EA008963B1 - Method for suppressing fluid communication to or from a wellbore - Google Patents

Abstract

A method for suppressing fluid communication to or from a wellbore in a subsurface formation, which method comprises providing a well fluid which comprises solid particles in a carrying fluid, which solid particles include a reactive polymer; introducing the well fluid into the wellbore so that carrier fluid passes through an interface between the wellbore and its surroundings, wherein particles are accumulated at the interface; and allowing the polymer to form a solid plug suppressing fluid communication through the interface; and a well fluid for use in a wellbore, which well fluid comprises solid particles in a carrying fluid, which solid particles include a reactive polymer.

Description

FIELD OF THE INVENTION

The present invention relates to a method for inhibiting the movement of a fluid into or out of a wellbore in a subterranean formation and to a wellbore fluid for use in a wellbore.

State of the art

When drilling and operating a wellbore in an underground formation, situations often arise in which it is desirable to suppress the movement of fluid in the well.

For example, fluid obtained from hydrocarbon oil or gas wells often contains significant amounts of water. As used herein, the term “water” also includes salt water. The source of water may be formation water penetrating from the formation layers adjacent to the hydrocarbon bearing layers, or water entering the formation when it is injected from the surface.

The water contained in the produced fluid reduces the ability to lift an oil or gas well, and the resulting water is an environmental problem. Often, the concentration of water in the produced fluid increases with the aging of the well, and at some point it is desirable to treat the well in order to get less water from it.

A similar challenge is to suppress fluid movement through cracks in the formation surrounding the wellbore. Cracks can lead to undesirable loss of drilling fluid in the surrounding formation, which leads to the need to seal the movement of the fluid through the cracks.

Other situations in which it may be desirable to suppress fluid movement within the well occur when casing seeps out, for example, when there are cavities behind the casing or when voids or rings are present between the metal casing and the surrounding cement. Such situations are hereinafter referred to as cementing heterogeneities.

In an example of a situation in which isolation is desired, the subterranean formation is formed from a plurality of oil-bearing layers located one above the other, and the wellbore extends through the formation and is made with holes located in all oil-bearing layers. After some time of operation, as a result of studying instrument readings, field data and production data, it is determined that some layers still have a high degree of saturation with hydrocarbons, while others are already filled with water. Therefore, it would be desirable to provide the ability to selectively suppress fluid movement between the wellbore and the water-filled layer (s).

Such a task does not have a simple solution. The applicant faced this problem in a situation in which the completion of the well is a complex with a relatively small string of tubing (diameter 3.5 = 9 cm) inside a relatively large casing of the wellbore (diameter 7 = 18 cm), at relatively high static temperatures in the well (> 110 ° C), with a relatively high pressure drop between the different layers (up to 3000 psi = 21 MPa).

Conventional cement insulation is in this case not a practical option for such high pressure drops.

When considering other possible solutions known in the prior art, it turned out that only relatively complex mechanical options are available.

One mechanical option would be to install a selective well completion with multiple zones. This would imply the need to remove the first existing completion, i.e. node pipes and equipment inside the well. After that, it would be necessary to establish a selective termination, in which all the corresponding layers are isolated by the elements of the packer, in order to provide the ability to control production from any of these zones using valves.

Another common mechanical option would be to cement the casing over existing openings to block fluid movement between all openings and the wellbore, followed by re-perforating the hydrocarbon containing zones. And again, this would require the removal of the existing termination.

Any of these mechanical options would be expensive and time consuming, because in each case it would first be necessary to remove the existing termination so that the required equipment could be used locally.

European patent application publication publication EP 1369401 discloses a sealing composition for use in a wellbore, the composition comprising water, a cementitious material and a water-soluble crosslinkable material such as 2-hydroxyethyl acrylate monomer or acrylamide-t-butyl acrylate copolymer. Such a sealing composition can withstand a much higher pressure drop (maximum back pressure) than conventional cement. Such a composition may be introduced through an existing completion into the wellbore. When the extrusion pressure is applied, the stitched material penetrates with water at a certain distance into the formation surrounding the wellbore, where it is stitched

- 1 008963. Cement remains at the interface with the wellbore and hardens there. The known sealing composition is relatively difficult to prepare and process, and it requires special expertise in use. Cement can, for example, harden in a tubing or in a wellbore under the influence of fluids in a wellbore or local hot spots in a well, and removing hardened cement from a flexible tubing or production tubing is very expensive. In addition, after cement is injected, excess cement must be pumped out along with viscous salt water. As a result, the entire completion of the well will be exposed to this mixture of cement and salt water, which potentially contaminates vital parts of the well, such as gas valves and side gas lift mandrels.

US Pat. No. 3,525,398 describes a method for sealing cracks in a permeable formation in which a thixotropic liquid suspension of deformable solid resin particles is introduced into the crack and in which deformation of the particles under pressure is used to form a substantially impermeable barrier in the crack. Another physical process for sealing cracks is known from US Pat. No. 3,327,719, in which solid polymer / wax / resin particles are introduced to form a temporary plug during cracking, which can then be dissolved by the formation hydrocarbons. Another physical process for providing hydraulic compaction under the ground is known from the publication of application No. \ ¥ O 01/74967 for an international patent, in which the gel-forming polymer is introduced into the circulation loss zone, where it swells.

An object of the present invention is to provide an improved method for suppressing the movement of a fluid between a wellbore and the surrounding subterranean formation.

Another objective is to obtain a special good downhole fluid suitable for use in this improved method.

SUMMARY OF THE INVENTION

To this end, a method for suppressing the movement of a fluid into or from a wellbore in a subterranean formation, comprising using a wellbore fluid containing solid particles in a carrier fluid, the solid particles comprising a reactive polymer;

supplying the wellbore fluid to the wellbore so that the carrier fluid penetrates through the interface between the wellbore and the surrounding area in which particles accumulate on the interface; and the formation of a polymer solid plug that inhibits the movement of fluid through the interface.

Also provided is a wellbore fluid for use in a wellbore, wherein the wellbore fluid contains solid particles in a carrier fluid, and these solid particles include a reactive polymer. The invention also relates to the use of this borehole fluid in a wellbore, in particular for suppressing the movement of a fluid at an interface.

The present invention is based on the applicant's understanding that solid polymer particles in a carrier fluid form, in particular, an easily processable sealant composition for use in a wellbore. The gravel packer mixer standard unit is sufficient to prepare the wellbore fluid. It is not required to use any special mixers for cement mortar and pumps, as in the preparation of complex multicomponent cement mixtures. There are no dusty components, and therefore the invention provides a much safer system for the operator.

The term polymer plug includes polymer layers that form at the interface. A solid plug is formed by the reaction of a reactive polymer. Accordingly, the polymer plug cannot be dissolved by the fluids of the field. Polymer plugs formed from reactive polymers can handle much higher pressure drops than conventional sealing systems, such as 21 MPa or more. Differentials can reach 50 MPa or more, depending on the mechanical properties of the polymer, due to the unlimited compressive strength of the polymer. As the carrier fluid, for example, salt water or a hydrocarbon liquid such as diesel fuel can be used.

Particles are solid and therefore not sticky on the surface. The chemical product and physical parameters can be tailored for a particular application. Preferably, the particles contain at least 50 wt.% Of the polymer or polymer composition, more preferably at least 90 wt.%, Most preferably they consist only of the polymer or polymer composition.

The carrier fluid is extruded into the formation, as a result of which solid particles accumulate on the interface. For this purpose, the particle size is preferably chosen so that they reach the interface, but slightly fall into the formation, respectively, less than 10 cm, preferably less than 2 cm, usually about 1 cm or less. When on top

- The section is formed by perforations of the wellbore into the formation, the particles have, respectively, the smallest linear size, in the range from 1 mm to 2 cm. When the interface is formed by a crack, the smallest linear size, respectively, is from 500 μm to 2 cm. For repair of cement inhomogeneities, smaller particles, respectively, are taken in the range of 1-200 μm. The shape of the particles can also be suitably selected, for example, usually spherical, cylindrical or cubic, as well as an irregular shape.

Particles accumulate on the interface, and unlike the water-soluble crosslinkable material of the prior art, the sealing compositions do not penetrate the formation, therefore, after correction, a solid layer or plugs are formed directly on the interface. Such a solid layer on the interface has the advantage that the movement of the fluid can be directly and selectively restored again, if necessary, using standard perforation techniques. Otherwise, i.e. if the seal were formed at some distance in the formation, re-perforation would be a problem. Another advantage of the solid layer at the interface is that the risk that the produced hydrocarbons will be locked in place is eliminated.

As reactive polymer particles, known curable polymers or a polymer composition can be used, for example, a phenolic resin composition, a polyester resin composition, an epoxy resin composition or a polyurethane composition.

Accordingly, the curable composition contains at least two different compositions, for example a chemically active polymer chain and a crosslinking agent or hardener, these compositions interacting with each other, forming frequent cross-links to form a (crosslinked) polymer network. Each chemically active polymer particle, respectively, contains both compounds.

The temperature at the interface is usually higher than the temperature at the surface of the earth. A typical temperature of the oil-bearing layers of the field is from 110 to 180 ° C, for example 150 ° C. The reaction of a reactive polymer can begin simply as a result of exposure to such a temperature at the interface for a sufficiently long period of time, for example 1-24

h. The formation of cross-links occurs, respectively, both inside the particles and between the particles, as a result of which a macroscopic sealing structure is formed.

Depending on the reaction rate of a particular reactive polymer at an elevated temperature, it may be necessary to supply a cooling fluid to the wellbore prior to introducing reactive polymer particles, for example, to lower the temperature in the wellbore near the interface to be sealed by 20-50K. This prevents the premature reaction of polymer particles during their movement down the wellbore to the interface.

In another embodiment of the use of chemically active polymers, their choice is such that additional heating above the formation temperature at the interface is necessary for the reaction to proceed. In this case, an appropriate heater, such as an electric cable heater, can be used to conduct the reaction in the wellbore. You can also use pre-flushing the interface with a heating fluid, such as hot salt water, to locally and temporarily heat the formation.

The relative densities of the polymer particles and the carrier fluid can be selected such that the particle density is equal to or higher or lower than the density of the carrier fluid. Density values at ambient temperature may accordingly be 500 kg / m ³ or higher, but should not exceed 1,500 kg / m ³ . At the same density, the particles will float in the liquid, which makes it possible to obtain a relatively stable suspension, with which it is possible to easily treat surfaces. At a higher particle density, excess particles that were not accumulated at the interface will automatically settle to the bottom of the wellbore. On the other hand, when particles are lighter than liquid, excess particles will preferably float to the surface where they can be removed.

The invention also relates to a wellbore fluid for use in a wellbore, wherein the wellbore fluid contains solids in a carrier fluid, and solids include a reactive polymer. Such a borehole fluid (processing fluid) can effectively and reliably isolate holes and cracks, and other liquid-permeable interfaces between the wellbore and the formation. Preferably, the reactive wellbore fluid polymer comprises an epoxy resin composition comprising an epoxy resin, a curing agent and, if necessary, an accelerator, catalyst and / or filler material.

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Brief Description of the Drawings

An embodiment of the invention will be described in more detail below with reference to the accompanying drawings, in which in FIG. 1-4 show several stages of an embodiment of the application of the method of the present invention in a wellbore extending into a layered formation of a field; and in FIG. 5 schematically shows a test bench for testing the present invention.

At the same time, the same reference numbers are used in different drawings, where they denote the same or similar objects.

DETAILED DESCRIPTION OF THE INVENTION

Consider FIG. 1. This figure shows the lower part of the wellbore 1 extending from the surface (not shown) into the underground formation 4. The underground formation in this example is layered. Layers 6 and 7 contain hydrocarbons - oil, and layer 8 is an aquifer. The layers 6, 7, 8 are separated by boundaries or impermeable layers 10, 11. The wellbore 1 is provided with a casing 14 formed of a metal casing, the ring 15 between the walls of the casing and the wellbore 1 is filled with cement. Well completion is indicated by a pipe 16 extending to the surface and a packer 18.

The fluid enters the wellbore 1 from the layers 6, 7, 8 through a perforation 20, 21, 22, as indicated by arrows, and is supplied to the surface through the tubing 16. This fluid contains oil 23 and a significant amount of water 24, obtained from layer 8. In this case, it is preferable to hermetically seal the influx of water from the aquifer 8, in particular through holes 21 that form the interface between the wellbore and the aquifer.

As shown in FIG. 2, for this purpose, the first flexible tubing 25 is lowered through the tubing 16, and the cooling fluid fluid 27 is supplied through the flexible tubing 25 to the wellbore 1, from which it flows for some distance into the layers 6, 7, 8 formations. The cooling fluid may be a 2 wt.% Solution of KC1 in water. The volume and rate of injection can be determined based on temperature simulation. Typically, 200-2000 barrels (31.8-318 m ³ ) of cooling fluid are supplied at a speed of 1-5 barrels / min (0.159-0.795 m ³ / min) to cool the interface by 20-50K.

As shown in FIG. 3, immediately after the cessation of the cooling fluid injection, a special well fluid 28 is pumped into the wellbore through a flexible tubing. In accordance with the invention, the wellbore fluid comprises a suspension of solid reactive polymer particles 29 in a carrier fluid. The particle concentration can be from 1 to 50% by weight of the total well fluid, and the particle size can be from 0.1 mm to 5 cm. For spherical particles, the particle size is represented by the weighted average of the diameter of the different particles. For particles with a different profile, the maximum values of the particle lengths in different linear directions can be determined, and the smallest value of the linear size can be defined as the smallest value of this maximum length, and the total particle size is the weighted average of the smallest linear size of different particles.

The corresponding reactive polymer (composition) includes an epoxy resin and a crosslinking agent, both of which are contained in the same particles.

At least part of the carrier fluid, which can also be a 2 wt.% KC1 solution in water, flows into the layers 6, 7, 8 of the formation through perforations 20, 21, 22. Due to their size, the reactive polymer particles will not penetrate into formation layers, and will accumulate on the interface between the wellbore and the formation layers in the perforation tunnels. This phenomenon can be noted on the surface of the earth by increasing pressure as a result of a decrease in throttle response. The injection, respectively, is continued until the maximum surface pressure is reached. Pressure (the so-called differential pressure) is maintained for a certain period of time, for example 2-16 hours. During this period, the temperature at the interface rises again, approaching the normal temperature of the formation. The chemically active polymer composition is chosen such that a reaction occurs at such an increase in temperature. Accordingly, the reaction rate at a temperature on the surface of the earth, as well as at temperatures during the movement of particles down the wellbore during injection, can be neglected. Some softening of the solid particles can occur at elevated temperatures before the start of the curing reaction, which forms a solid plug. Preferably, the glass transition temperature of the polymer after the reaction is higher than the ambient temperature at the sealed interface. The cured polymer is not substantially deformed.

At the temperature of the formation, cross-links are formed within the particles and between adjacent particles, as a result of which a plug or a sealing layer 31 of polymer is formed on the interface. Preferably, the particles are selected so that they soften at an elevated temperature so that they come into close contact with each other to ensure good bonding between the particles. It is also possible to use a polymer that expands after curing to improve insulation. The expanded polymer is still considered a solid polymer.

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After the reactive polymer has cured, the perforation 20, 21, 22 is sealed, preventing the movement of fluid between the wellbore and the layers 6, 7, 8. The flexible tubing is removed and the oil layers 6, 7 can be selectively re-punched through the tubing 16, using technologies known in the art.

The result is shown in FIG. 4. Oil 23 is obtained from layers 6, 7 through a new perforation 35, 36, and the flow of water from layer 8 is suppressed by the sealing layer 31 at the interface.

It should be understood that the cooling step is not necessary if the injection of particles into the wellbore and accumulation at the interface occurs much faster than the reaction.

In a preferred embodiment, the reactive polymer is an epoxy resin composition. The epoxy resin composition typically contains an epoxy resin, a crosslinking agent or a hardener and, if necessary, an accelerator, catalyst and / or filler material. For each component of such a composition, a plurality of suitable materials are known in the art.

An epoxy resin is a molecule containing more than one epoxy group. There are two main categories of epoxies: glycidyl epoxide and non-glycidyl epoxies. Glycidyl epoxides can be further classified as glycidyl ether, glycidyl ester and glycidylamine. Non-glycidyl epoxides are aliphatic or cycloaliphatic epoxies. Glycidyl epoxides can be prepared using the condensation reaction of the corresponding dihydroxy compound, dibasic acid or diamine and epichlorohydrin. Non-glycidyl epoxides can be obtained by peroxidation of an olefinic double bond.

Suitable and common glycidyl ether epoxides are either bisphenol-A diglycidyl ether (DHEBA, ΌΟΕΒΑ) diglycidyl ether epoxies or novolac phenol-formaldehyde resin epoxies. Bisphenol-A diglycidyl ether (DHEBA) can be synthesized by reacting bisphenol-A with epichlorohydrin in the presence of a basic catalyst. The properties of DHEBA resins depend on the number of repeating elementary units forming the resin chain, also known as the degree of polymerization. Typically, this amount is from 0 to 25 for many commercial products.

Other suitable epoxies are novolac phenol-formaldehyde resins, which are glycidyl ethers of novolac phenol-formaldehyde resins. Phenols interact with excess with formaldehyde in the presence of an acid catalyst to produce novolac phenol formaldehyde resin. Epoxy resins based on novolac phenol formaldehyde resin can be synthesized by reacting novolac phenol formaldehyde resin with epichlorohydrin in the presence of sodium hydroxide as a catalyst. Novolac phenol-formaldehyde resin-based epoxies typically contain many epoxy groups. The number of epoxy groups in the molecule depends on the number of phenolic hydroxyl groups in the initial novolac phenol-formaldehyde resin, the degree of their interaction, and the number of low molecular weight radicals polymerized during the synthesis. Many epoxy groups provide a high crosslink density for these resins, resulting in excellent resistance to temperatures, chemicals and solvents.

Epoxy resins based on novolac phenol-formaldehyde resin, among other things, have exceptional characteristics at elevated temperatures, excellent formability and mechanical properties.

You can also use another suitable epoxy resin, such as orthocresol-based epoxy instead of bisphenol-A.

The curing process is a chemical reaction in which the epoxy groups in the epoxy resin interact with a curing agent (curing agent) to form a highly crosslinked three-dimensional network. To convert epoxy resins to solid material, the resin must be cured with a hardener. Epoxy resins can be designed to quickly and easily cure at virtually any temperature from 5 to 160 ° C, depending on the choice of curing agent. Accordingly, the composition is configured to cure at temperatures prevailing at the place where it is desired to provide insulation, in particular above 50 ° C, preferably from 80 to 150 ° C.

A wide variety of curing agents for epoxy resins is known in the art. Typical curing agents for epoxides include amines, polyamides, phenol aldehyde resins, anhydrides, isocyanates and polymer mercaptans. The cure kinetics and TD of the cured system depend on the molecular structure of the hardener. The choice of resin and hardener depends on the application and the required properties. The stoichiometry of the epoxy hardener system also affects the properties of the cured material.

Amines are commonly used to cure epoxy. Primary and secondary amines are chemically active in reaction with an epoxy resin. Tertiary amines are typically used

- 5 008963 used as catalysts, commonly known as curing accelerators. By using excess catalyst, faster cure is achieved, but usually by shortening the service life and thermal stability. The catalytic effect of the catalysts affects the physical parameters of the final cured polymer.

Epoxy resins can also be cured using a phenolic hardener. For full cure, it may be preferable to use an accelerator.

Appropriate epoxy resin compositions according to the invention can also be based on a liquid epoxy resin that can be mixed with a curing agent with an incomplete curing reaction, which forms a solid polymer with an epoxy resin for injection into the wellbore. The solid particles can be further cured by an additional reaction with a curing agent after exposure at an appropriate temperature at the interface. The liquid epoxy resin may, for example, be an epoxy resin based on novolac phenol-formaldehyde resin with an epoxy content of 5500-5700 mmol / kg. Another example is an intermediate viscosity resin based on bisphenol-A / epichlorohydrin with an epoxy content of 5000-5500 mmol / kg, such as a material known as ΕΡΙΚΟΤΕ 828. In both cases, diethyltoluene diamine can be a curing agent.

Suitable compositions may also be based on an epoxy formulation powder, such as ΕΡΙΚΟΤΕ 1001 or 3003, or a high temperature formulation coating powder. Materials ляет are supplied by Ke8o1i1yui RegGogtaps RtobisK

The filler material may be added to the epoxy resin composition to reduce cost, limit compression after curing, limit the stickiness of solid particles and / or control particle density. As appropriate fillers, you can use calcium carbonate, silica or glass balls.

Information confirming the possibility of carrying out the invention

Example.

The present invention has been tested in a so-called closed trial. Consider FIG. 5. A cylindrical core 50 of Wegea sandstone with a permeability of 500 millidarsi was installed in a steel test bench 53, which can be placed in a furnace (not shown). A small hole 60 was drilled on one side 55 of the core 50. The core had an outer diameter and a height of 5 cm, and the hole had a diameter of 0.8 cm and a depth of 1 cm. The core surface outside the hole 60 and outside side 63 of the opposite side 55 was sealed for epoxy fluid with resin 65. A suspension was prepared from milled high-temperature epoxy powder, coating the powder without filler in a 2% solution of KC1 in water with a particle size of less than 1 mm at 20 wt.% solid. The suspension was pressed into the hole under a pressure of 0.5-1 bar. The composition was left to cure for 48 hours at 150 ° C to form a solid plug in the hole 60, as well as in the area 68 of the interface between the core 50 and the hole 60. After that, the obtained permeability was determined by applying 180 bar of liquid pressure (salt water) at 150 ° C through hole 70 on side 63. The resulting permeability (reverse permeability) was 0.02% of the original core permeability value. In an additional experiment, a suspension of powder was pressed under a pressure of 25 bar into the hole and cured and checked in the same way. Although the cut of the treated core showed that, at a higher pressure, the plug 70 extends deeper into the core than at a lower pressure, the reverse permeability value was similar to the first experiment.

Claims (7)

CLAIM 1. A method of suppressing the movement of fluid into or out of a wellbore in a subterranean formation, including the use of a well fluid containing solid particles in a carrier fluid, the solid particles comprising a reactive polymer; supplying the well fluid to the wellbore so that the carrier fluid penetrates the interface between the wellbore and the surrounding area in which particles accumulate at the interface; and forming a solid cork from the polymer that suppresses the movement of fluid through the interface. 2. The method of claim 1, wherein the interface is formed from perforations in the formation, fractures in the formation, or cement heterogeneity between the metal casing and the formation. 3. The method according to claim 1 or 2, in which the polymer is a thermosetting active polymer composition, for example, selected from the group consisting of a phenolic resin composition, a polyester based resin composition, an epoxy resin composition and a polyurethane based composition. 4. The method according to claim 3, in which the polymer is an epoxy resin composition containing - 6 008963 epoxy resin, curing agent and, if necessary, accelerator, catalyst and / or filler material. 5. The method according to any one of claims 1 to 4, in which the cooling fluid is injected into the wellbore prior to the supply of a downhole agent with chemically active polymer particles. 6. The method according to any one of claims 1 to 5, in which the heating fluid is injected into the wellbore prior to the delivery of a downhole agent with chemically active polymer particles. 7. The method according to any one of claims 1 to 6, in which the underground formation is subsequently selectively re-perforated.