RU2771651C1 - Discharge of liquids at low temperatures in completion operations using a natural mineral compound - Google Patents

Abstract

FIELD: treatment fluids.

SUBSTANCE: inventions group relates to treatment fluids and methods for use in hydrocarbon reservoirs and, in particular, to the use of degradable additives in treatment fluids. A method for closing a hole in a subterranean formation includes introducing a treatment fluid containing a carrier liquid and a granular langbeinite material into the subterranean formation. At least one hole is blocked in said underground formation using granular langbeinite material. The granular langbeinite material is allowed to decompose. Fluid is passed through said at least one hole.

EFFECT: improving the efficiency of temporary blocking of holes in the underground formation.

20 cl, 3 ex, 1 tbl, 8 dwg

Description

PREVIOUS RELATED APPLICATIONS

This patent application is filed pursuant to a patent cooperation agreement that claims benefit and priority under U.S. Provisional Application No. 62/858,694, filed June 7, 2019, and U.S. Provisional Application No. 62/882,930, filed August 5, 2019, the contents of which are incorporated herein by reference in their entirety.

FEDERAL SCIENTIFIC STATEMENT

Not applicable.

LINK TO THE APP CONTAINING THE FISH

Not applicable.

FIELD OF TECHNOLOGY TO WHICH THE INVENTION RELATES

The invention relates to treatment fluids and methods for use in hydrocarbon reservoirs, and in particular to the use of degradable additives in treatment fluids.

BACKGROUND OF THE INVENTION

Oil and gas companies must develop as much of their hydrocarbon reserves as possible in an economical way. As such, completion and development processes are often based on the use of treatment fluids designed to address specific reservoir conditions through the use of one or more additives to enhance hydrocarbon production.

The required treatment fluid flow depends on the phase of the hydrocarbon recovery operation. During the production (or injection) phase of a well, it is generally desirable that the reservoir flow be as free as possible or have a velocity provided for by the well design. Conversely, it may be necessary for the various fluids to move into only one section of the formation or wellbore and not enter other sections during the drilling, completion, or workover phases. However, various treatment fluids may instead enter fractures, pore spaces, and natural or man-made fractures in formations, as well as other flow paths such as wellbore, well strings, perforation tunnels, slots, pipes, annulus, washouts. , solids buildup, void spaces in sand plug or proppant pack, screens and equipment for completion, maintenance or workover. As a result, there is often a loss of processing fluids, which reduces the efficiency of processing operations.

To prevent fluid loss, granular material is used to block/plug/shut certain flow paths in formations where flow or fluids are not desired. In this case, such a material should block the flow paths temporarily so that these flow paths can be reopened for subsequent operations.

Degradable materials of various types have been used for several decades to temporarily block flow paths in underground operations. These materials successfully block flow paths at high tank temperatures, but at low tank temperatures of 75°F to 140°F, blocking is problematic. Lower tank temperatures slow or stop the decomposition process. This makes it difficult to determine the recovery of permeability, since the rate of decomposition, if it occurs, may not be known at such low tank temperatures. This retardation of decomposition at low temperatures results in an increased risk of permanently blocking the flow paths.

In addition to degradation process uncertainty, degrading materials may also be affected by other additives such as salts, pH control additives, surfactants, thinners, biocides, crosslinkers, particulates, etc., which may be present when other processing agents are subsequently introduced. liquids. Unexpected reactions between undegraded material and related other additives may result in tank fouling, formation of insoluble contaminants or environmental contamination.

Therefore, additional measures (i.e. additional costs) are taken to remove residual decomposing material in these tanks to prevent unwanted reactions with subsequent treatment fluids and processes.

Despite advances in the development of degradable materials to block unwanted flow paths in tanks, there is a continuing need to develop improved formulations that can be used at lower tank temperatures. Preferably, these formulations can decompose at a known rate at a given tank temperature and do not react undesirably with other additives in the same treatment fluid or in fluids introduced subsequently.

SUMMARY OF THE INVENTION

Disclosed herein are treatment fluids for use in hydrocarbon reservoirs and methods for using treatment fluids. In particular, at least one member of the langbeinite family in particulate form is used as a degradable additive to treatment fluids used in well stimulation, fluid loss control, fluid diversion, and shutoff operations. Langbeinites are a family of crystalline substances with the general formula M _r M' _s X _t , where M is a monovalent cation, M' is a divalent cation, and X is a tetrahedral anion with a double negative charge. The granular langbainite material is capable of creating a temporary physical barrier to fluid flow (for example, by blocking a pore passage or filling an annulus region) and then slowly decomposing over time to remove the physical barrier, especially at lower reservoir temperatures from about 75°F (~23° C) up to approximately 140°F (~60°C). Thus, it can be added to a treatment fluid that can carry the granular langbeinite material to varying degrees from the injection site.

In some embodiments, the fluid may have a high content of langbainite material (about 20 pounds per gallon of carrier fluid), which allows it to form a coating on the downhole tool on the surface of the reservoir, or allows it to be formed into objects such as sleeves or plugs for slotted filters and other downhole tools. When a downhole tool is placed in the wellbore, the langbeinite-based plug or coating may decompose, exposing the plug or allowing the tool to be actuated.

Alternatively, the langbeinite-rich fluid may be shaped for use as a ball or plug to temporarily block flow in a channel, such as a tubing string or wellbore. Decomposition and removal of the plug (or ball) is then completed without mechanical intervention from the surface of the well. In addition, no decayed langbeinite-based plug (or ball) remains to contaminate the reservoir or to be removed using well fluids.

In addition to the langbainite material, the treatment fluids disclosed herein may contain other additional additives often used in treatment fluids that do not react undesirably with the langbainite material at low tank temperatures. These additional additives include, but are not limited to, salts, pH control additives, surfactants, thinners, biocides, crosslinkers, additional fluid loss control agents, stabilizers, chelating agents, scale inhibitors, gases, mutual solvents, particulate matter. , binders, proppants, corrosion inhibitors, oxidizers, reducing agents, friction reducers, and any combination thereof. These additional additives do not affect the ability of langbeinite to form a physical barrier, which allows the langbeinite material to be used for a variety of purposes, both in reservoir operations and wellbore operations. In some applications, the additive may help with physical blockage, as is the case with the use of additional fluid loss control agents. Thus, the langbainite material can be added to commonly used treatment fluids to provide physical blocking capability without affecting the intended performance of the remaining components of the treatment fluids.

Alternatively, a treatment fluid containing langbainite material can be combined with acids with a pH ≤ 3. The acids react with the langbainite material to increase its degradation rate. This allows the langbainite material to be used for temporary, but long-term, removal of liquids during acid treatment. Alternatively, the acid treatment fluid may be introduced into the tank or channel after the langbainite material has been placed therein, so that the langbeinite material is impregnated with acid, thereby causing accelerated decomposition of the langbainite material.

The present compositions and methods include any of the following embodiments in any combination(s) thereof:

A treatment fluid for treating a tank containing a carrier fluid and a granular langbeinite material.

A method for plugging a hole in a subterranean formation, characterized in that a treatment fluid containing a carrier liquid and a granular langbeinite material is injected into at least one section of the underground formation so that the hole is blocked by the granular langbeinite material, and the granular langbeinite material decomposes so that the hole is blocked temporarily. In the following steps, one or more fluids are passed through the temporarily occluded opening. An opening may be an annulus, a pipe string, a pipe, screens, slots, ports, voids in a sand plug or proppant pack, perforations, washouts, a hole and/or break in a pipe string or pipe, a natural fracture, a crack, channel, pore channel, man-made crack and/or formation surface. Alternatively, the hole is a porous section of a subterranean formation, wherein the treatment fluid is injected at fracturing pressure to fracture the subterranean formation, and the particulate langbainite material blocks the porous section to stop fluid loss in the porous section.

A method for shutting off a part of a wellbore, such as an annulus, a pipe string, a pipe, screens, slots, ports, an empty space in a sand plug or a proppant pack, perforations, washouts, holes, a break in a pipe string or pipe, characterized in that that a treatment fluid containing a carrier fluid and a particulate langbeinite material is injected into at least one section of the wellbore so that a portion of the wellbore is occluded by the particulate langbeinite material and the particulate langbeinite material decomposes so that the hole is temporarily occluded.

A method of temporarily closing at least one opening in a subterranean formation, such as natural faults, fractures, channels, pore channels, man-made fractures, or formation surface. In this method, a treatment fluid containing a carrier fluid and a granular langbeinite material is injected into a subterranean formation. The granular langbainite material blocks at least one hole in the subterranean formation and subsequently decomposes so that the hole is temporarily blocked.

A method for fracturing a subterranean formation using a treatment fluid containing a carrier fluid and a granular langbeinite material, characterized in that the treatment fluid is injected into the subterranean formation under fracturing pressure. The granular langbainite material seals off at least one porous section of a subterranean formation to stop fluid loss in the porous section by decomposing such that the porous section is temporarily blocked.

A method for temporarily blocking a flow in a channel using a plug formed by a composition containing granular langbeinite material, additional particles and/or binders. The formed plug can be placed in the channel to temporarily block the duct. The granular langbainite material within the formed plug may then decompose such that the duct opens. In further steps, one or more fluids or downhole tools are passed through the temporarily blocked flow. The flow path may be within a conduit, such as a well tubing string, a tubing string, a downhole tool, or other downhole equipment. The composition may be a liquid containing a carrier liquid with a high content of granular langbeinite material. The fluid may contain approximately 10 to 20 pounds of particulate langbainite material per gallon of fluid, allowing it to form into a plug. The plug can be of any shape necessary to block the channel.

A method for temporarily blocking at least one hole in a downhole tool using a composition containing granular langbeinite material and additional particles and/or binders. The composition can be formed into a sleeve and placed over at least one hole, as a plug shaped to fit the hole, or the composition can form a coating on the tool, creating a hard shell over the hole. After at least one hole is blocked with the composition, the downhole tool may be run in the wellbore. The particulate langbainite material within the formed sleeve, plug and/or cover may then decompose such that at least one opening is exposed. In further steps, one or more fluids are passed through at least one temporarily occluded opening. The composition may be a liquid containing a carrier liquid with a high content of granular langbeinite material. The fluid may contain approximately 10 to 20 pounds of particulate langbainite material per gallon of fluid, allowing it to be formed into any shape of plug or sleeve of any length, width, or thickness. Alternatively, the high content of granular langbainite material allows it to form a thick coating (about 0.5 to 5 inches thick) on the surface of the tool to temporarily block at least one hole.

Any of the above methods, further comprising the step of passing one or more liquids through the temporarily occluded opening.

Any of the above methods, further comprising the step of: selectively decomposing the granular langbeinite material by introducing an acid treatment fluid into the subterranean formation.

Any of the aforementioned methods or formulations, wherein the treatment fluid is used in tanks at bottomhole temperatures of 75°F (~23°C) to 140°F (~60°C).

Any of the aforementioned methods or formulations, wherein said treatment fluid has a pH of seven or less.

Any of the aforementioned methods or formulations further containing an acid, starch, surfactant, guar polymer, crosslinker, friction reducer, corrosion inhibitor, xylene, or any combination thereof in the treatment fluid.

Any of the aforementioned methods or formulations, wherein the treatment fluid further comprises at least one additive selected from the group consisting of salts, thickeners, pH control additives, surfactants, thinners, biocides, crosslinkers, additional loss control agents liquids, stabilizers, chelating agents, scale inhibitors, gases, mutual solvents, solids, corrosion inhibitors, oxidizers, reducing agents, friction reducers, and any combination thereof.

Any of the foregoing methods or compositions, wherein the particle size of the granular langbainite material is from about 4 mesh to about 150 mesh according to the US Sieve Scale.

Any of the foregoing methods or compositions, wherein the particle size of the granular langbainite material is from about 5 microns to about 4 mesh (US Sieve Scale) or from 5 to 50 microns US Sieve Scale.

Any of the above methods or formulations, wherein the carrier fluid is a saline solution, the particle size of the granular langbeinite material is from about 4 mesh (US Sieve Scale) to about 5 microns, and the pH of the treatment fluid is 6.

Any of the above processes or formulations, wherein the carrier fluid is a saline solution, the particle size of the granular langbeinite material is approximately 12-14 mesh (US Sieve Scale), and the pH of the treatment fluid is 6.

Any of the aforementioned methods or formulations, wherein the carrier fluid is seawater, the particle size of the granular langbeinite material is from about 4 mesh (US Sieve Scale) to about 5 microns, and the pH of the treatment fluid is 6.

Any of the above processes or formulations, wherein the carrier fluid is a saline solution, the particle size of the granular langbeinite material is approximately 12-14 mesh (US Sieve Scale), and the pH of the treatment fluid is 6.

Any of the aforementioned methods or formulations, wherein the carrier liquid is salt water with a NaCl concentration of about 2.5 to about 15%, the particle size of the granular langbainite material is from about 4 mesh (U.S. Sieve Scale) to about 5 microns , and the pH of the treatment fluid is 6.

Any of the aforementioned methods or formulations, wherein the carrier liquid is salt water with a NaCl concentration of about 2.5 to about 15% NaCl, the particle size of the granular langbainite material is about 12-14 mesh (U.S. Sieve Scale), and pH processing fluid is 6.

Any of the above methods or formulations, characterized in that the carrier liquid is pH neutral fresh water and the degree of decomposition for a given temperature in °F (T) and time in hours (t) can be calculated as follows:

Any of the aforementioned methods or compositions, wherein the particulate langbainite material is present in a volume of from about 50 pounds per thousand gallons ("ftg") of carrier fluid to about 400 ftg of carrier fluid.

Any of the aforementioned methods or formulations, wherein the granular langbainite material is present in less than 20 pounds per gallon of carrier fluid.

Any of the aforementioned methods or formulations, wherein the treatment fluid is used for stimulation, fluid loss control, fluid diversion, and occlusion operations.

Any of the above methods or compositions, wherein the granular langbeinite material is langbeinite.

Any of the above methods or compositions, characterized in that the granular langbeinite material is K₂mg₂(SO₄)₃, K₂Ca₂(SO₄)₃, K₂Mn₂(SO₄)₃, (NH₄)₂mg₂(SO₄)₃, K₂Mn₂(BeF₄)₃, K₂mg₂(BeF₄)₃, K₂Zn₂(BeF₄)₃, (NH₄)₂mg₂(BeF₄)₃, (NH₄)₂Mn₂(BeF₄)₃, Cs₂Ca₂(BeF₄)₃, Cs₂Mn₂(BeF₄)₃, (NH₄)₂Mn₂(SeO₄)₃, Cs₂Mn₂(CrO₄)₃or any combination of them.

Any of the above methods, characterized in that the treatment fluid is introduced alternately with the acidic treatment fluid.

A method of using any of the above formulations for stimulation, fluid loss control, fluid diversion, and shut-off operations, comprising the step of: injecting the compound(s) into a subterranean formation at a bottom hole temperature of 75°F (~23°C) to 140°F (~60°C) and block at least one hole in the underground formation with a granular langbeinite material. The granular langbainite material can then be left to decompose naturally or be selectively degraded with an acidic fluid. After decomposition, liquid may be passed through at least one temporarily blocked opening. The granular langbeinite material may be K₂mg₂(SO₄)₃, K₂Ca₂(SO₄)₃, K₂Mn₂(SO₄)₃, (NH₄)₂mg₂(SO₄)₃, K₂Mn₂(BeF₄)₃, K₂mg₂(BeF₄)₃, K₂Zn₂(BeF₄)₃, (NH₄)₂mg₂(BeF₄)₃, (NH₄)₂Mn₂(BeF₄)₃, Cs₂Ca₂(BeF₄)₃, Cs₂Mn₂(BeF₄)₃, (NH₄)₂Mn₂(SeO₄)₃, Cs₂Mn₂(CrO₄)₃or any combination of them.

Definitions

The terms "langbeinite material" and "langbeinite" are used interchangeably and denote the langbeinite family, a family of crystalline substances with a cubic structure: a small and a large cation and a tetrahedral anion with a double negative charge with the general formula M_rM'_sX_t, where M is a monovalent cation, M' is a divalent cation, and X is a tetrahedral anion with a double negative charge. The meaning of these terms is not limited to a specific langbeinite material, which is potassium and magnesium sulfate with the chemical formula K₂mg₂(SO₄)₃, while K₂mg₂(SO₄)₃ included in the meaning of these terms. Other examples of langbeinites include, but are not limited to, K2mg₂(SO₄)₃, K₂Ca₂(SO₄)₃, K₂Mn₂(SO₄)₃, (NH₄)₂mg₂(SO₄)₃, K₂Mn₂(BeF₄)₃, K₂mg₂(BeF₄)₃, K₂Zn₂(BeF₄)₃, (NH₄)₂mg₂(BeF₄)₃, (NH₄)₂Mn₂(BeF₄)₃, Cs₂Ca₂(BeF₄)₃, Cs₂Mn₂(BeF₄)₃, (NH₄)₂Mn₂(SeO₄)₃ and Cs₂Mn₂(CrO₄)₃.

The term "treating" or "treating" as used herein means any wellbore or subterranean operation that uses a fluid to perform a desired function and/or purpose. The term "processing" or "processing" does not refer to any particular action produced by the fluid or its components. Examples of treatment fluids include, but are not limited to, oxidizing fluids, fracturing fluids, gravel pack fluids, drilling or grinding fluids, lost circulation fluids, solvents, chemical stimulation fluids, repair fluids, completion fluids, cleaning fluids. , perforating fluids and jamming fluids.

The term "fluid loss" as used herein refers to the unwanted movement or loss of fluids and/or being lost to the subterranean formation and/or entering void space in the proppant pack.

The term "design temperature" as used herein means the calculated value or measurement data of the actual temperature in the well at the time of processing. In other words, the design temperature takes into account not only the static temperature at the bottom of the wellbore STZS ("BHST"), but also the effect of the temperature of the treatment fluid on the STZS during treatment. Since the treatment fluids can be much colder than the SCSS, the difference between the two temperatures can be quite large.

The term "reservoir temperature" as used herein refers to the bottomhole temperature of the reservoir. "Low tank temperature" is a tank temperature equal to or below 140°F (~60°C).

The terms "fracturing" and "fracturing" are used interchangeably and refer to a well stimulation technique in which the rock is fractured with a pressurized treatment fluid called "fracturing fluid". After the hydraulic pressure in the well is released, small granules of fracturing proppants (eg sand or alumina) seal the fractures. The burst pressure of the treatment fluid is very high, up to 15,000 psi, and the injection rate can be about 265 liters per second.

The term "acid treatment" is used to refer to a well stimulation technique in which an acid treatment fluid is injected into a reservoir to dissolve debris or scale in the reservoir, solids in the drilling fluid, and/or other soluble defects between reservoir rock grains or flow paths. . This treatment allows the natural productivity of the reservoir rock to be restored.

The terms "carrier fluid" and "base fluid" are used interchangeably to refer to a fluid used to transport materials into or out of a wellbore.

The term "derivative compound" as used herein means a compound derived from a similar compound in a chemical reaction. A derivative compound can be obtained, for example, by replacing one atom in a like compound with another atom or group of atoms, rearranging two or more atoms in a like compound, ionizing a like compound, or creating a salt of a like compound.

All concentrations in this document are in mass fraction (% mass fraction) unless otherwise indicated.

The term "foamed" as used herein means liquids mixed with a gas or mixed liquids.

The term "starch" or "starches" as used herein means a polysaccharide adhesive. Starch is a fluid loss control agent, but can also increase the viscosity of the carrier fluid if present in a high enough volume.

The use of the word "along" means to expand in a more or less constant direction with respect to something else, such as a wellbore or a fault surface.

The use of the word "any" in combination with the term "comprises" in a claim or specification means "one" or "more than one" unless the context suggests otherwise.

The term "approximately" means the specified value plus or minus the measurement error tolerance, or plus or minus 10% if the method of measurement is not specified.

The use of the word "or" in a formula means "and/or" unless it is expressly stated that it refers only to alternatives, or if the alternatives are not mutually exclusive.

The terms "comprise", "have", "comprise", and "comprise" (and their variants) are open linking verbs and allow other elements to be added when used in a formula.

The phrase "consist of" is closed and excludes all additional elements.

The phrase "consist essentially of" excludes additional essential elements, but allows the inclusion of non-essential elements that do not materially change the nature of the invention.

The following abbreviations are used in this document:

REDUCTION TERM STZS bottom hole static temperature ftg pounds per thousand gallons f/g pounds per gallon lb. lb.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1A-B. A downhole tool with a sleeve formed from a langbeinite-based fluid (FIG. 1A) and a downhole tool after langbeinite decomposition (FIG. 1B).

FIG. 2A-B. A downhole tool with a plug formed from a langbeinite-based fluid to block a hole in the downhole tool (FIG. 2A), and a downhole tool after decomposition of the langbeinite plug (FIG. 2B).

FIG. 3. A decomposing ball formed from a langbeinite-based liquid to temporarily close the hole.

FIG. 4. Decomposition of langbeinite over time in a pH-neutral solution.

FIG. 5. Comparison of the decomposition of langbeinite over time in a pH-neutral solution and in an acid solution.

FIG. 6. Comparison of langbeinite decomposition over time in pH neutral solution, salt water 5% NaCl, salt water 10% NaCl and sea water.

DISCLOSURE OF EMBODIMENTS

The present invention provides novel treatment fluid formulations using particulate langbeinite material and methods of use. Langbeinite material is a family of crystalline substances with a cubic structure, small and large cation, and a tetrahedral anion with a double negative charge. In particulate form, the langbainite material can form temporary physical barriers in the reservoir, particularly in reservoirs with bottomhole temperatures ranging from 75°F (~23°C) to 140°F (~60°C). After some time, the langbeinite material decomposes naturally, thus removing the physical barrier. Alternatively, the langbainite material can be removed before it is completely decomposed by absorbing it with a treating acid (pH ≤ 3). This allows the operator to controllably block certain areas of porous formation and holes or other areas in the reservoir or downhole tool for any period of time without creating a permanent blockage. Also disclosed are methods for using langbainite material in various treatment fluid formulations.

In more detail, langbeinites are a family of crystalline substances with the general formula M _r M' _s X _t , where M is a monovalent cation, M' is a divalent cation, and X is a tetrahedral anion with a double negative charge. The treatment fluid formulations disclosed herein use langbainite materials that are environmentally friendly and soluble at tank temperatures of 140°F (~60°C) or lower. Thus, the langbainite material used in these compositions and methods consists of a large monovalent cation (M) selected from the following group of substances: potassium, cesium and/or ammonium; a small divalent cation (M') selected from the following group of substances: magnesium, calcium, manganese, iron and/or zinc; and a tetrahedral anion with a double negative charge (X) from the following group of substances: sulfate (SO ₄ ² ), tetrafluoroberyllate (BeF ₄ ^2– ), selenate (SeO ₄ ^2– ) and chromate (CrO ₄ ^2– ).

Examples of langbainite material include but are not limited to K₂mg₂(SO₄)₃, K₂Ca₂(SO₄)₃, K₂Mn₂(SO₄)₃, (NH₄)₂mg₂(SO₄)₃, K₂Mn₂(BeF₄)₃, K₂mg₂(BeF₄)₃, K₂Zn₂(BeF₄)₃, (NH₄)2Mg2(BeF₄)₃, (NH₄)₂Mn₂(BeF₄)₃, Cs₂Ca₂(BeF₄)₃, Cs₂Mn₂(BeF₄)₃, (NH₄)₂Mn₂(SeO₄)₃ and Cs₂Mn₂(CrO₄)₃. In some embodiments, the langbeinite material is langbeinite. The chemical formula of langbeinite is K₂mg₂(SO₄)₃, a Mohs hardness of 3.5 to 4, and a specific gravity of approximately 2.83. Langbeinite is an inexpensive and readily available material that can reduce the cost of various wellbore and reservoir treatments.

The new formulation of the treatment fluid contains a carrier fluid and granular langbeinite material, as well as other additional additives. In some embodiments, the treatment fluid composition is introduced into the wellbore by penetrating the boards, wherein the carrier fluid carries the granular langbeinite material some distance from the injection site. The treatment fluid is distributed underground through openings or porous zones in the reservoir rock, which may occur naturally (fractures, cracks and crevices) or be of technological origin, such as the space between installed pipes or between a wellbore and a pipe (wellbores, perforations). and cracks). After the treatment fluid is placed in the reservoir, the granular langbainite material flows from the treatment fluid into the formation or annulus and is driven into the holes depending on the selected particle size of the granular langbainite material. The compacted granular langbainite material can then be used as a fluid loss control agent, diversion agent, or bridging agent, directing additional injection fluids to other areas of the reservoir or annulus.

The methods disclosed herein use granular langbainite material in many different types of treatment fluids for a variety of subsurface processing operations, including stimulation, fluid loss control, lost circulation, fluid diversion, and capping.

Alternatively, the composition may have a high content of granular langbainite material such that it may be formed into a sleeve or other coating to temporarily block holes in downhole tools or form plugs to block channels in channels. As another option, the composition may form a coating on the surface of the downhole tool. A suitable coating may be 0.5 to 5 inches or 1 to 3 inches thick.

When fluid loss control is required, new treatment fluid formulations can be used in methods to perform fracturing, oxidation, scaling retardation, water blocking, clay stabilization, biocide, fracturing, gravel pack fracturing operations. , and gravel pack operations, as fluid loss is problematic for these operations.

In fracturing operations, for example, loss of fluid in the formation can result in a reduction in the efficiency of the fluid such that the fracturing fluid cannot increase the fracture as needed. Accordingly, fluid loss control materials are added to the fracturing fluid to reduce the volume of filtrate passing through the filter media. In other words, fluid loss control materials block pore channels and spaces that would otherwise allow fluid to flow from the desired zone to the unwanted zone. In the present methods, the granular langbainite material can be used as a fluid loss control material in underground treatment fluids, filling/bridging voids in formation rock and/or packing with a proppant, or contacting the surface of the formation and/or packing with a proppant, thereby forming its own a kind of filter cake that blocks voids in the formation or in the packing with proppant and prevents loss of fluid in it. The treatment fluid containing the langbainite material may be alternated with the fracturing fluid at such intervals that the first section of the formation is fractured and shut off prior to subsequent injection of the fracturing fluid.

In some embodiments, the novel treatment fluid formulations are fracturing fluids and the particulate langbainite material is used as a fluid loss control agent. When used in fracturing operations, this new treatment fluid formulation is injected at a pressure/velocity sufficient/sufficient to form or expand at least one fracture in the appropriate section of the subterranean formation where the carrier fluid carries particulate langbeinite material to the section of the reservoir where it was break has been made. The granular langbainite material can then provide fluid loss control along the fracture face.

For fluid diversion methods, a treatment fluid containing a diversion material is used to seal a section of a subterranean formation. The methods disclosed herein include the step of introducing new treatment fluid formulations into the formation, the granular langbeinite material being the diversion material used to seal a section of the formation. The granular langbeinite material fills the widest pores, gaps or cracks until the corresponding section of the formation is covered and compacted. This allows the second fluid to be redirected from the newly compacted high permeability portions of the formation to lower permeability portions of the formation or to new areas requiring treatment. The steps of introducing the granular langbainite material and the second fluid may be repeated until the required number of treatment fluid injection steps has been completed.

For methods used in bridging operations, particulate langbainite material in new treatment fluid formulations is used as a bridging agent to seal the wellbore, providing zonal isolation. In this method, a new composition of the treatment fluid is introduced such that the granular langbainite material seals the wellbore surface, preventing liquids from entering the porous areas, before the bridging agent (granular langbainite material) is decomposed or removed. In some method embodiments, it may be necessary to use a granular langbeinite material for bridging operations to completely fill the annulus along the wellbore.

In other embodiments, the particulate langbainite material is present at a high concentration of about 10 to about 20 pounds per gallon of the carrier fluid, which allows it to form sleeves or other coatings to block holes in downhole tools or as plugs for downhole tools or passages. FIG. 1A represents one such embodiment, where a granular langbeinite material was used to form a sleeve (100) to cover and block holes (102) in the downhole tool (101). After the tool is installed in the well (103), the granular langbeinite material can decompose and open the holes (102), as shown in FIG. 1B by allowing liquid or other material to pass through. Although not shown in FIG. 1A, the particulate langbainite material may also wrap around the surface of the downhole tool (101) to cover and block the holes.

FIG. 2A shows an alternative plug (200) formed from a composition containing particulate langbainite material. The shape and size of the plug can be changed to fit the shape of a port or other opening. The plug is placed in a port and/or other opening in a downhole tool or other equipment (201) at the surface prior to installation in the wellbore (not shown). Once installed, the granular langbainite material can decompose, opening port (202) and allowing flow.

FIG. 3 shows a ball formed from a composition containing granular langbeinite material. The ball (300) may be placed in a channel or other duct (302) to temporarily block the orifice. The flow path (302) may be located within a bore in a downhole tool or other equipment, or may be located in a wellbore or tubing string. Such balls are often used in multiple downhole operations, including tool launching or flow blocking operations. Although the ball (300) is shown in a spherical shape in FIG. 3, the ball can be any shape needed to block the hole.

With respect to the novel formulations disclosed herein, the treatment fluid contains a carrier fluid, also known as a base fluid, which may be water-based, non-aqueous, foamed or emulsified. It may include, but is not limited to, fresh water, salt water, brine (salt-saturated water), sea water, produced water (subterranean formation water brought to the surface), surface water (e.g., lake or river water), and return flow water (water introduced into an underground reservoir and then raised back to the surface). In some embodiments, the carrier fluid is one of the following fluids: fresh water, salt water, brine, and sea water. Salt water may have a NaCl concentration of about 2.5% w/w to about 15% w/w. In other embodiments, the carrier fluid is a saline solution.

A foamed carrier fluid may be required in certain methods to reduce the volume of fluid required in a water susceptible formation, to reduce fluid loss in the formation, and/or to provide more secure proppant anchorage. For novel gas-foamed treatment fluid formulations, any gas can be used, including nitrogen, carbon dioxide, air, or methane. The gas concentration may be from about 5% to about 98% by volume of the treatment fluid, or alternatively, in the range from about 20% to about 80% by volume of the treatment fluid. The volume of gas to include in the fluid can be determined by many factors, including fluid viscosity and bottom hole pressure in a particular application. In this case, a person skilled in the art will be able to determine what volume of gas, if necessary, should be added to the foamed treatment fluid of the presented composition for selected operations.

In other embodiments, the novel treatment fluid formulations may be an aqueous acid solution, for example where the treatment fluid also acts as an oxidizing fluid. The aqueous acid solution may include one or more acids such as hydrochloric acid, acetic acid, methane acid, and other organic acids, so that the pH of the treatment liquid is low, about 3 or lower.

In other embodiments, the novel treatment fluid formulations are viscous, especially when using a large volume of particulate langbainite material. In fracturing operations, hydraulic fracturing operations combined with gravel packing, gravel pack operations, or other operations conducted either to accommodate solids or to stimulate the formation, the viscous treatment fluid must carry the granular langbainite material to the desired location. Accordingly, new treatment fluid formulations may further include thickeners and possibly crosslinkers.

The choice of particulate langbainite material for a new treatment fluid formulation for the desired use depends on a number of factors including (1) particle size of the langbeinite material, (2) content of langbainite material in the treatment fluid, (3) pH of the treatment fluid, and (4) design temperature. Factors 1 and 2 are associated with the characteristics of the granular langbainite material that allows it to provide hole bridging, and factors 3 and 4 are associated with the solubility of the granular langbainite material.

Particle size influences the choice of granular langbeinite material. Granular langbainite material flows from the treatment fluid into the formation, where it is driven into the holes. Accordingly, the particle size of the material must be selected depending on the calculated size of the holes to be closed.

The particle size of the granular langbainite material used in the present formulations can range from about 4 US sieve mesh to about 150 US sieve mesh, and the size(s) chosen will depend on the application. Alternatively, the particle size of the granular langbainite material may be from 5 microns to 50 microns, or from 4 mesh (US Sieve Scale) to 5 microns. To bridge and plug fractures in the bottom hole zone, the particles can be in the range from about 4 mesh to about 5 microns. In contrast, the particle size of particulate langbainite material when used to control fluid loss at fractures can vary from about 100 mesh to about 5 microns. For remote liquid disposal methods, the particle size can be in the range of about 60 mesh to about 5 microns. For treatments used to compact a gravel pack or proppant pack, langbainite material with a particle size of from about 50 mesh to about 5 microns can be used, and the size of langbainite screen material can be from about 12 mesh to about 5 microns. Even larger particles of langbeinite material, which can be as small as 1 inch, may be required to bridge gaps, ports, or perforations.

New treatment fluid formulations may contain particulate langbeinite material with a single particle size or a combination of two or more particle sizes. Some embodiments of the new treatment fluid formulations use a combination of two or more particle sizes of particulate langbeinite material to provide fluid loss control or fluid diversion, such as a 12/14 mesh combination or use of sizes ranging from 5 to 50 microns.

The content of langbainite material in the treatment fluid influences the choice of granular langbainite material. Since the particulate langbainite material is used as a fluid loss control agent, a diverting agent, or a capping agent, its content depends on the application. The methods disclosed herein require large volumes of granular langbainite material for bridging operations to completely close the flow paths, rather than simply blocking pore channels or the rock surface as is required for fluid diversion or fluid loss control methods. A person skilled in the art will be able to select the desired content of granular langbainite material to add to a new treatment fluid composition, depending on, among other things, the use of the treatment fluid.

In some embodiments, the particulate langbainite material may be added to a treatment fluid containing a non-foamed carrier fluid in an amount as low as about 10 pounds per thousand gallons ("ftg") or about 20 pounds per gallon ("lb/g") of carrier fluid. Alternatively, the particulate langbainite material may be added to the non-foamed carrier fluid in an amount of from about 10 to about 500 ftg, or from 50 ftg to about 400 ftg, or from about 100 ftg to about 300 ftg, or from about 10 ftg to about 100 ftg , or from about 10 ftg to about 50 ftg, or from about 200 ftg to about 400 ftg, or from about 50 to about 150 ftg. This relatively high content of granular langbainite material provides enough to seal holes, control fluid loss, or drain fluids as needed. Foamed carrier fluids have reduced carrying capacity, depending at least in part on foam density.

The pH of the treatment fluid influences the choice of granular langbeinite material. Given the relatively low solubility (i.e., degradation) of granular langbeinite material, new treatment fluid formulations are pH neutral or lower (pH ≤ 7). In some embodiments, for example when the treatment fluid also acts as an oxidizing fluid, the pH may be very low (pH ≤ 3). Alternatively, the pH of the treatment fluid is in the range of about 4 to about 7, or 0 to about 3, or about 3 to about 5.

The lower pH has the advantage of reducing the formation of magnesium hydroxide (Mg(OH) ₂ ) from the decomposition of the langbeinite material containing magnesium. Mg(OH) ₂ is insoluble and can damage the reservoir, so its formation is prevented by lowering the pH.

The choice of granular langbainite material is influenced by the design temperature.

The design temperature affects the solubility of the particulate langbeinite material and can be used to estimate the length of time the particulate langbeinite material will block a hole before decomposing. At optimum pH and content, the particulate langbainite material provides a physical hole block for approximately 3 to 14 hours at tank temperatures from 75°F (~23°C) to approximately 140°F (~60°C). At temperatures below 75°F (~23°C) the rate of decomposition is reduced, allowing for longer block times. At temperatures above 140°F (~60°C) the rate of decomposition increases, reducing the period of time during which the particulate langbainite material can block the hole. As the temperature rises (>125°F (~52°C)) and the pH decreases (≤ 3), the rate of decomposition of the particulate langbainite material increases, reducing the period of time that the particulate langbainite material can block the hole. Accordingly, it may be necessary to use a particulate langbainite material with an elevated pH carrier fluid (i.e., 3 < pH ≤ 7) and introduce it in multiple steps with a lower pH fluid.

In some embodiments, new treatment fluid formulations are introduced into tanks having a design temperature ranging from about 75°F (~23°C) to about 140°F (~60°C) or from about 75°F (~23°C) to approximately 100°F (~38°C), or from approximately 110°F (~43°C) to approximately 140°F (~60°C), or from approximately 95°F (35°C) to approximately 125 °F (~52°C).

Regardless of the application, the total time required for the granular langbainite material to decompose and dissolve in a liquid in a low temperature tank is from about 3 hours to about 14 hours, depending on the temperature of the subterranean area into which it is introduced. However, the rate of decomposition may vary to some extent depending on the particle size and other additives that may be present in the treatment fluid.

For embodiments in which a blocking period must be set, the particulate langbeinite material can be removed before it decomposes by impregnating the material with an acid solution (pH ≤ 3). This acid solution increases the rate of decomposition of the granular langbeinite material.

Depending on the application of the treatment fluid containing particulate langbainite material, additives may be included in the carrier fluid to meet other needs of the reservoir or wellbore without affecting the ability of the particulate langbainite material to block holes.

In some embodiments, the additives help provide the langbainite material with fluid loss control, fluid drainage, and hole bridging. Alternatively, additives have functions other than fluid loss control, fluid diversion, and orifice bridging. Thus, treatment fluids may additionally contain optional additives including, but not limited to, salts, pH control additives, surfactants, thinners, biocides, crosslinkers, additional fluid loss control agents, stabilizers, chelating agents, scale inhibitors, gases. , mutual solvents, particulate matter, corrosion inhibitors, oxidizers, reducing agents, friction reducers, and any combination thereof.

In more detail, new treatment fluid formulations using particulate langbainite material can be combined with additional additives such as:

Thickeners and crosslinkers . In particular, it may be necessary to add a viscosifier to the treatment fluids disclosed herein during fracturing and gravel packing operations. Thickeners can be any substance (eg, a polymeric material) capable of increasing the viscosity of the treatment fluids. In certain embodiments, the viscosifying agent may be one or more polymers capable of being crosslinked in a crosslinking reaction in the presence of a crosslinking agent and/or polymers having at least two crosslinked molecules (i.e., a crosslinked viscosifier). Thickeners may be biopolymers, polysaccharides and/or compounds derived from them containing one or more of the following monosaccharides: galactose, mannose, glucose, xylose, arabinose, fructose, glucuronic acid or pyranosyl sulfate. Examples of thickeners for the present methods and formulations include, but are not limited to, cellulose derivatives, carboxymethyl guar, carboxymethyl hydroxypropyl guar, hydroxyethyl cellulose, carboxyethyl cellulose, carboxymethyl cellulose, carboxymethyl hydroxyethyl cellulose, diutan gums, xanthan gum, galactomannans, hydroxyethyl guar, hydroxypropyl guar, scleroglucans, welan gums, starch, and any compounds derived from them, and any combination thereof.

The thickener may be present in an amount sufficient to provide the desired viscosity. In some embodiments, viscosifiers may be present in a volume ranging from about 0.01% to about 10% by weight, based on the treatment fluid. In other embodiments, the thickeners may be cellulose derivatives present in a volume ranging from about 0.1% to about 1% by weight, based on the treatment fluid. In other embodiments, the thickeners may be starch present in a volume in the range of from about 3% to about 5% by weight based on the treatment fluid, or from about 5 to 10 ftg of the carrier fluid. In other embodiments, the viscosifiers may be guar present in about 10 to 50 ftg of treatment fluid, or about 10 to 25 ftg of carrier fluid, or about 30 to 50 ftg of carrier fluid, or 30 ftg of carrier fluid. In other embodiments, the thickeners may be polysaccharides present in a volume ranging from about 0.1% to about 3% by weight, based on the treatment fluid. In some embodiments, the thickener may be a mixture of polysaccharide and starch.

In those embodiments of the composition of the treatment fluid, where crosslinking of the thickener is required, the treatment fluid may contain crosslinking agents. Crosslinking agents may contain a metal ion or a similar component capable of crosslinking at least two thickener molecules. Examples of crosslinkers include but are not limited to magnesium ions, zirconium ions, titanium ions, aluminum ions, antimony ions, chromium ions, iron ions, copper ions, magnesium ions, and zinc ions. These ions can be obtained from any compound capable of producing one or more of these ions, as is known to those skilled in the art. Examples of such compounds include but are not limited to ferric chloride, magnesium oxide, zirconium lactate, zirconium triethanolamine, zirconium lactate triethanolamine, zirconium carbonate, zirconium acetylacetonate, zirconium malate, zirconium citrate, zirconium diisopropylamine lactate, zirconium glycolate, zirconium acetate lactate, zirconium triethanolamine glycolate, zirconium lactate glycolate, zirconium triisopropanolamine lactate, titanium lactate, titanium malate, titanium citrate, titanium ammonium lactate, titanium triethanolamine and titanium acetylacetonate, aluminum lactate, aluminum citrate, aluminum acetate, antimony compounds, chromium (III) compounds, compounds iron(II), iron(III) compounds, copper compounds, zinc compounds, and combinations thereof. In certain embodiments, the crosslinker may be formulated to be inactive until "activated", including by certain fluid conditions (eg, pH, temperature, etc.) and/or by interaction with some other substance. Alternatively, a crosslinking agent may be used, wherein the ionic compound is one of the following: ammonium zirconium carbonate, zirconium citrate, zirconium lactate citrate, zirconium oxide, titanium dioxide, aluminum nicotinate, aluminum sulfate, aluminum sodium sulfate, sodium sulfate aluminum ammonium, chromium caseinate, chromium potassium sulfate, zinc sulfate, zinc hydrosulfite, magnesium chloride, magnesium sulfate, magnesium gluconate, copper sulfate and copper gluconate.

Crosslinkers may be present in the treatment fluids in a volume sufficient to provide the desired degree of crosslinking between the thickener molecules. In certain embodiments, the crosslinker may be present in a volume of from about 0.005% to about 1% by weight, based on the treatment fluid. Alternatively, the crosslinker may be present in a volume of from about 0.05% to about 0.1% by weight, based on the first treatment fluid and/or the second treatment fluid.

The crosslinkers may be added in concentrated solution, the values mentioned above referring to the mass fraction of metal ions as a percentage of the treatment liquid. One skilled in the art will be able to select the appropriate amount of crosslinker to add to the treatment fluid based on, but not limited to, the temperature conditions of the particular application, the type of thickener used, the molecular weight of the thickeners, the degree of viscosity increase required, and/or the pH of the treatment fluid.

More viscous fluids require more power to pump, especially when attempting to pump fluid a significant distance from the injection site. Accordingly, it may be necessary to delay the crosslinking of the treatment fluids until the fluid has reached the area to be treated. This delay will allow the operator to pump the non-crosslinked (and therefore less viscous) fluid a greater distance before needing more power to move the more viscous crosslinked fluid. Those skilled in the art are aware of existing methods of delaying crosslinking, such as encapsulation, chemical delays (e.g., the use of chelating agents), etc. the agent may slowly spread, or degradable coating decomposing in the well), delaying the release of the crosslinking agent for the desired length of time, or until the liquid reaches the desired location.

solid particles. The novel treatment fluids disclosed herein may additionally contain optional solid particles, including proppant or gravel particles. Such particulate matter may be included in treatment fluids when, for example, gravel packing is required in at least one section of a wellbore or proppant pack in one or more subterranean formation faults.

Solid particles that can be used in the treatment fluids and methods disclosed herein may include any material used in underground operations, including, but not limited to, sand, bauxite, ceramic materials, glass materials, polymeric materials, polytetrafluoroethylene materials, nutshell fragments, hardened resin particles containing nut shell fragments, seed coat fragments, hardened resin particles containing seed coat fragments, fruit stone fragments, hardened resin particles containing fruit stone fragments, wood, composite materials, and combinations thereof. Exemplary solid composite particles may contain a binder and an aggregate, and the aggregates include silicon, aluminum, carbon deposits, carbon black, graphite, mica, titanium dioxide, calcium silicate, kaolin, talc, zirconium, boron, fly ash, hollow glass microspheres , whole glass and their combinations.

The additional solid particles disclosed herein may be in any form. Depending on the application, any form of material may be used, including substantially spherical materials, fibrous materials, polygonal (eg, cubic) materials, and combinations. For example, fibrous materials may or may not be used under closed fracture pressure in fracturing operations, but may be included in fluid loss control operations. In some embodiments, the solid particles may be coated with an appropriate resin or tackifier known to those skilled in the art.

The average size of these additional solids can range from about 2 mesh to about 400 mesh US Sieve Scale. However, in certain circumstances, a different average particle size may be required, which will be fully suitable for use in the framework of the present disclosed methods. In some embodiments, one or more of the following average particle size ranges are used: 6/12, 8/16, 12/20, 16/30, 20/40, 30/50, 40/60, 40/70, 50/70, or 70/140 mesh or down to 200 mesh or 10 microns. Additional solids may be present in the treatment fluids in a volume of from 0.5 pounds per gallon ("lb/g") to about 30 lb/g of the volume of the treatment fluid.

Additives for pH control. pH control additives may be necessary to maintain the pH of the treatment fluid at the desired level to increase the effectiveness of certain thinners or crosslinkers, etc. Examples of pH control additives that can additionally be added to the treatment fluids in the present invention are base formulations and/ or acids. One skilled in the art will be able to determine the correct pH for a particular application.

Surfactants. In some embodiments, the treatment fluids within the scope of the present invention may include additional surfactants to increase the compatibility of the treatment fluids with other fluids (such as formation fluids) that may be present in the well. One skilled in the art will be able to determine the type of surfactant and the appropriate concentration of surfactant needed for use.

Surfactants can be used in liquid or powder form. When used, surfactants may be present in the treatment fluid in a volume sufficient to prevent incompatibility with formation fluids, other treatment fluids, or wellbore fluids. In the embodiment where liquid surfactants are used, the surfactants are present in a volume of from about 0.01% to about 5.0% by volume of the treatment fluid. In other embodiments, liquid surfactants are present in a volume of from about 0.1% to about 2.0% by volume of the treatment fluid. In other embodiments, the liquid surfactants are present in a volume of greater than 0 to about 10 ftg of carrier liquid, or about 2 to about 7 ftg of carrier liquid, or 1 ftg of carrier liquid. In embodiments where powdered surfactants are used, the surfactants are present in a volume of from about 0.001% to about 0.5% by weight based on the treatment fluid.

In embodiments where it is desired to foam the treatment fluid of the present invention, surfactants such as HY-CLEAN (HC-2) surfactant suspending agent or AQF-2 additive commercially available from Halliburton Energy Services, Inc., can be used. Duncan, Oklahoma. Additional examples of blowing agents that can be used to foam and stabilize treatment fluids include, but are not limited to, betaines, amine oxides, methyl ester sulfonates, alkylamido betaines such as cocamidopropyl betaine, alpha olefin sulfonate, trimethyltallow ammonium chloride, C8-C22 alkyl ethoxylate sulfate, and trimethylcocoammonium chloride. Other blowing agents and foam stabilizing agents may also be included and will be known to those skilled in the art.

Thinners. In some embodiments of the present invention, the treatment fluids may contain diluents.

Examples of diluents for use in the disclosed treatment fluids include, but are not limited to, sodium chlorites, hypochlorites, perborates, peroxosulfates, and peroxides (including organic peroxides). Other breakers include, but are not limited to, acids and peroxide breakers, bond breakers, and enzymes, which may be effective in breaking thickened process fluids. In some embodiments, the diluent may be citric acid, tetrasodium EDTA, ammonium persulfate, or cellulose enzymes.

The thinner may be included in a volume and form sufficient to achieve the desired viscosity reduction at the desired point in time. The breaker may be formulated to provide delayed liquefaction or may be encapsulated. Encapsulation methods are known to those skilled in the art, and exemplary methods of encapsulation may include coating the selected breaker with a porous material to release the breaker at a controlled rate, or coating selected breaker with downhole degradable material to release the breaker at the desired time. Resins that may be used in the present formulations include, but are not limited to, downhole degradable polymeric materials.

Alternatively, thinners can be encapsulated with synthetic and natural waxes. Waxes with different melting points can be used to control the liquefaction delay depending on the temperature of specific underground operations. Thinner encapsulation is accomplished by mixing the thinner and wax at a temperature above the melting point for the particular wax and then extruding the composition to form small particles of encapsulated material. The resulting product can be calcined by rapidly heating the product to a temperature that closes cracks in the coating, thus preventing premature release of the substance. Encapsulation can also be achieved by spraying the liquid phase wax onto the diluent particles (eg citric acid) or by other means known to those skilled in the art. If used, the diluent is included in the disclosed treatment fluid in a volume sufficient to provide the desired reduction in the viscosity of the treatment fluid. For example, the possible concentration of peroxide varies from about 0.1 to about 30 gallons of peroxide per 1000 gallons of treatment fluid. Similarly, if, for example, citric acid is used as a diluent, a concentration of 0.11 fg to 30 fg is possible.

Additionally, an activating agent or retarder may be used, including to optimize the rate of liquefaction provided by the breaker. The present treatment fluids may use any known activating agent or retarder that is compatible with the selected breaker. Examples of activating agents include, but are not limited to, acid forming materials, chelated iron, copper, cobalt, and reducing sugars. Examples of moderators include sodium thiosulfate, methanol and diethylenetriamine. One skilled in the art will be able to determine the activating agent or retarder to be used with the selected fluid and the desired concentration of such activating agent or retarder for a given application.

In some embodiments, the retarder or activating agent may be used in a volume of from about 1 to about 100 ftg of carrier fluid, or from about 5 to about 20 ftg.

One skilled in the art will be able to determine the activating agent or retarder to be used with the selected fluid and the desired concentration of such activating agent or retarder for a given application.

Additives to control fluid loss. In some embodiments of these disclosed treatment fluids, additional fluid loss control additives may be combined with the particulate langbainite material disclosed herein. Examples of such additional fluid loss control agents include, but are not limited to, starch (e.g., IN-DRIL® HT Plus, commercially available from Halliburton Energy Services, Inc., Duncan, Oklahoma), polylactide, other aliphatic esters , silica flour, gas bubbles (carbonated liquid or foam), benzoic acid, soap, resin particles, relative permeability modifiers and other immiscible liquids. If included, an additional fluid loss control additive may be included in a volume of from about 5 to about 2000 ftg of treatment fluid.

In some embodiments, the additional fluid loss control additive may comprise up to 75% of the total fluid loss control additive present. Alternatively, the particulate langbainite material may contain the largest particles in a range of particle sizes used as a fluid loss control additive. For some fluid additives that function as fluid loss control additives, they may be included in a volume of from about 0.01% to about 20% by volume; in some embodiments, they may be included in a volume of from about 1.0% to about 10% by volume.

Starch can be used in the treatment fluid as a fluid loss control agent, but can also increase the viscosity of the carrier fluid if present in a high enough volume. As such, starch may be present in the fluid in a volume of 10% to 0.1% by weight, based on the treatment fluid, or 1 to 10 pounds.

In other embodiments, it may be desirable to use particulate langbainite material without using a large volume of another fluid loss control additive. That is, approximately 75-100% reduction in fluid loss should be achieved through the use of langbeinite, and not through the use of an additional additive to control fluid loss. In some embodiments, the treatment fluid composition disclosed herein contains substantially no fluid loss control material other than particulate langbeinite material.

corrosion inhibitors . In some embodiments of the treatment fluid formulation disclosed herein, the langbeinite material particles may be combined with corrosion inhibitors. Corrosion inhibitors are mixed with the treatment fluid to protect the metal components that the fluid comes into contact with. This is especially useful in acidizing to protect iron and steel components in the wellbore and processing equipment from corrosive working fluid.

Corrosion inhibitor activating agents, such as quaternary ammonium compounds, are often added to activate corrosion inhibitor components. Examples of corrosion inhibitor activating agents that can be used in accordance with these treatment fluids include, but are not limited to, copper compounds such as copper iodide and copper chloride; antimony compounds such as antimony oxide, antimony halide, antimony tartrate, antimony citrate, alkali metal salts of antimony tartrate and antimony citrate, alkali metal salts of pyroantimonate, and ethylene glycol antimony adducts; bismuth compounds such as bismuth oxides, bismuth halides, bismuth tartrate, bismuth citrate, alkali metal salts of bismuth tartrate and bismuth citrate; iodine, iodine compounds; formic acid; and their combinations. If a corrosion inhibitor is included in the treatment fluid, it may be present in the range of from about 0.1% to about 5.0% by weight based on the treatment fluid.

friction reducers. In some embodiments of the composition of the treatment fluids disclosed herein, particles of langbeinite material may be combined with friction reducers. Friction reducers help improve injection efficiency in hydraulic fracturing. The addition of friction reducers to treatment fluids allows fracturing fluids and langbainite material to be pumped into the target zone at a higher rate and at lower pressure than fluids without friction reducers. Examples of such friction reducers include but are not limited to polyacrylamide derivatives and low concentration copolymers. In some embodiments, the friction reducer can be from about 0.1% to about 1% of the treatment fluid, or about 1 lb of the treatment fluid.

Because the particulate langbeinite material can be combined with various known oil and gas treatment fluid additives without reducing the physical blocking ability of the langbeinite, the particulate langbeinite material can be used for a variety of purposes. Its versatility allows the granular langbainite material to be used for a variety of applications including stimulation, fluid loss control, fluid diversion and occlusion.

The following disclosure demonstrates various embodiments of exemplary treatment fluids, is illustrative, and does not limit the scope of the appended claims. It will be apparent to those skilled in the art that changes may be made to the specific disclosed embodiments to obtain a similar or similar result without deviating from the spirit and scope of the present invention. In no event should the following examples be construed as limiting or defining the scope of the appended claims.

One embodiment of the present formulation is a fluid loss control treatment fluid in a high permeability (>50 mD) formation that is being perforated. After perforating between the wellbore and the formation, it is necessary to control the loss of fluid in the formation when the perforator assembly is lifted out of the wellbore and the gravel pack is lowered into the wellbore. One way to control fluid loss is to physically block the orifice through which the fluid escapes using a particulate material. A treatment fluid composition containing saline, xanthan, starch, and a granular langbeinite material sized to physically block these holes can be prepared and introduced into the tank prior to lifting the gun assembly. The starch and xanthan increase the viscosity of the carrier brine, allowing the granular langbeinite material to be transported to the orifices into which it enters from the carrier fluid. Alternatively, the treatment fluid composition may contain about 1 barrel of saline, 0.7 pounds of xanthan, 7 pounds of starch, and about 10-100 pounds of granular langbainite material with a particle size of about 5 to about 50 microns. Alternatively, the treatment fluid composition may contain about 1 barrel of saline, 0.7 pounds of xanthan, 7 pounds of starch, and about 40 pounds of granular langbainite material with a particle size of about 5 to about 50 microns.

Another variation of the present formulation may be a medium to high permeability (10-25 mD) fracturing treatment fluid. When fracturing a formation with medium and high permeability, a significant volume of the base fluid of the fracture can leak through the walls of the fracture. This loss of base fluid makes it difficult to perform fracturing operations at the planned location. A treatment fluid containing a base fracturing fluid, a guar polymer with a crosslinker, a surfactant, and a granular langbainite material to block fluid loss can be prepared and introduced into the reservoir. As in the example above, the guar/crosslinker increases the viscosity of the base fluid, allowing the particulate langbainite material to be transported to the fracture walls where it enters from the base fluid. Alternatively, the treatment fluid formulation may contain approximately 1,000 gallons of base fracturing fluid and 30 pounds of crosslinked guar, 1 gallon of surfactant, and approximately 10-200 pounds of 15 micron granular langbainite material per 1,000 gallons of base fracturing fluid. As another option, the treatment fluid formulation may contain approximately 1000 gallons of base fracturing fluid and 30 pounds of crosslinked guar polymer, 1 gallon of surfactant, and approximately 50 pounds of 15 micron particulate langbainite material per 1000 gallons of base fracturing fluid.

Another embodiment of the present formulation may be a treatment fluid used to divert fluids in a shale formation in a long horizontal well. When fracturing shale formations, hydraulic fracturing is carried out in several stages to improve the contact of the surface area with the formation. To perform these multiple steps, the formation is fractured, which is then isolated by injecting treatment fluids with flow diverters. This allows additional fracturing fluid to be pumped into the formation in the next step. A fluid diverting treatment fluid containing a fracturing base fluid, a friction reducer, and a granular langbainite material may be prepared and introduced into the containment tank at any stage of the fracturing operations. Alternatively, the treatment fluid composition may contain approximately 1000 gallons of base fracturing fluid and 1 gallon of friction reducer and 100 pounds of langbainite material per 1000 gallons of base fracturing fluid. In yet another embodiment, the treatment fluid composition may contain 100 pounds of langbainite particulate material per 100 gallons, where the langbainite particulate material contains 20 pounds of 6/8 US sieve mesh and 80 pounds of 16 to 400 US sieve mesh. Alternatively, the treatment fluid composition may contain 100 pounds of langbainite particulate material per 100 gallons, with the langbainite particulate material containing approximately 5-45 pounds of 6/8 mesh U.S. mesh according to the US Sieve Scale.

Another embodiment of the present composition may be a treatment fluid for diverting fluids in an acid treatment in a naturally fractured formation. In some embodiments, continuous acid removal is necessary to obtain a better coating over the production interval. Accordingly, the treatment fluid may contain an acid carrier fluid, a corrosion inhibitor, a surfactant, and a particulate langbainite material. The granular langbainite material blocks fractures by allowing the remaining treating acid to contact more surface area of the wellbore. Alternatively, the treatment fluid may contain approximately 1,000 gallons of 15% acid carrier fluid, 0.5% by weight corrosion inhibitor based on acid carrier fluid, 1 gallon of surfactant, and approximately 20-500 pounds of langbainite material per 1,000 gallons of carrier acid liquid. In yet another embodiment, the treatment fluid may contain approximately 1000 gallons of 15% acid carrier fluid, 0.5% by weight corrosion inhibitor based on the acid fluid, 1 gallon of surfactant, and approximately 150 pounds of langbainite material per 1000 gallons of acid fluid. .

Another embodiment of the present composition may be a treatment fluid for cleaning asphaltene buildup in a medium permeability (~10 mD) formation. To remove the asphaltene, a treatment fluid composition containing a xylene carrier fluid and a granular langbainite material can be prepared and introduced into the tank. Alternatively, the treatment fluid may contain 1000 gallons of xylene carrier fluid and approximately 10-500 pounds of 5-25 micron langbeinite or approximately 150 pounds of 5-25 micron langbeinite.

The following examples are provided to demonstrate the ability of the langbainite material to be used as a physical barrier in wells at low temperatures and in acidic conditions. In these examples, granular langbeinite (K ₂ Mg ₂ (SO ₄ ) ₃ ) is chosen as the granular langbeinite material.

Example 1

The decomposition of langbeinite in a pH neutral solution was measured as a function of time. In this example, a series of langbeinite/water solutions were heated at predetermined temperatures and undecomposed langbeinite was weighed at various time intervals to determine the rate of decomposition.

Each solution contained 1 gram of granular langbeinite placed in an 8 oz container with 100 ml of water. The langbeinite particle size was 12/14 US Sieve Scale. The containers were hermetically sealed and placed in a temperature controlled oven. The oven has been heated to 72°F (~22°C), 100°F (~38°C), 120°F (~49°C), 130°F (~54°C) and 140°F (~60° C). At a predetermined time, the closed containers were removed from the furnace, the remains of granular langbeinite from the containers were filtered, dried and weighed to determine the change in weight over time. The results are shown in FIG. 4.

The rate of decomposition of langbeinite was dependent on temperature, with the highest oven temperatures corresponding to the highest rate of decomposition. However, even at a temperature of 140°F (~60°C) complete decomposition of langbeinite occurred only after approximately 3 hours. At 72°F (~22°C) decomposition time increased to approximately more than 10 hours.

A curve was drawn from the results to enable prediction. It has been found that Equation 1 describes all five curves and can be used to predict the degree of decomposition at a given temperature in °F (T) and time in hours (t).

EQUATION 1:

Based on these results, the operator can control the blocking of porous areas of the reservoir using granular langbeinite material at a given time at known temperatures.

Example 2

The decomposition of langbeinite in the acid solution was measured as a function of time and compared with a pH-neutral solution of water and langbeinite. In this example, a series of solutions of granular langbeinite in water or 15% HCl were heated at given temperatures and the langbeinite was weighed at various time intervals to determine the rate of decomposition.

For each acid solution, 1 gram of langbeinite was placed in an 8 oz container with a 15% HCl solution (85 ml water and 15 ml HCl). As in the example above, the pH neutral solution contained 1 gram of granular langbeinite placed in an 8 oz container with 100 ml of water. The langbeinite particle size was 12/14 US Sieve Scale. The containers were sealed and placed in a temperature controlled oven at 100°F (~38°C). At various points in time, closed containers were removed from the oven, solid residues from the containers were filtered, dried and weighed to determine the change in weight over time. The results are shown in FIG. 5.

The decomposition rate of langbeinite was higher in acid. In a pH-neutral solution, complete decomposition of langbeinite occurred after about 6.5 hours; however, in a 15% HCl solution, langbeinite did not decompose completely (after about 3 hours, approximately 3% of the mass remained). Thus, FIG. 5 shows that langbeinite has some life time limit in 15% HCl solution and can be used with diverting acid. This figure also shows that the rate of decomposition in 15% HCl solution is higher. Thus, acidic liquids can be introduced into the tank to increase the rate of decomposition of the langbeinite and remove it more quickly. Such rapid decomposition may be required for processes using flow induction without the use of acid treatment.

The results of Example 2 show that at 100°F (~38°C) or below, the life cycle of langbeinite is long enough that it can be placed in HCl and have enough time to pump it into the well (approximately 15-30 minutes, depending on pipe size). Thus, the operator can control the blocking of the porous areas of the reservoir using granular langbeinite for a given time during the acid stimulation of the reservoirs.

Example 3

The decomposition of langbeinite in solutions with different percentages of salt was measured as a function of time and compared with pH-neutral fresh water and langbeinite control solutions. For this example, a series of solutions of granular langbeinite in fresh water without NaCl added, in salt water with 5% NaCl (5 g NaCl in approximately 100 ml of water), in salt water with 10% NaCl (10 g NaCl in approximately 100 ml of water) ) and in sea water was heated at given temperatures, and langbeinite was weighed at different time intervals to determine the rate of decomposition.

For each solution of salt water and sea water, 1 gram of langbeinite was placed in an 8 ounce container with 100 ml of salt water or sea water. As in the example above, the pH-neutral control solution contained 1 gram of granular langbeinite placed in an 8 oz container with 100 ml of water. The langbeinite particle size was 12/14 US Sieve Scale. The containers were hermetically sealed and placed in a temperature controlled oven. The oven was heated to 100°F (~38°C). At a predetermined time, the closed containers were removed from the furnace, the remains of granular langbeinite from the containers were filtered, dried and weighed to determine the change in weight over time. The results are shown in FIG. 6.

The degree of decomposition in salt water with 10% NaCl was the lowest of all salt solutions during the testing period. The rate of decomposition was higher in salt water with 5% NaCl, and to a lesser extent, the increase in the rate of decomposition was observed in sea water. After 6 hours, langbeinite in salt water with 5% NaCl decomposed almost completely (about 5% remained), and in salt water with 10% NaCl, approximately 40% of langbeinite remained. Accordingly, the langbeinite residue in sea water was approximately 22%. After 11 hours, the degree of decomposition of langbeinite in both salt water with 10% NaCl and sea water was the same, with a residual langbeinite of approximately 3.5%. In salt water with 5% NaCl, no langbeinite residue was observed after 11 hours. Thus, FIG. 6 shows that the percentage of salt can be selected to control the blockage of porous areas of the tank using granular langbainite material in shorter (<6 hours) periods of time.

The above examples show that langbeinite is able to slowly dissolve at temperatures below 140°F in 3-10 hours. This dissolution rate can be maintained using water or saline solutions, including salt water and sea water. Alternatively, acidic solutions may be used to increase the rate of decomposition to create a controlled temporary physical barrier. Thus, the present composition is able to block the openings temporarily without the risk of permanent blockage often occurring in tanks at low temperatures. This allows the compositions to be used for a number of well operations, including fluid loss control, fluid diverting, and shut-off operations.

Claims (30)

1. A treatment fluid for treating a subterranean formation, characterized in that said treatment fluid contains: a) carrier fluid and b) granular langbeinite material. 2. Treatment fluid according to claim 1, characterized in that the granular langbeinite material is selected from the group containing K₂mg₂(SO₄)₃, K₂Ca₂(SO₄)₃, K₂Mn₂(SO₄)₃, (NH₄)₂mg₂(SO₄)₃, K₂Mn₂(BeF₄)₃, K₂mg₂(BeF₄)₃, K₂Zn₂(BeF₄)₃, (NH₄)₂mg₂(BeF₄)₃, (NH₄)₂Mn₂(BeF₄)₃, Cs₂Ca₂(BeF₄)₃, Cs₂Mn₂(BeF₄)₃, (NH₄)₂Mn₂(SeO₄)₃ and Cs₂Mn₂(CrO₄)₃. 3. A treatment fluid according to claim 1, wherein said treatment fluid has a pH of seven or less. 4. The treatment fluid of claim 1 further comprising at least one additive selected from the group consisting of salts, thickeners, pH control additives, surfactants, thinners, biocides, crosslinkers, additional fluid loss control agents, stabilizers, chelating agents, scale inhibitors, gases, mutual solvents, particulate matter, corrosion inhibitors, oxidizers, reducing agents, friction reducers, and any combination thereof. 5. The treatment fluid of claim 1 further comprising an acid, a starch, a surfactant, a guar polymer, a crosslinker, a friction reducer, a corrosion inhibitor, xylene, or any combination thereof. 6. The treatment fluid of claim 1 wherein said granular langbeinite material has a particle size of about 4 mesh to about 150 mesh according to the US Sieve Scale. 7. The treatment fluid of claim 1, wherein said particulate langbainite material is present in a volume of from about 50 pounds per thousand gallon ftg (pptg) of carrier fluid to about 400 ftg of carrier fluid. 8. A method for closing a hole in an underground formation, comprising the following steps: c) introducing a treatment fluid containing a carrier fluid and a granular langbeinite material into the subterranean formation; d) blocking at least one hole in said subterranean formation with a granular langbeinite material; e) allow the granular langbeinite material to decompose; and f) passing liquid through said at least one opening. 9. The method of claim 8, wherein said particulate langbeinite material is selectively degraded by introducing an acid treatment fluid into the subterranean formation. 10. The method of claim 8, wherein said opening is an annular space, a tubing string, a pipe, screens, slots, ports, a void in a sand plug or proppant pack, perforations, washouts, a hole, a hole in a downhole tool, a fracture in a pipe string or pipe, a natural fracture, a fracture, a channel, a pore channel, a man-made fracture, and/or a formation surface. 11. The method of claim 8, wherein said decomposition takes about 3 to about 14 hours. 12. The method of claim. 8, and the temperature at the bottom of the wellbore is from 75°F (~23°C) to 140°F (~60°C). 13. The method of claim 8, wherein said granular langbainite material has a particle size of about 4 mesh to about 150 mesh US Sieve Scale, or about 5 to about 50 microns. 14. The method according to claim 8, further comprising the step of introducing a hydrochloric acid solution and impregnating the granular langbeinite material with said hydrochloric acid solution until the granular langbeinite material is completely decomposed. 15. The method of claim 8, wherein said particulate langbainite material is present in a volume of from about 50 pounds per thousand gallons (ftg) of carrier fluid to about 400 ftg of carrier fluid. 16. The method of claim 8, further comprising at least one additive selected from the group consisting of salts, thickeners, pH control additives, surfactants, thinners, biocides, crosslinkers, additional fluid loss control agents, stabilizers, chelators. agents, scale inhibitors, gases, mutual solvents, particulate matter, corrosion inhibitors, oxidizing agents, reducing agents, friction reducers, and any combination thereof. 17. The method of claim 8, further comprising the step of alternating the injection of the acidic treatment fluid with the injection of said treatment fluid. 18. The method of claim 8, wherein the orifice is a porous portion of said subterranean formation, wherein the treatment fluid is injected at fracturing pressure to fracture the subterranean formation, and the particulate langbeinite material blocks the porous portion to stop fluid loss in the porous portion. 19. A method for temporarily overlapping a channel, comprising the following steps: g) inserting a plug formed from the composition containing the granular langbeinite material into the subterranean formation; h) blocking a flow in said subterranean formation with a plug; i) allow the granular langbainite material in the plug composition to decompose; and j) passing the fluid or downhole tool through the flow. 20. The method of claim 19, further comprising the step of introducing an acidic liquid to selectively decompose the granular langbeinite material.

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