Technique for deploying expandables
US20080135250A1 (en) * 2004-11-18 2008-06-12 Shell Oil Company Method of Sealing an Annular Space In a Wellbore
US20070044963A1 (en) * 2005-09-01 2007-03-01 Schlumberger Technology Corporation System and Method for Controlling Undesirable Fluid Incursion During Hydrocarbon Production
US20100126722A1 (en) * 2007-03-28 2010-05-27 Erik Kerst Cornelissen Wellbore system and method of completing a wellbore
US20100175895A1 (en) * 2007-06-26 2010-07-15 Paul David Metcalfe Permeability Modification
US20090120640A1 (en) * 2007-11-09 2009-05-14 David Kulakofsky Methods of Integrating Analysis, Auto-Sealing, and Swellable-Packer Elements for a Reliable Annular Seal
US8662172B2 (en) * 2010-04-12 2014-03-04 Schlumberger Technology Corporation Methods to gravel pack a well using expanding materials

Also Published As

Publication number Publication date
US20160002998A1 (en) 2016-01-07

Similar Documents

Publication Publication Date Title
US20160002998A1 (en) Method of Supporting a Subterranean Conduit
US8555985B2 (en) Permeability modification
CA2596773C (fr) Amorcage de plans d'injection dans un puits
US7543640B2 (en) System and method for controlling undesirable fluid incursion during hydrocarbon production
GB2398582A (en) System and method for maintaining zonal isolation in a wellbore
NO325734B1 (no) Grusoppblast isolasjonspakning samt en fremgangsmate for tetting av et ringrom i en bronn.
MX2013006301A (es) Filtro para filtracion con grava de canal de flujo alternativo y metodo para completar un sondeo.
CA2443172C (fr) Procede de fixation de tuyaux dans un puits visant a limiter la pression et le debit de ceux-ci
CN110847847A (zh) 一种可重复座封解封的机械触发式封隔器
GB2419902A (en) Method of cementing expandable tubulars
US9810046B2 (en) Screen packer assembly
WO2019051176A1 (fr) Atténuation de la production de sable dans un réservoir de grès à l'aide de billes thermiquement expansibles
EP2670940B1 (fr) Procédés de maintien d'une pression hydrostatique suffisante dans de multiples intervalles d'un puits de forage dans une formation molle
US4279307A (en) Natural gas production from geopressured aquifers
Chen et al. Optimisation of sand control technique for offshore heavy oil and unconsolidated Sandstone reservoir: case study from Bohai Bay
CN114718505B (zh) 固井方法及固井系统
El-Fseis A feasibility study for drilling & completing ERD wells on the Brage field
CA2694822A1 (fr) Procede pour modifier l'etat de contrainte d'une formation et/ou d'un element tubulaire

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 15815584

Country of ref document: EP

Kind code of ref document: A1

NENP Non-entry into the national phase

Ref country code: DE

122 Ep: pct application non-entry in european phase

Ref document number: 15815584

Country of ref document: EP

Kind code of ref document: A1

点击 这是indexloc提供的php浏览器服务，不要输入任何密码和下载